1
As filed with the United States Securities and Exchange
Commission on March 2, 2000.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended DECEMBER 31, 1999
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____ to _____
C O L U M B I A E N E R G Y G R O U P
(Exact name of registrant as specified in its charter)
Delaware 13-1594808
(State or other Jurisdiction of incorporation (I.R.S. Employer
or organization) (Identification No.)
13880 Dulles Corner Lane, Herndon, VA 20171
(Address of Principal Executive Office) (Zip Code)
Registrant's telephone number, including area code (703) 561-6000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
Common Stock, $0.01 Par Value . . . . . . . . . . . New York Stock Exchange
Debentures
6.39% Series A due November 28, 2000
6.61% Series B due November 28, 2002
6.80% Series C due November 28, 2005
7.05% Series D due November 28, 2007
7.32% Series E due November 28, 2010
7.42% Series F due November 28, 2015
7.62% Series G due November 28, 2025
Securities registered pursuant to Section 12(g) of the Act: None
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 proceeding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days: Yes [ X ] or No [ ]
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. [ ]
The aggregate market value of the outstanding common shares of the Registrant
held by nonaffiliates as of January 31, 2000, was $5,231,062,000. For purposes
of the foregoing calculation, all directors and/or officers have been deemed to
be affiliates, but the registrant disclaims that any of such directors and/or
officers is an affiliate.
The number of shares outstanding of each class of common stock as of January 31,
2000, was: Common Stock $0.01 Par Value: 81,304,961 shares outstanding.
Documents Incorporated by Reference
Part III of this report incorporates by reference specific portions of the
Registrant's Proxy Statement relating to the 2000 Annual Meeting of
Stockholders.
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CONTENTS
Page
Part I No.
Item 1. Business................................................................... 3
Item 2. Properties................................................................. 7
Item 3. Legal Proceedings.......................................................... 9
Item 4. Submission of Matters to a Vote of Security Holders........................ 11
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.. 11
Item 6. Selected Financial Data.................................................... 12
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 14
Item 8. Financial Statements and Supplementary Data................................ 39
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 72
Part III
Item 10. Directors and Executive Officers of the Registrant......................... 72
Item 11. Executive Compensation..................................................... 72
Item 12. Security Ownership of Certain Beneficial Owners and Management............. 72
Item 13. Certain Relationships and Related Transactions............................. 72
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............ 73
Undertaking made in Connection with 1933 Act Compliance on Form S-8................. 73
Signatures.......................................................................... 74
Exhibits............................................................................ 75
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PART I
ITEM 1. BUSINESS
General
Columbia Energy Group (Columbia), formerly The Columbia Gas System, Inc., and
its subsidiaries comprise one of the nation's largest integrated natural gas
systems engaged in natural gas transmission, natural gas distribution, and
exploration for and production of natural gas and oil. Columbia is also engaged
in related energy businesses including the distribution of propane and petroleum
products, marketing of natural gas and electricity and the generation of
electricity, primarily fueled by natural gas. Columbia, organized under the laws
of the State of Delaware on September 30, 1926, is a registered holding company
under the Public Utility Holding Company Act of 1935, as amended, (1935 Act) and
derives substantially all its revenues and earnings from the operating results
of its 19 direct subsidiaries. Columbia owns all of the securities of these
direct subsidiaries except for approximately 8% of the stock in Columbia LNG
Corporation. Columbia and its subsidiaries are sometimes collectively referred
to herein as the Columbia Group.
On February 28, 2000, Columbia announced that it had entered into an Agreement
and Plan of Merger, dated as of February 27, 2000 (Merger Agreement), between
Columbia and NiSource, Inc., an Indiana corporation (NiSource). The Board of
Directors of Columbia determined to enter into the Merger Agreement after a
comprehensive evaluation of strategic alternatives that might generate value
greater than that which Columbia's business plan could create.
The terms of the Merger Agreement provide that NiSource will organize a new
company which shall serve as the holding company for both Columbia and NiSource
after the completion of the transaction. Pursuant to the terms of the Merger
Agreement, each of Columbia and NiSource will be merged into newly formed
special purpose subsidiaries of the new holding company, and each will become a
wholly owned subsidiary of the new holding company.
Subject to the terms and conditions of the Merger Agreement, upon completion of
the transaction, Columbia's shareholders will receive, for each share of
Columbia common stock, $70 in cash and a $2.60 face value SAILS(sm) (a unit
consisting of a zero coupon debt security with a forward equity contract).
Columbia's shareholders also have the option to elect to receive (in lieu of
cash and SAILS(sm)) shares in the new holding company in a tax-free exchange,
for up to 30% of the outstanding shares of Columbia common stock. Pursuant to
the stock election option, each Columbia share will be exchanged for up to $74
in new holding company stock, subject to a collar such that, if the average
closing price of NiSource shares during the 30 days prior to the closing of the
transaction is greater than $16.50, Columbia shareholders will receive shares of
the new holding company valued at $74 for each share of Columbia stock, and if
the average closing price of NiSource shares during the 30 days prior to closing
of the transaction is $16.50 or below, Columbia shareholders will receive 4.4848
shares of new holding company stock for each Columbia share. Upon completion of
the transaction, NiSource shareholders will receive one share of holding company
stock for each share of NiSource common stock that they own.
The Merger is conditioned upon, among other things, the approvals of the
shareholders of both companies and various regulatory commissions. However, if
the NiSource shareholder approval is not obtained, the transaction will
automatically be restructured so that, instead of each of NiSource and Columbia
becoming wholly-owned subsidiaries of the new holding company, Columbia will
become a wholly owned subsidiary of NiSource, and Columbia shareholders will
receive $70 in cash and a $3.02 face value SAILS(sm) unit of NiSource with no
option for Columbia shareholders to elect new holding company stock.
Presentation of Segment Information
Columbia revised its presentation of primary business segment information
beginning with the reporting of third quarter 1999 results. The results for
Columbia Propane have been moved from the propane, power generation and
liquefied natural gas (LNG) operations to energy marketing operations that also
includes Columbia Energy Services Corporation's (Columbia Energy Services)
retail operations. Prior periods have been restated to reflect this change.
Transmission and Storage Operations
Columbia's two interstate pipeline subsidiaries, Columbia Gas Transmission
Corporation (Columbia Transmission) and Columbia Gulf Transmission Company
(Columbia Gulf), own a pipeline network of approximately 16,250 miles extending
from offshore in the Gulf of Mexico to Lake Erie, New York and the eastern
seaboard. In addition, Columbia Transmission operates one of the nation's
largest underground natural gas storage systems. Together, Columbia Transmission
and Columbia Gulf serve customers in 15 northeastern, mid-Atlantic, midwestern,
and southern states and the District of Columbia. Columbia Gulf's pipeline
system extends from offshore Louisiana to West Virginia and transports a major
portion of the gas delivered by Columbia Transmission. It also transports gas
for third parties within the production areas of the Gulf Coast. Columbia
Pipeline Corporation and its wholly-owned subsidiary, Columbia Deep Water
Services Company, were formed to operate pipeline and gathering facilities that
are not regulated by the Federal Energy Regulatory Commission (FERC).
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ITEM 1. BUSINESS (continued)
Columbia Transmission and Columbia Gulf provide an array of competitively priced
natural gas transportation and storage services for local distribution companies
and industrial and commercial customers who contract directly with producers or
marketers for their gas supplies.
In 1999, Columbia Transmission completed construction of the largest ever
expansion of its storage and transportation system. The expansion adds
approximately 500,000 Mcf (thousand cubic feet) per day of firm storage to 23
customers. Columbia Transmission is also participating in the proposed 442-mile
Millennium Pipeline Project that has been submitted to the FERC for approval. As
proposed, the project will transport approximately 700,000 Mcf of natural gas
per day from the Lake Erie region to eastern markets. For additional information
regarding the transmission and storage operation's expansion projects see Item
7, page 21.
Distribution Operations
Columbia's five distribution subsidiaries provide natural gas service to nearly
2.1 million residential, commercial and industrial customers in Ohio,
Pennsylvania, Virginia, Kentucky and Maryland. Approximately 32,400 miles of
distribution pipelines serve these major markets. The distribution subsidiaries
have initiated transportation programs that allow residential and small
commercial customers the opportunity to choose their natural gas suppliers and
to use the distribution subsidiaries for transportation service. This ability to
choose a supplier was previously limited to larger commercial and industrial
customers. See Item 7, page 26 and "Competition" on page 5 for additional
information.
Exploration and Production Operations
Columbia's exploration and production subsidiary, Columbia Energy Resources,
Inc. (Columbia Resources), explores for, develops, gathers and produces natural
gas and oil in Appalachia and Canada. As of December 31, 1999, Columbia
Resources held interests in approximately 3.9 million net acres of gas and oil
leases and had proved reserves of 965.8 billion cubic feet of natural gas
equivalent. Columbia Resources owns and operates 8,188 wells and 6,069 miles of
gathering facilities and has expanded its reserve base and production through an
aggressive drilling and acquisition program. During 1999, Columbia Resources
purchased 800 wells, gathering assets and approximately 800,000 undeveloped
acres in the U.S. and Canada. In August 1997, Columbia Resources acquired
Alamco, Inc. (Alamco), an Appalachian gas and oil exploration and development
company. Through Columbia Resources' operations in north-central West Virginia,
southern Kentucky, northern Tennessee and New York, it is one of the
largest-volume independent natural gas and oil producers in the Appalachian
Basin. For additional information, see Item 7, page 31.
Energy Marketing Operations
The energy marketing segment includes Columbia Energy Services that consists of
a retail mass marketing business, an internet based service and a wholly-owned
subsidiary that provides energy related services and products. Also included in
the energy marketing segment are the operations of Columbia Propane Corporation
(Columbia Propane).
As a result of an ongoing strategic assessment in 1999, Columbia Energy Services
decided to focus its efforts on the Mass Markets business, which provides energy
products to smaller volume retail customers, and to exit the Wholesale and
Trading and Major Accounts businesses. The Wholesale and Trading business was
sold at the end of 1999 and the Major Accounts business is being offered for
sale. These businesses are recorded as discontinued operations, in accordance
with generally accepted accounting principles.
Columbia Propane sells propane at wholesale and retail and has been aggressively
expanding its operations through acquisitions and internal growth. See Item 7,
page 33 for additional information regarding recent acquisitions. At the end of
1999, Columbia Propane served more than 350,600 customers in 31 states and the
District of Columbia, which is more than triple the number of customers served
at the end of 1998. Columbia Petroleum Corporation, a subsidiary of Columbia
Propane, owns and operates petroleum assets and had sales of 202.4 million
gallons in 1999 with approximately 42,600 customers in five states.
Power Generation, LNG and Other Operations
Columbia Electric Corporation (Columbia Electric) is an unregulated electric
generation company whose primary focus is the development, ownership and
operation of clean, natural gas fueled power projects. Columbia currently has
three operating facilities totaling 248 megawatts, one 550-megawatt (equivalent)
plant under construction in Gregory, Texas and approximately 3,000 megawatts of
gas-fired generation under development. Publicly announced projects in Columbia
Electric's development portfolio include the Kelson Ridge Project in Charles
County, Maryland, the Liberty Electric Project in Eddystone, Pennsylvania, the
Grassy Point Energy Project in Haverstraw, New York, the Ceredo Electric
Generating Station in Ceredo, West Virginia and the Henderson Generating Station
in Henderson, Kentucky.
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ITEM 1. BUSINESS (continued)
The Gregory Project, a partnership between subsidiaries of Columbia Electric and
LG&E Power, Inc., is anticipated to start operations in the summer of 2000.
Construction of the Liberty Electric Project is anticipated to commence in
spring 2000. Ownership of the Liberty Electric Project was jointly held by
Columbia Electric and subsidiaries of Westcoast Energy, Inc. (Westcoast). In
December 1999, the ownership agreement between Columbia and Westcoast was
terminated due to allocation of capital to other projects by Westcoast in
geographic areas more closely aligned with other Westcoast operating assets and
the desire of Westcoast to focus its resources in ventures that will generate
near-term operating income. Columbia Electric announced on February 16, 2000,
that it purchased Westcoast's 50% interest and now owns 100% of the Liberty
Electric Project.
In December 1999, a limited partnership company established between Columbia
Electric and Atlantic Generation, Inc. completed a transaction terminating a
long-term power purchase contract. Columbia Electric's portion was approximately
$71 million pre-tax under the terms of the buyout. The partners will continue to
operate the facility as a merchant power plant.
Columbia LNG Corporation and an affiliate company own an LNG facility, located
in Cove Point, Maryland, which is one of the largest natural gas peaking and
storage facilities in the United States. The facility has the capacity to
liquify natural gas at a rate of 15,000 Mcf of natural gas per day. The facility
enables LNG to be stored until needed for the winter peak-day requirements of
utilities and other large gas users.
Columbia Network Services Corporation (Columbia Network), a wholly-owned
subsidiary of Columbia, and its subsidiaries provide telecommunications and
information services and assist personal communications service providers and
other microwave radio service licensees in locating and constructing antenna
facilities.
In 1999, Columbia Transmission Communications Corporation (Transcom), a
wholly-owned subsidiary of Columbia, began the construction of its
telecommunications network along the Washington, D.C. to New York City corridor.
Transcom will build and maintain a fiber optics network for voice and data
communications on rights-of-way of Columbia's pipeline companies. Transcom
expects to complete the D.C. to New York fiber optics link in the first half of
2000. The route covers 260 miles and provides access to 16 million people in the
busiest telecommunications corridor in the United States. The company is
developing plans to extend the fiber optics network beyond the initial route.
For additional discussion of Columbia's business segments, including financial
information for the last three fiscal years, see Item 7, pages 21 through 37 and
Note 17 on pages 65 and 66 of Item 8.
Competition
Open access to natural gas supplies over interstate pipelines and the
deregulation of the commodity price of gas has led to tremendous change in the
energy markets, which continue to evolve. During the past couple of years, local
distribution company (LDC) customers and marketers began to purchase gas
directly from producers and marketers and an open competitive market for gas
supplies has emerged. This separation or "unbundling" of the transportation and
other services offered by pipelines and LDCs allows customers to select the
service they want independent from the purchase of the commodity. Columbia's
distribution subsidiaries are involved in programs that provide residential
customers the opportunity to purchase their natural gas requirements from third
parties and use the distribution subsidiaries for transportation services. It is
likely that, over time, distribution companies will have a very limited merchant
function. At the same time that the natural gas markets are evolving, the
markets for competing energy sources are also changing. In 1997, open access to
interstate transmission of electricity was approved by the FERC and was
subsequently approved by several state regulatory commissions, which approvals
provide for increased competition in the electricity market. Columbia's other
operations also experience competition for energy sales and related services
from third party providers. Columbia meets these challenges through innovative
programs aimed at providing energy products and services at competitive prices
while also providing new services that are responsive to the evolving energy
market and customer requirements. For additional information regarding
competition, see Item 7.
Credit Ratings and Credit Facilities
Columbia has an investment grade credit rating which, when coupled with its
$1.35 billion revolving credit facilities, adds to Columbia's financial
flexibility to take advantage of business opportunities as they arise. The
credit facilities consist of a $450 million 364-day revolving credit facility,
with a one-year term loan option, that expires in March 2000 and a $900 million
five-year revolving credit facility that expires in March 2003 and provides for
the issuance of up to $300 million of letters of credit. Columbia is currently
negotiating the replacement of the 364-day facility
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ITEM 1. BUSINESS (continued)
with a bank facility substantially similar in terms. There were no borrowings
under the credit facilities as of December 31, 1999. Columbia's long-term debt
is rated A3, A and BBB+ by Moody's Investors Service, Inc. (Moody's), Fitch
Investors Service (Fitch) and Standard & Poor's Rating Group (S&P),
respectively. Columbia's long-term debt ratings are currently under review for a
possible change by Moody's and S&P. Columbia's commercial paper is rated F-1 by
Fitch, P-2 by Moody's and A-2 by S&P.
The foregoing discussion and Item 3 contain "forward-looking statements," within
the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. Investors and
prospective investors should understand that many factors govern whether any
forward-looking statement contained herein will be or can be achieved. Any one
of those factors could cause actual results to differ materially from those
projected. These forward-looking statements include, but are not limited to,
statements concerning Columbia's plans, proposed acquisitions and dispositions,
objectives, expected performance, expenditures and recovery of expenditures
through rates, stated on either a consolidated or segment basis, and any and all
underlying assumptions and other statements that are other than statements of
historical fact. From time to time, Columbia may publish or otherwise make
available forward-looking statements of this nature. All such subsequent
forward-looking statements, whether written or oral and whether made by or on
behalf of Columbia, are also expressly qualified by these cautionary statements.
All forward-looking statements are based on assumptions that management believes
to be reasonable; however, there can be no assurance that actual results will
not differ materially. Realization of Columbia's objectives and expected
performance is subject to a wide range of risks and can be adversely affected
by, among other things, increased competition in deregulated energy markets,
weather, fluctuations in supply and demand for energy commodities, successful
consummation of proposed acquisitions and dispositions, growth opportunities for
Columbia's regulated and nonregulated businesses, dealings with third parties
over whom Columbia has no control, actual operating experience of acquired
assets, Columbia's ability to integrate acquired operations into its operations,
the regulatory process, regulatory and legislative changes as well as changes in
general economic, capital and commodity market conditions, counter-party credit
risk, many of which are beyond the control of Columbia. In addition, the
relative contributions to profitability by each segment, and the assumptions
underlying the forward-looking statements relating thereto, may change over
time.
With respect to any references made to ratings assigned to Columbia's debt
securities, there can be no assurance that Columbia will be successful in
maintaining its credit quality, or that such credit ratings will continue for
any given period of time, or that they will not be revised downward or withdrawn
entirely by the rating agencies. Credit ratings reflect only the views of the
rating agencies, whose methodology and the significance of their ratings may be
obtained from them.
Other Relevant Business Information
Columbia Group's customer base is broadly diversified, with no single customer
accounting for a significant portion of revenues.
As of January 31, 2000, the Columbia Group had 9,683 full-time employees of
which 1,797 are subject to collective bargaining agreements.
Columbia's subsidiaries are subject to extensive federal, state and local laws
and regulations relating to environmental matters. These laws and regulations,
which are constantly changing, require expenditures for corrective action at
various operating facilities, waste disposal sites and former gas manufacturing
sites for conditions resulting from past practices that have subsequently become
subject to environmental regulation. Information relating to environmental
matters is detailed in Item 7, pages 23, 28 and 34, and in Item 8, Note 14 on
page 63.
On February 22, the board of directors of Columbia amended Columbia's bylaws to
provide that the annual meeting of Columbia will be held on the third Wednesday
in May of each year, at nine o'clock in the morning. If that day is a legal
holiday, the annual meeting will be held on the following day. The board of
directors may change such date and time in its discretion. The board of
directors further amended the bylaws to require stockholders to provide
Columbia with advance notice of stockholder proposals and stockholder
nominations to the board of directors. As amended, the bylaws provide that
stockholders must notify Columbia not less than 60 days and not more than 90
days before the date of the meeting of any stockholder proposal or stockholder
nomination to the board of directors. If, however, the date of the meeting is
first publicly announced or disclosed less than 70 days prior to the meeting,
then stockholders must provide Columbia with such notice within 10 days after
announcement or disclosure. With respect to stockholder proposals, the notice
must include the text of the proposal, a brief written statement of the reasons
why the stockholder favors the proposal, and other information as set forth in
the bylaws. In the case of nominations to the board of directors, the bylaws
provide that the notice must contain the name of the nominated person and other
information as set forth in the bylaws.
For a listing of the direct subsidiaries of Columbia refer to Exhibit 21.
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ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed below and
on page 8 and page 47 of Item 8 under Note 1F. Assets under lien and other
guarantees are described on page 62 in Note 14D of Item 8.
Neither Columbia nor any subsidiary knows of material defects in the title to
any real properties of the subsidiaries of Columbia or any material adverse
claim of any right, title, or interest therein, pending or contemplated.
Substantially all of Columbia Transmission's property has been pledged to
Columbia as security for First Mortgage Bonds issued by Columbia Transmission to
Columbia.
EXPLORATION AND DEVELOPMENT DATA
Acreage - at December 31, 1999
Developed Acreage Undeveloped Acreage
---------------------------------- ---------------------------------------
Gross Net Gross Net
---------- --------- --------- ---------
United States........ 2,177,356 2,050,862 1,362,091 1,061,595
Canada............... 3,524 1,625 1,435,344 774,962
---------- --------- --------- ---------
Total................ 2,180,880 2,052,487 2,797,435 1,836,557
========= ========= ========= =========
Net Wells Completed - 12 Months Ended December 31,
Exploratory Development Total
------------------------- ------------------------- ------------------------
Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- ---
United States........
1999............ 3 1 193 37 196 38
1998............ 5 1 136 32 141 33
1997............ - - 84 18 84 18
Canada...............
1999............ - 1 1 2 1 3
1998............ - 1 - 1 - 2
Productive and Drilling Wells - At December 31, 1999
Production Wells
----------------------------------------
Gross Net Wells Drilling
--------------- ------------- ---------------------------
Gas Oil Gas Oil Gross Net
------ ------ ---- ---- ------ -----
United States........ 8,019(a) 142 7,493 85 40 33
Canada............... 12 15 6 8 6 4
----- ----- ----- ------ ------ -----
Total................ 8,031 157 7,499 93 46 37
===== ===== ===== ====== ====== =====
(a) Includes 616 multiple completion gas wells, all of which are included as
single wells in the table. Also includes 1 gross productive horizontal
well.
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ITEM 2. PROPERTIES (continued)
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1999
Underground Storage Miles of Pipeline
----------------------------------- -------------------------------------------------
Gathering
Subsidiaries State Acreage Wells and Storage Transmission Distribution
- --------------------------------------- --------- ---------- ---------- ----------- ------------ ------------
Columbia Gas of Kentucky, Inc. KY - - - - 2,433
Columbia Gas of Maryland, Inc. MD - - - - 601
Columbia Gas of Ohio, Inc. OH - - - - 18,387
Columbia Gas of Pennsylvania, Inc. PA 3,300 8 4 - 6,961
Columbia Gas of Virginia, Inc. VA - - - - 4,021
Columbia Gas Transmission Corporation DE - - - 3 -
KY - - - 711 -
MD 945 - - 229 -
NJ - - - 69 -
NY 26,228 143 30 338 -
NC - - - 1 -
OH 486,884 2,476 815 4,136 -
PA 63,587 230 76 1,845 -
VA - - - 1,149 -
WV 304,867 811 281 2,405 -
Columbia Gulf Transmission Company KY - - - 716 -
LA - - - 2,035 -
MS - - - 659 -
TN - - - 556 -
TX - - - 183 -
WY - - - 10 -
Columbia Energy Resources, Inc. KY - - 2,289 - -
MI - - 6 - -
NY - - 130 - -
OH - - 123 - -
PA - - 37 - -
TN - - 45 - -
VA - - 429 - -
WV - - 3,010 - -
Columbia Pipeline Company LA - - 3 - -
Columbia LNG Corporation MD - - - 48 -
VA - - - 39 -
---------- ---------- ---------- ---------- ----------
Total 885,811 3,668 7,278 15,132 32,403
========== ========== ========== ========== ==========
Compressor Stations
------------------------------
Installed
Subsidiaries Number Capacity (hp)
- --------------------------------------- ---------- -------------
Columbia Gas of Kentucky, Inc. - -
Columbia Gas of Maryland, Inc. - -
Columbia Gas of Ohio, Inc. - -
Columbia Gas of Pennsylvania, Inc. 1 800
Columbia Gas of Virginia, Inc. - -
Columbia Gas Transmission Corporation - -
6 18,270
1 12,000
- -
3 3,880
1 1,200
25 103,187
23 66,194
10 79,330
39 313,564
Columbia Gulf Transmission Company 2 70,000
6 195,500
3 131,500
2 85,600
- -
- -
Columbia Energy Resources, Inc. 20 6,332
- -
- -
1 10
- -
2 100
- -
15 1,189
Columbia Pipeline Company - -
Columbia LNG Corporation - -
- -
---------- ----------
Total 160 1,088,656
========== ==========
NOTE: This table excludes minor gas properties and all construction work in
progress. The titles to the real properties of the subsidiaries of
Columbia have not been examined for the purpose of this document.
Neither Columbia nor any subsidiary know of material defects in the
title to any of the real properties of the subsidiaries of Columbia or
of any material adverse claim of any right, title, or interest therein,
pending or contemplated. Substantially all of Columbia Transmission's
property has been pledged to Columbia as security for First Mortgage
Bonds issued by Columbia Transmission to Columbia.
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ITEM 3. LEGAL PROCEEDINGS
I. Purchase and Production Matters
A. New Bremen Corp. v. Columbia Gas Transmission Corp. and Columbia Gulf
Transmission Co., No. 88V-631 (Dist. Ct. Austin County, TX); In re The
Columbia Gas System, Inc. and Columbia Gas Transmission Corporation,
No. 91-803 and No. 91-804 (U.S. Bankr. Ct. Dist. of Del.). As reported
in the Quarterly Report on Form 10-Q for the quarter ended March 31,
1999, the Bankruptcy Court approved the settlement of this matter on
April 12, 1999. Payment was made on April 26, 1999. This matter is now
concluded. For further information regarding bankruptcy matters see
Item 7, page 38.
II. Environmental
A. Columbia Gas Transmission Corp. v. Aetna Casualty & Surety Co., et al.,
C.A. No. 94-C-454 (Kanawha (W.Va.) Cir. Ct. March 14, 1994). Columbia
Transmission filed a complaint in West Virginia state court seeking
coverage from various insurers under various insurance policies for
environmental cleanup costs. These costs are discussed more fully in
the Management's Discussion and Analysis of Financial Condition and
Results of Operations section of this Report. All insurers have
responded to the complaint denying such claims. The case is currently
stayed under the evergreen provision of the agreed scheduling order
entered by the state court on November 29, 1995, in order to allow
informal discussions among the parties to the litigation. The parties
have also entered into an agreed order concerning a special discovery
master, which was entered by the court. Columbia Transmission continues
to pursue recovery of environmental expenditures from its insurance
carriers, however, at this time, management is unable to determine the
total amount or final disposition of any recovery.
B. Columbia Gulf Transmission Co. v. Aetna Casualty & Surety Co., et al.,
C.A. No. 95-C-177 (Kanawha (W.Va.) Cir. Ct. January 19, 1995). Columbia
Gulf filed a complaint in West Virginia state court seeking coverage
from various insurers under various insurance policies for
environmental cleanup costs. These costs are discussed more fully in
the Management's Discussion and Analysis of Financial Condition and
Results of Operations section of this Report. All insurers have
responded to the complaint denying such claims. The case is currently
stayed under the evergreen provision of the agreed scheduling order
entered by the state court on December 1, 1995, in order to allow
informal discussions among the parties to the litigation. The parties
have also entered into an agreed order concerning a special discovery
master, which was entered by the court. Columbia Gulf continues to
pursue recovery of environmental expenditures from its insurance
carriers, however, at this time, management is unable to determine the
total amount or final disposition of any recovery.
C. "Emergency Planning and Community Right to Know Act". In January 2000,
the management of Columbia Petroleum discovered that an erroneous
determination of the applicability of certain regulatory requirements
to certain of its petroleum distribution facilities had resulted in a
failure to submit toxic chemical release information required under
Section 313 of the Emergency Planning and Community Right-To-Know Act
of 1986. Management promptly self-reported the circumstance to state
and federal regulatory officials and submitted the required
information. Columbia Petroleum has entered into discussions with
regulatory officials concerning the circumstances, which gave rise to
the failure to report. Because these discussions are in as very
preliminary state, management is unable to estimate the amount of
sanctions, if any, associated with the final resolution of this matter.
III. Other
A. MarkWest Hydrocarbon, Inc., Arbitration Proceeding, AAA Case No. 77 181
0035 98 (filed February 13, 1998); Columbia Gas Transmission Corp. v.
MarkWest Hydrocarbon, Inc., U.S. D.C., S.D. W.Va., Case No. 2:98-03622
(filed April 28, 1998). As reported in the Quarterly Report on Form
10-Q for the quarter ended September 30, 1999, Columbia Transmission
and MarkWest executed, on October 16, 1999, the necessary documents to
implement a full and complete settlement of all issues. As part of the
settlement, MarkWest will expand certain facilities to process
additional gas production in the Appalachian region. This matter is now
concluded.
B. Canada Southern Petroleum Ltd. v. Columbia Gas Development of Canada
Ltd. (C.A. No. 9001-03466, Court of Queen's Bench, Alberta, Canada,
filed March 7, 1990). The plaintiffs assert, among other things, that
the defendant working interest owners, including Columbia Gas
Development of Canada Ltd. (Columbia Canada) and various Amoco
affiliates, breached an alleged fiduciary duty to ensure the earliest
feasible marketing of gas from the Kotaneelee field (Yukon Territory,
Canada). The plaintiffs seek, among other remedies, the return of the
defendants' interests in the Kotaneelee field to the plaintiffs, a
declaration that such interests are held in trust for the plaintiffs
and an order requiring the defendants to promptly market Kotaneelee gas
or assessing damages.
In November 1993, the plaintiffs amended their Amended Statement of
Claim to include allegations that the balance in the Carried Interest
Account (an account for operating costs, which are recoverable, by
working
9
10
ITEM 3. LEGAL PROCEEDINGS (continued)
interest owners) which is in excess of the balance as of November 1988
should be reduced to zero. Columbia, on behalf of Columbia Canada,
consented to the amendment in consideration of the plaintiffs'
acknowledgment that some $63 million was properly charged to the
account. However, Columbia and Columbia Canada continue to dispute the
claim to the extent that the claim challenges expenditures incurred
since November 1988, including expenditures made after Columbia Canada
was sold to Anderson Exploration Ltd. (Anderson) effective December 31,
1991.
A trial commenced in the third quarter of 1996 in the Court of Queen's
Bench. Following multiple lengthy adjournments, plaintiffs concluded
their case-in-chief in the fourth quarter of 1998. Defendants are
currently presenting their witnesses and evidence. The trial is
expected to conclude by the end of 2000. Management continues to
believe that its defenses are meritorious, and that the risk of any
material liability to Columbia is de minimis.
Pursuant to an Indemnification Agreement regarding the Kotaneelee
Litigation entered into when Columbia Canada was sold to Anderson,
Columbia agreed to indemnify and hold Anderson harmless for losses due
to this litigation arising out of actions occurring prior to December
31, 1991. As a result of the 1997 upgrading of Columbia's long-term
debt, an escrow account that provides security for the indemnification
obligation and is now funded by a letter of credit was reduced to
approximately $35,835,000 (Cdn).
C. Cathodic Protection. In September 1995, the management of Commonwealth
Gas Services, Inc. (now Columbia Gas of Virginia, Inc.) (Columbia of
Virginia) advised the Staff of the Virginia State Corporation
Commission (VSCC) that there had been deficiencies in Columbia of
Virginia's cathodically protected pipeline distribution system in its
Northern Operating Area in Virginia. Following several months of
informal investigation, on March 1, 1996, the Commission subpoenaed
Columbia of Virginia to produce documents related to its cathodic
protection program in the Northern Operating Area. Columbia of Virginia
complied with the subpoena. On November 18, 1998, Columbia of Virginia
reported to the VSCC that, with one small exception, it had completed
all remedial work related to the cathodic protection deficiencies. On
April 29, 1999, the Staff of the VSCC issued a Notice of Probable
Violation, indicating it had discovered numerous "probable violations"
of the VSCC's pipeline safety regulations. On May 26, 1999, Columbia of
Virginia submitted a response to the Notice acknowledging that cathodic
protection deficiencies had occurred, identifying the actions taken by
Columbia of Virginia to address such deficiencies, and requesting an
informal conference. Numerous informal conferences have been held with
the Staff. As a result of these conferences, Columbia of Virginia has
agreed to engage an independent consultant to review its cathodic
protection program as part of an overall settlement of the matter.
Discussions between Columbia of Virginia and the Staff concerning the
complete resolution of this matter are continuing. At this time
Columbia is unable to determine the likelihood or magnitude of any
penalties that might be assessed.
D. Columbia Gas Transmission Corp. v. Consolidation Coal Co., et al.,
U.S.D.C. W.D. Pa., C.A. No. 99-2071. On December 21, 1999 Columbia
Transmission filed, but did not serve, a complaint against
Consolidation Coal Co. and McElroy Coal Co. (collectively, Consol),
seeking declaratory and permanent injunctive relief enjoining Consol
from pursuing its current plan to conduct longwall mining through
Columbia Transmission's Victory Storage Field in northern West
Virginia. Consol's current plans to longwall mine through the Victory
Storage Field would destroy certain infrastructure of Victory Storage
Field, including all of Columbia Transmission's storage wells in the
path of the mining. The parties have held discussions concerning
resolution of this matter and, contingent upon the parties reaching an
agreement to hold the litigation in abeyance, further discussions may
occur.
E. NiSource Related Litigation. NiSource has commenced three lawsuits
against Columbia and its directors, two in Delaware Chancery Court and
one in the United States District Court for the District of Delaware.
Several groups of shareholders have instituted similar or identical
actions against Columbia. These shareholder actions have been
consolidated with each other and coordinated with NiSource's actions.
NiSource's federal court complaint was filed on June 24, 1999, and was
amended on July 8, 1999. The federal court complaint, among other
things (i) alleges that certain statements that Columbia has made in
connection with NiSource's offer to purchase Columbia have been false
and misleading in violation of the Securities Exchange Act of 1934, as
amended; (ii) seeks an injunction requiring Columbia to take all
actions necessary to exempt the NiSource tender offer from the
requirements of Section 203 of the Delaware General Corporation Law,
and (iii) seeks injunctive relief prohibiting Columbia from taking any
defensive actions in response to the Offer. Columbia has moved to
dismiss the federal court complaints and the motions are pending.
10
11
ITEM 3. LEGAL PROCEEDINGS (continued)
The first Chancery Court complaint was filed on June 24, 1999, and
alleged that Columbia's certificate of incorporation requires 13
persons to be on the Board of Directors and that, therefore, Columbia's
current 12-person Board of Directors violates the certificate. On
September 22, 1999, the Chancery Court granted Columbia's motion to
dismiss the complaint and declined to grant an order for a special
meeting of the shareholders to elect a thirteenth director.
The second Chancery Court complaint was filed on July 29, 1999, and
alleges that the Board's actions in response to the Offer, including
the announced increase in Columbia's share repurchase program,
represent a breach of the fiduciary duties owed to Columbia
stockholders. The parties began discovery in both the federal and
Chancery Court actions, but on October 25, 1999, the parties agreed to
stay the federal action and second Chancery Court action pending the
outcome of meetings between the two companies.
Following the execution of the Merger Agreement, NiSource and Columbia
have agreed to dismiss the remaining litigation brought by NiSource.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of Columbia is traded on the New York Stock Exchange under the
ticker symbol CG and abbreviated as either ColumEngy or ColumEgy in trading
reports. At December 31, 1999, the number of shareholders of record was
approximately 31,625 and the stock closed at $63 1/4, as reflected in the New
York Stock Exchange Composite Transactions as reported by The Wall Street
Journal. On February 22, 2000, Columbia declared a quarterly dividend of $0.225
per share for the first quarter of 2000, which will be payable on March 15,
2000, to holders of record as of March 3, 2000.
See Item 7 on page 20 for additional information regarding Columbia's common
stock prices and dividends.
11
12
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
Columbia Energy Group and Subsidiaries
($ in millions, except per share amounts) 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total net revenues 1,994.8 1,861.9 1,896.9 1,856.6
Earnings (Loss) before discontinued operations,
extraordinary item and accounting changes 355.0 300.3 280.3 218.2
Earnings (Loss) before extraordinary item
and accounting changes 249.2 269.2 273.3 221.6
Earnings (Loss) on common stock 249.2 269.2 273.3 221.6
- -----------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA**
Earnings (Loss) per share of common stock ($):
Continuing operations 4.31 3.60 3.37 2.71
Discontinued operations (1.28) (0.37) (0.08) 0.04
Before extraordinary item and accounting changes 3.03 3.23 3.29 2.75
Earnings (Loss) per share of common stock 3.03 3.23 3.29 2.75
Average common shares outstanding (000) 82,210 83,382 83,100 80,681
Diluted earnings (loss) per share of common stock ($):
Continuing operations 4.29 3.58 3.35 2.70
Discontinued operations (1.28) (0.37) (0.08) 0.04
Before extraordinary item and accounting changes 3.01 3.21 3.27 2.74
Diluted earnings (loss) per share of common stock 3.01 3.21 3.27 2.74
Diluted average common shares (000) 82,709 83,748 83,594 80,919
Dividends:
Per share ($) 0.875 0.77 0.60 0.40
Payout ratio (%) 28.9 23.8 18.2 14.5
- -----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 2,064.0 2,005.3 1,790.7 1,553.6
Preferred stock -- -- -- --
Long-term debt 1,639.7 2,003.1 2,003.5 2,003.8
Short-term debt 465.5 N/A N/A N/A
Current maturities of long-term debt 311.3 0.4 0.5 0.8
Debt subject to Chapter 11 -- -- -- --
Total 4,480.5 4,008.8 3,794.7 3,558.2
Total assets 7,095.9 6,531.4 6,259.4 5,905.8
- -----------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including current maturities ***):
Common stock equity 46.1 50.0 47.2 43.7
Preferred stock -- -- -- --
Debt 53.9 50.0 52.8 56.3
Capital expenditures ($) 867.3 479.2 563.2 314.0
Net cash from operations ($) 831.6 698.3 504.1 461.0
Book value per share of common stock ($) ** 25.39 24.01 21.51 18.74
Return on average common equity before discontinued
operations, extraordinary item and accounting changes (%) 17.5 15.8 16.8 16.4
- -----------------------------------------------------------------------------------------------------------------------------------
($ in millions, except per share amounts) 1995* 1994*
- ----------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total net revenues 1,807.4 1,756.2
Earnings (Loss) before discontinued operations,
extraordinary item and accounting changes (433.4) 244.7
Earnings (Loss) before extraordinary item
and accounting changes (432.3) 246.2
Earnings (Loss) on common stock (360.7) 240.6
- ----------------------------------------------------------------------------------------------------
PER SHARE DATA**
Earnings (Loss) per share of common stock ($):
Continuing operations (5.72) 3.23
Discontinued operations 0.01 0.02
Before extraordinary item and accounting changes (5.71) 3.25
Earnings (Loss) per share of common stock (4.76) 3.17
Average common shares outstanding (000) 75,708 75,838
Diluted earnings (loss) per share of common stock ($):
Continuing operations (5.72) 3.23
Discontinued operations 0.01 0.02
Before extraordinary item and accounting changes (5.71) 3.25
Diluted earnings (loss) per share of common stock (4.76) 3.17
Diluted average common shares (000) 75,708 75,838
Dividends:
Per share ($) -- --
Payout ratio (%) N/A N/A
- ----------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 1,114.0 1,468.0
Preferred stock 399.9 --
Long-term debt 2,004.5 4.3
Short-term debt N/A --
Current maturities of long-term debt 0.5 1.2
Debt subject to Chapter 11 -- 2,317.1
Total 3,518.9 3,790.6
Total assets 6,033.4 7,152.2
- ----------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including current maturities ***):
Common stock equity 31.7 38.7
Preferred stock 11.4 --
Debt 56.9 61.3
Capital expenditures ($) 420.8 447.1
Net cash from operations ($) (798.0) 574.9
Book value per share of common stock ($) ** 15.09 19.36
Return on average common equity before discontinued
operations, extraordinary item and accounting changes (%) (33.6) 18.2
- ----------------------------------------------------------------------------------------------------
N/A - Not applicable
Dilutive potential common shares were not included in the 1995 computation of
diluted EPS as the effect would be antidilutive.
* Reference is made to Note 14(A) of Notes to Consolidated Financial
Statements. Due to the bankruptcy filings, interest expense of
approximately $230 million, $210 million, $204 million and $86 million
was not recorded in 1994, 1993, 1992 and 1991, respectively. Interest
expense of $982.9 million, including write-off of unamortized discounts
on debentures, was recorded in the fourth quarter of 1995.
** All per share amounts, average common shares outstanding and diluted
average common shares have been restated to reflect a three-for-two
common stock split, in the form of a stock dividend, effective June 15,
1998.
*** Prior to 1991, Columbia made extensive use of variable rate debt since
the associated cost was normally less than senior long-term debt.
Short-term borrowings were used in 1999 to finance acquisitions and to
fund Columbia's stock repurchase program. Inclusion of the short-term
debt in years prior to 1991 and in 1999 makes those historical ratios
more meaningful.
12
13
ITEM 6. SELECTED FINANCIAL DATA (continued)
SELECTED FINANCIAL DATA
Columbia Energy Group and Subsidiaries
($ in millions, except per share amounts) 1993 1992 1991 1990 1989
- -----------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total net revenues 1,734.0 1,622.3 1,407.2 1,499.9 1,520.3
Earnings (Loss) before discontinued operations,
extraordinary item and accounting changes 152.1 90.9 (794.8) 104.7 145.8
Earnings (Loss) before extraordinary item
and accounting changes 152.2 90.9 (794.8) 104.7 145.8
Earnings (Loss) on common stock 152.2 51.2 (694.4) 104.7 145.8
- -----------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA**
Earnings (Loss) per share of common stock ($):
Continuing operations 2.01 1.20 (10.49) 1.48 2.14
Discontinued operations -- -- -- -- --
Before extraordinary item and accounting changes 2.01 1.20 (10.49) 1.48 2.14
Earnings (Loss) per share of common stock 2.01 0.68 (9.16) 1.48 2.14
Average common shares outstanding (000) 75,838 75,838 75,798 70,983 68,260
Diluted earnings (loss) per share of common stock ($):
Continuing operations 2.01 1.20 (10.49) 1.47 2.13
Discontinued operations -- -- -- -- --
Before extraordinary item and accounting changes 2.01 1.20 (10.49) 1.47 2.13
Diluted earnings (loss) per share of common stock 2.01 0.68 (9.16) 1.47 2.13
Diluted average common shares (000) 75,838 75,838 75,798 71,133 68,537
Dividends:
Per share ($) -- -- 0.77 1.47 1.33
Payout ratio (%) N/A N/A N/A 99.3 62.1
- -----------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 1,227.3 1,075.1 1,006.9 1,757.8 1,620.3
Preferred stock -- -- -- -- --
Long-term debt 4.8 5.4 6.1 1,428.7 1,196.0
Short-term debt -- -- N/A 735.5 634.2
Current maturities of long-term debt 1.3 1.4 2.9 35.2 47.2
Debt subject to Chapter 11 2,317.1 2,317.1 2,317.1 -- --
Total 3,550.5 3,399.0 3,333.0 3,957.2 3,497.7
Total assets 6,934.7 6,505.9 6,332.2 6,196.3 5,878.4
- -----------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including current maturities ***):
Common stock equity 34.6 31.6 30.2 44.4 46.3
Preferred stock -- -- -- -- --
Debt 65.4 68.4 69.8 55.6 53.7
Capital expenditures ($) 361.1 299.7 381.9 629.6 473.5
Net cash from operations ($) 839.4 765.4 531.6 420.1 400.5
Book value per share of common stock ($) ** 16.18 14.18 13.28 23.22 23.67
Return on average common equity before discontinued
operations, extraordinary item and accounting changes (%) 13.2 8.7 (57.5) 6.2 9.2
- -----------------------------------------------------------------------------------------------------------------------------
N/A - Not applicable
Dilutive potential common shares were not included in the 1995 computation of
diluted EPS as the effect would be antidilutive.
* Reference is made to Note 14(A) of Notes to Consolidated Financial
Statements. Due to the bankruptcy filings, interest expense of
approximately $230 million, $210 million, $204 million and $86 million
was not recorded in 1994, 1993, 1992 and 1991, respectively. Interest
expense of $982.9 million, including write-off of unamortized discounts
on debentures, was recorded in the fourth quarter of 1995.
** All per share amounts, average common shares outstanding and diluted
average common shares have been restated to reflect a three-for-two
common stock split, in the form of a stock dividend, effective June 15,
1998.
*** Prior to 1991, Columbia made extensive use of variable rate debt since
the associated cost was normally less than senior long-term debt.
Short-term borrowings were used in 1999 to finance acquisitions and to
fund Columbia's stock repurchase program. Inclusion of the short-term
debt in years prior to 1991 and in 1999 makes those historical ratios
more meaningful.
13
14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Index Page
- ----- ----
Consolidated Review............................................................................. 14
Liquidity and Capital Resources................................................................. 17
Transmission and Storage Operations............................................................. 21
Distribution Operations......................................................................... 26
Exploration and Production Operations........................................................... 31
Energy Marketing Operations..................................................................... 33
Power Generation, LNG and Other Operations...................................................... 36
Bankruptcy Matters.............................................................................. 38
The Management's Discussion and Analysis, including statements regarding market
risk sensitive instruments, contains "forward-looking statements," within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. Investors and
prospective investors should understand that many factors govern whether any
forward-looking statement contained herein will be or can be achieved. Any one
of those factors could cause actual results to differ materially from those
projected. These forward-looking statements include, but are not limited to,
statements concerning Columbia's plans, proposed acquisitions and dispositions,
objectives, expected performance, expenditures and recovery of expenditures
through rates, stated on either a consolidated or segment basis, and any and all
underlying assumptions and other statements that are other than statements of
historical fact. From time to time, Columbia may publish or otherwise make
available forward-looking statements of this nature. All such subsequent
forward-looking statements, whether written or oral and whether made by or on
behalf of Columbia, are also expressly qualified by these cautionary statements.
All forward-looking statements are based on assumptions that management believes
to be reasonable; however, there can be no assurance that actual results will
not differ materially. Realization of Columbia's objectives and expected
performance is subject to a wide range of risks and can be adversely affected
by, among other things, increased competition in deregulated energy markets,
weather, fluctuations in supply and demand for energy commodities, successful
consummation of proposed acquisitions and dispositions, growth opportunities for
Columbia's regulated and nonregulated businesses, dealings with third parties
over whom Columbia has no control, actual operating experience of acquired
assets, Columbia's ability to integrate acquired operations into its operations,
the regulatory process, regulatory and legislative changes as well as changes in
general economic, capital and commodity market conditions, counter-party credit
risk, many of which are beyond the control of Columbia. In addition, the
relative contributions to profitability by each segment, and the assumptions
underlying the forward-looking statements relating thereto, may change over
time.
With respect to any references made to ratings assigned to Columbia's debt
securities, there can be no assurance that Columbia will be successful in
maintaining its credit quality, or that such credit ratings will continue for
any given period of time, or that they will not be revised downward or withdrawn
entirely by the rating agencies. Credit ratings reflect only the views of the
rating agencies, whose methodology and the significance of their ratings may be
obtained from them.
CONSOLIDATED REVIEW
Columbia's income from continuing operations for 1999 was $355 million, or $4.29
per share, an increase of $54.7 million, or $0.71 per share, over 1998. All per
share amounts are reported on a diluted basis. Increasing after-tax income
relative to last year was a $49 million after-tax gain recorded in connection
with the termination of a cogeneration power purchase contract, a $20.6 million
after-tax gain related to the final producer contract claim stemming from
Columbia's bankruptcy proceedings concluded in 1995, an after-tax gain of $7.8
million on the sale of Columbia's interests in the Trailblazer pipeline system
and a reduction in tax expense for the realization of state net carryforwards
that increased net income by $6.9 million. Weather was 12% colder than in 1998;
however, weather in 1999 was still 8% warmer than normal. Also improving results
was increased natural gas production for the exploration and production
operations along with lower gross receipts and property taxes for the
distribution segment. Partially offsetting these improvements were higher costs
for energy marketing operations, higher interest expense, and professional fees
primarily related to Columbia's response to an unsolicited tender offer. In
1998, several key items improved results including a $16.5 million improvement
recorded for a settlement gain related to postretirement benefit costs, which
reflected the purchase of insurance for a portion of those liabilities, the
implementation of state tax planning initiatives and the settlement of certain
tax issues.
14
15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Discontinued operations, which include the Wholesale and Trading and Major
Accounts businesses of Columbia Energy Services, Inc. (Columbia Energy
Services), reflected an after-tax loss of $105.8 million or $1.28 per share in
1999, compared to an after-tax loss of $31.1 million, or $0.37 per share in
1998. Taking into account income from continuing operations and the loss from
discontinued operations, Columbia reported net income of $249.2 million, or
$3.01 per share in 1999, versus $269.2 million or $3.21 per share for the prior
year.
Income from continuing operations for 1998 of $300.3 million, or $3.58 per
share, increased $20 million, or $0.23 per share, from 1997, due largely to
lower operation and maintenance costs for Columbia's rate-regulated
subsidiaries, higher revenue from transportation services and gas management
activities and increased gas production and prices from Columbia's exploration
and production segment. These changes were largely offset by the impact of
record warm weather in 1998 and higher costs for Columbia Energy Services
related to its larger infrastructure. Several other items also affected both
years' results. In 1998, the benefit from the reduction in certain
postretirement benefit costs, reflecting the purchase of insurance for a portion
of those liabilities, and a $10 million benefit from state tax planning
initiatives enhanced net income. Also improving 1998 results was a gain of $6.5
million from the settlement of 1991-1994 tax issues. In 1997, net income was
improved $12.8 million as a result of reduced state income taxes, $12.4 million
from a regulatory settlement for Columbia Gas Transmission Corporation (Columbia
Transmission) that included the sale of base gas storage volumes, $6 million
from the sale of coal assets, $5.5 million from a gain on the deactivation of a
storage field and $4.4 million for payments received from a cogeneration
partnership. Reducing net income in 1997 were $20.2 million of restructuring and
relocation costs and a $6.6 million reserve for the sale of certain pipeline
facilities.
The after-tax loss on discontinued operations increased from $7 million, or
$0.08 per share, in 1997 to $31.1 million, or $0.37 per share, in 1998. Income
from continuing operations together with the loss from discontinued operations
resulted in reported net income in 1998 decreasing $4.1 million, or $0.06 per
share, from the $273.3 million, or $3.27 per share, reported for 1997.
Net Revenues
Total net revenues (revenues less associated product purchased costs) of
$1,994.8 million for 1999 reflected an increase of $132.9 million over 1998
primarily due to a gain recorded for the settlement of a cogeneration power
purchase contract, the impact of 1999's colder weather, increased transportation
services and higher production for the exploration and production operations.
Also providing higher net revenues was the effect of recent acquisitions for the
propane and petroleum operations. Reduced prices for natural gas production and
a reduction to revenues resulting from a Columbia of Ohio regulatory settlement
partially offset these improvements.
For 1998, total net revenues of $1,861.9 million reflected a decrease of $35
million from 1997, due primarily to the adverse effect of warmer weather in 1998
on gas sales for the distribution segment. The impact of warmer weather was
partially offset by higher revenues from transportation services and gas
management activities in the transmission and distribution segments. Also
improving revenues in 1998 was a $13.4 million increase resulting from the gain
on the sale of storage base gas volumes and higher revenues from increased gas
production and prices.
Expenses
Total operating expenses for 1999 were $1,346.4 million, an increase of $65.8
million over 1998. Operation and maintenance expense increased $108.3 million,
due to higher expenses for the energy marketing and exploration and production
segments, due in part to recent acquisitions for Columbia Energy Resources
Corporation (Columbia Resources) and Columbia Propane Corporation (Columbia
Propane) and increased costs for Columbia Energy Services, and a $25.4 million
favorable adjustment in 1998 for a settlement gain related to postretirement
benefit costs. Also increasing 1999 operation and maintenance expense were costs
related to Columbia's response to an unsolicited tender offer. Depreciation and
depletion expense declined $2.9 million primarily due to Columbia Gas of Ohio's
1999 regulatory settlement that was partially offset by lower revenues, which
was also related to the settlement, as mentioned above. The settlement of gas
supply litigation in 1999 reduced operating expenses by $31.7 million reflecting
the bankruptcy-related producer settlement mentioned above. In addition, lower
gross receipts and property taxes for the distribution operations also improved
income.
Total operating expenses of $1,280.6 million for 1998 decreased $94.8 million
compared to 1997, reflecting a reduction of $104.8 million in operation and
maintenance expense largely due to cost conservation measures and efficiencies
gained through recently implemented restructuring activities for the
rate-regulated segments. The lower operation and maintenance expense also
reflects a $25.4 million reduction in the cost of certain postretirement
benefits, reflecting the purchase of insurance for a portion of Columbia's
liabilities. The 1997 operating expenses were higher due in part to $24.8
million of restructuring costs. Depreciation and depletion expense increased $12
million in 1998 due primarily to an increase in depletion expense for the
exploration and production segment
15
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
resulting from a higher depletion rate, together with the effect of increased
production from both the acquisition of Alamco, Inc., (Alamco) an Appalachian
exploration and production company in 1997, and the success of Columbia Energy
Resources Inc.'s (Columbia Resources) drilling program.
Other Income (Deductions)
Twelve Months Ended December 31, (in millions) 1999 1998 1997
- --------------------------------------------------------------------------------------------
Interest income and other, net $ 29.2 $ 12.3 $ 39.4
Interest expense and related charges (164.4) (144.5) (157.4)
- --------------------------------------------------------------------------------------------
TOTAL OTHER INCOME (DEDUCTIONS) $(135.2) $(132.2) $(118.0)
- --------------------------------------------------------------------------------------------
Other income (deductions) reduced income by $135.2 million in 1999 compared to a
reduction of $132.2 million in 1998. Interest income and other, net, of $29.2
million was $16.9 million greater than in the year earlier, due largely to gains
in 1999 of $12.1 million for the sale of Columbia's interests in a pipeline
partnership and $2.9 million from the sale of coal properties. Interest expense
and related charges of $164.4 million increased $19.9 million due largely to
higher short-term borrowings to finance recent acquisitions and to fund
Columbia's stock repurchase program, as discussed below.
For 1998, other income (deductions) reduced income by $132.2 million compared to
a reduction of $118 million in 1997. Interest income and other, net of $12.3
million decreased $27.1 million when compared to 1997, due largely to two
transactions recorded in 1997 namely, an $8.5 million gain for a payment
received from the deactivation of a storage field that allowed the owner of the
coal reserves to mine the property and a $9.5 million improvement for the sale
of Columbia's coal assets. In addition, temporary cash investments in 1998 were
lower than the prior year, which led to reduced interest income. Interest
expense and related charges of $144.5 million in 1998 decreased $12.9 million
from 1997, primarily reflecting a reduction in interest expense for a 1998 tax
settlement, involving tax issues from 1991-1994, partially offset by additional
interest expense on prepayments received from third parties for gas to be
delivered in future periods.
Income Taxes
Income tax expense in 1999 totaled $158.2 million, an increase of $9.4 million
over 1998, primarily due to higher pre-tax income in 1999. Income benefited as a
result of utilizing certain tax benefits and state tax planning initiatives
during 1999 and 1998.
Income tax expense of $148.8 million for 1998 increased $25.6 million from the
year earlier, primarily reflecting higher pre-tax income. There were reductions
to income tax expense of approximately $10 million in 1998 and $12.8 million in
1997 due to the implementation of state tax planning initiatives.
Discontinued Operations
Discontinued operations reflected an after-tax loss of $105.8 million, or $1.28
per share, in 1999 compared to an after-tax loss of $31.1 million, or $0.37 per
share, in 1998. The increased loss on discontinued operations reflected higher
operation and maintenance costs that included the write down of certain assets,
establishing reserves for certain issues and lower margins for gas and power
trading.
In August 1999, Columbia Energy Services announced that it had decided to sell
its Wholesale and Trading operations based in Houston, Texas. The decision was
made as part of an ongoing strategic review of Columbia Energy Services' overall
energy marketing businesses initiated in February 1999. In December 1999, its
Wholesale and Trading operations were sold to Enron North America Corp., a
wholly-owned subsidiary of Enron Corp.
Columbia Energy Services subsequently determined that it would exit the Major
Accounts business that provided energy services and products to industrial and
large commercial customers. In accordance with generally accepted accounting
principles, the Wholesale and Trading and Major Accounts businesses are reported
as discontinued operations on Columbia's consolidated financial statements.
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17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
LIQUIDITY AND CAPITAL RESOURCES
A significant portion of Columbia's operations, most notably in the distribution
segment, is subject to seasonal fluctuations in cash flow. During the heating
season, which is primarily from November through March, cash receipts from sales
and transportation services typically exceed cash requirements. Conversely,
during the remainder of the year, cash on hand, together with external
short-term and long-term financing, is used to purchase gas to place in storage
for heating season deliveries, perform necessary maintenance of facilities, make
capital improvements in plant and expand service into new areas.
Net cash from continuing operations in 1999 of $825.8 million reflected a
decrease of $19.9 million from 1998 due primarily to normal working capital
changes.
Net cash from continuing operations for 1998 was $860.5 million, an increase of
$286 million over 1997. The increase primarily reflected higher prepayments
received for natural gas to be delivered over several years partially offset by
a decrease in the overrecovery of gas costs by the distribution segment as well
as the effect of warm weather in 1998. The decrease in the overrecovery position
reflects higher gas prices in 1998 compared to the same period in 1997. The
recovery of gas costs in the distribution segment's rates is provided for under
the current regulatory process.
Columbia satisfies its liquidity requirements primarily through internally
generated funds and from the sale of commercial paper, which is supported by two
unsecured bank revolving credit facilities that total $1.35 billion (Credit
Facilities). The Credit Facilities consist of a $450 million 364-day revolving
credit facility, with a one-year term loan option, that expires in March 2000
and a $900 million five-year revolving credit facility that expires in March
2003 and provides for the issuance of up to $300 million of letters of credit.
Columbia is currently negotiating the replacement of the 364-day bank facility
with a bank facility substantially similar in terms. Columbia also utilizes
other borrowing arrangements from time-to-time. As of year-end 1999, Columbia
had no borrowings under the Credit Facilities. See Note 12 in the Notes to
Consolidated Financial Statements for additional information.
Interest rates on borrowings under the Credit Facilities are based upon the
London Interbank Offered Rate, Certificate of Deposit rates or other short-term
interest rates. In addition, the 364-day facility has a utilization fee if
borrowings exceed a certain level. The interest rate margins and facility fee on
the commitment amounts are based on Columbia's public debt ratings. In 1998,
Moody's Investors Service, Inc. (Moody's) and Fitch Investors Service (Fitch)
upgraded their rating of Columbia's long-term debt to A3 and A, respectively.
Columbia's long-term debt rating is BBB+ by Standard & Poor's Ratings Group
(S&P). Columbia's long-term debt ratings are currently under review for a
possible change by Moody's and S&P. Higher debt ratings result in lower facility
fees and interest rate margins on borrowings. Columbia's commercial paper
ratings are F-1 by Fitch, P-2 by Moody's and A-2 by S&P.
As of year-end 1999, Columbia had approximately $133.7 million of letters of
credit outstanding, of which approximately $54.7 million was issued under the
Credit Facilities. At the end of 1999, Columbia had $340.5 million of commercial
paper outstanding under its $850 million commercial paper program and $125
million of notes payable.
During 1998, Columbia entered into fixed-to-floating interest rate swap
agreements to modify the interest characteristics of $300 million of its
outstanding long-term debt. As a result of these transactions, that portion of
Columbia's long-term debt is now subject to fluctuations in interest rates. This
allows Columbia to benefit from a lower interest rate environment. In order to
maintain a balance between fixed and floating interest rates, Columbia is
targeting average floating rate debt exposure of 10-20% of its outstanding
long-term debt.
Columbia has an effective shelf registration statement on file with the
Securities and Exchange Commission for the issuance of up to $1 billion in
aggregate of debentures, common stock or preferred stock in one or more series.
Currently, Columbia has $750 million available under the shelf registration.
Management believes that its sources of funding are sufficient to meet
short-term and long-term liquidity needs of Columbia.
Common Stock Repurchase Program
At its February 1999 meeting, Columbia's Board of Directors (Board) authorized
the purchase of up to $100 million of Columbia's common stock through February
29, 2000, in the open market or otherwise. In July 1999, Columbia's Board
authorized the purchase of an additional $400 million of common stock through
July 14, 2000. In October 1999, the program was suspended pending consideration
of strategic alternatives. The source of funds for
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18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
repurchases consisted of available funds and/or borrowings. Through this
program, 2,478,500 common shares were repurchased at a cost of approximately
$135 million, before the program was suspended. There can be no assurance as to
when the share repurchase program will recommence or if it will resume. If the
program were to resume, the timing and terms of additional purchases, and the
number of shares actually purchased, will be determined by management based on
several factors including market conditions. Purchased shares are held in
treasury to be made available for general corporate purposes, or resale at a
future date or they may be retired.
Capital Expenditures
The table below reflects actual capital expenditures by segment for 1999 and
1998 and an estimate for year 2000:
(in millions) 2000 1999 1998
- -------------------------------------------------------------------
Transmission and Storage $148.4 $183.4 $210.0
Distribution 135.6 145.5 151.9
Exploration and Production 165.7 166.5 75.7
Energy Marketing 43.3 315.5 27.9
Power Generation, LNG and Other 376.5 51.0 2.7
Corporate 5.2 5.4 11.0
- -------------------------------------------------------------------
TOTAL $874.7 $867.3 $479.2
- -------------------------------------------------------------------
For 1999, capital expenditures were $867.3 million, an increase of $388.1
million from 1998. The 1999 program included approximately $347 million for
acquisitions, of which approximately $301 million was for propane acquisitions
that added nearly 235,000 new customers. The 1999 program also included $86
million for new business initiatives for the transmission and storage segment.
The largest portion of the transmission and storage segment's investments are
made to ensure the safety and reliability of the pipelines and for market
expansion activities. The distribution subsidiaries' program includes
investments to extend service to new areas and develop future markets, as well
as expenditures required to ensure safe, reliable and improved service. The
exploration and production segment's 1999 program included amounts for its
expanded drilling program and acquisitions.
For 2000, Columbia's estimated capital expenditure program of $874.7 million is
$7.4 million higher than the 1999 program. Included in the 2000 program for the
Power Generation, LNG and Other Operations is about $196 million for the
development of Columbia Transmission Communication Corporation's fiber optics
network and approximately $131 million for cogeneration activities. The
transmission and storage segment includes approximately $44 million for new
business activities and another $54 million is planned for new business and
development activities for the distribution segment. The exploration and
production segment's capital program provides for the drilling of approximately
330 new wells.
All discretionary capital expenditures are subject to review under Columbia's
value added approach (CVA) that determines whether the anticipated return on a
business activity or project exceeds its risk adjusted capital cost.
Market Risk Exposure
Subsidiaries in Columbia's exploration and production and energy marketing
segments are exposed to market risk due primarily to fluctuations in commodity
prices. In order to help minimize this risk, Columbia has adopted a policy that
provides for commodity hedging activities to help ensure stable cash flow,
favorable prices and margins. Financial instruments authorized for use by
Columbia for hedging include futures, swaps and options. Due to the sale of
Columbia's Wholesale and Trading business, Columbia's use of derivatives has
been significantly reduced. However, Columbia Energy Services does utilize
financial instruments to help assure adequate margins for its Mass Markets
business on the purchase and resale of energy products. Columbia Resources
utilizes financial instruments to fix prices for a portion of its future
production volumes, which are hedged in the marketplace through a third party.
Columbia Propane utilizes financial instruments to help protect the value of its
propane and petroleum inventories and commitments.
Any positions using derivative instruments continue to be controlled within
predetermined limits as provided by Columbia's senior management. Columbia's
policy prohibits any Columbia subsidiary from entering into derivative
transactions that are not effectively connected with its business. Market risks
are monitored by an independent risk control group operating separately from the
area that creates or actively manages these risk exposures in order to monitor
compliance with Columbia's stated risk management policies.
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19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
Columbia measures the market risk in its energy marketing portfolios and employs
multiple risk control mechanisms to mitigate market risk including value-at-risk
measures using a variance/covariance methodology and volumetric limits.
Value-at-risk simulates forward price curves in the energy markets to estimate
the size and probability of future potential losses. Based on a 95% confidence
interval and a one-day time horizon, the value-at-risk for Columbia's energy
marketing operations was insignificant.
Columbia also utilizes fixed-to-floating interest rate swap agreements to modify
the interest characteristics of a portion of its outstanding long-term debt. As
a result of these transactions, $300 million of Columbia's long-term debt is now
subject to fluctuations in interest rates.
Merger Agreement
On February 28, 2000, Columbia announced that it had entered into an Agreement
and Plan of Merger, dated as of February 27, 2000 (Merger Agreement), between
Columbia and NiSource, Inc., an Indiana corporation (NiSource). The Board of
Directors of Columbia determined to enter into the Merger Agreement after a
comprehensive evaluation of strategic alternatives that might generate value
greater than that which Columbia's business plan could create.
The terms of the Merger Agreement provide that NiSource will organize a new
company which shall serve as the holding company for both Columbia and NiSource
after the completion of the transaction. Pursuant to the terms of the Merger
Agreement, each of Columbia and NiSource will be merged into newly formed
special purpose subsidiaries of the new holding company, and each will become a
wholly owned subsidiary of the new holding company.
Subject to the terms and conditions of the Merger Agreement, upon completion of
the transaction, Columbia's shareholders will receive, for each share of
Columbia common stock, $70 in cash and a $2.60 face value SAILS(sm) (a unit
consisting of a zero coupon debt security with a forward equity contract).
Columbia's shareholders also have the option to elect to receive (in lieu of
cash and SAILS(sm)) shares in the new holding company in a tax-free exchange,
for up to 30% of the outstanding shares of Columbia common stock. Pursuant to
the stock election option, each Columbia share will be exchanged for up to $74
in new holding company stock, subject to a collar such that, if the average
closing price of NiSource shares during the 30 days prior to the closing of the
transaction is greater than $16.50, Columbia shareholders will receive shares of
the new holding company valued at $74 for each share of Columbia stock, and if
the average closing price of NiSource shares during the 30 days prior to closing
of the transaction is $16.50 or below, Columbia shareholders will receive 4.4848
shares of new holding company stock for each Columbia share. Upon completion of
the transaction, NiSource shareholders will receive one share of holding company
stock for each share of NiSource common stock that they own.
The Merger is conditioned upon, among other things, the approvals of the
shareholders of both companies and various regulatory commissions. However, if
the NiSource shareholder approval is not obtained, the transaction will
automatically be restructured so that, instead of each of NiSource and Columbia
becoming wholly-owned subsidiaries of the new holding company, Columbia will
become a wholly owned subsidiary of NiSource, and Columbia shareholders will
receive $70 in cash and a $3.02 face value SAILS(sm) unit of NiSource with no
option for Columbia shareholders to elect new holding company stock.
Presentation of Segment Information
Columbia revised its presentation of primary business segment information
beginning with the reporting of third quarter 1999 results. The results for
Columbia Propane have been moved from the propane, power generation and
liquefied natural gas (LNG) operations to energy marketing operations that also
includes Columbia Energy Services' retail operations. Prior periods have been
restated to reflect this change.
Impact of Year 2000 on Computer and Other Systems
The Year 2000 issue was a worldwide concern because certain existing software,
hardware and embedded systems were initially designed without addressing the
impact of the change to the Year 2000. If not corrected, these systems could
have failed or created erroneous results. In October 1999, Columbia announced
that it had met its Year 2000 readiness objectives designed to provide
uninterrupted, safe and reliable delivery of natural gas through the Year 2000.
Columbia's comprehensive Year 2000 program included a thorough evaluation of its
information technology and non-information technology to determine if they were
Year 2000 compliant and,
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20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
ensure that the appropriate corrective action was completed, if appropriate. The
total cost of assessing, testing and remediating Columbia's systems for Year
2000 compliance was approximately $19 million. Since the date change, Columbia
has not experienced any interruption in service.
As part of its normal operations, Columbia continuously operates in a
safety-conscious, high-reliability environment and has numerous back-up systems
in place. As a result of the extensive planning that was incorporated into
Columbia's contingency plans and the Year 2000 project, management believed that
the most reasonably likely worst case Year 2000 scenario would have involved
minor failures that were not detected and corrected during the project. However,
such failures were not experienced.
Common Stock Prices and Dividends*
Market Price
----------------------------------------------------------
Quarterly
Quarter Ended High Low Close Dividends Paid
- -----------------------------------------------------------------------------------------------------------------------------------
$ $ $ $
1999
December 31 66 1/4 55 1/16 63 1/4 .225
September 30 64 11/16 54 1/4 55 3/8 .225
June 30 64 1/4 43 7/8 62 11/16 .225
March 31 58 44 5/8 52 1/4 .200
- -----------------------------------------------------------------------------------------------------------------------------------
1998
December 31 60 3/4 54 1/4 57 3/4 .200
September 30 60 3/8 47 1/2 58 5/8 .200
June 30 57 11/12 50 1/3 55 5/8 .200
March 31 52 17/24 47 1/3 51 5/6 .166
- -----------------------------------------------------------------------------------------------------------------------------------
* Amounts have been restated to reflect a three-for-two common stock
split, in the form of a stock dividend, effective June 15, 1998.
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21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
TRANSMISSION AND STORAGE OPERATIONS
Columbia's transmission and storage segment consists of the operations of
Columbia Transmission, Columbia Gulf Transmission Company (Columbia Gulf) and
Columbia Pipeline Corporation. Together they own a pipeline network of
approximately 16,250 miles extending from offshore in the Gulf of Mexico to Lake
Erie, New York and the eastern seaboard serving 15 northeastern, mid-Atlantic,
midwestern and southern states, as well as the District of Columbia. In
addition, Columbia Transmission operates one of the nation's largest underground
natural gas storage systems.
Proposed Millennium Pipeline Project
The proposed Millennium Pipeline Project (Millennium Project), in which Columbia
Transmission is participating and will serve as developer and operator, will
transport western gas supplies to northeast and mid-Atlantic markets. The
442-mile pipeline will connect to TransCanada Pipe Lines Ltd. at a new Lake Erie
export point and transport approximately 700,000 Mcf per day to eastern markets.
Nine shippers have signed agreements for the available capacity. A filing with
the Federal Energy Regulatory Commission (FERC), requesting approval of the
Millennium Project, was made on December 22, 1997. This filing began the
extensive review process, including opportunities for public review,
communication and comment. The Millennium Project sponsors proposed an
in-service date of November 1, 2000. However, the final in-service date for the
entire project is now expected to be delayed as a result of the timing of
certificate approval by the FERC.
The sponsors of the proposed Millennium Project are Columbia Transmission,
Westcoast Energy, Inc., TransCanada Pipe Lines Ltd. and MCN Energy Group, Inc.
Market Expansion Project
Columbia Transmission initiated services under the final phase of the market
expansion project in November 1999. The expansion project, which was phased in
over a three-year period, added approximately 500,000 Mcf per day of firm
service to 23 customers.
Columbia Transmission's Phase II Rate Proceeding
Columbia Transmission's rate case settlement, approved by the FERC in April
1997, provided for a hearing in the fall of 1998 to address environmental cost
recovery that was excluded from the settlement. However, at the request of
Columbia Transmission and other active parties, the schedule was suspended in
May 1998 in order to afford the parties an opportunity to pursue settlement
discussions. As a result of these discussions, the active parties reached an
agreement on the overall components of an environmental settlement. The
comprehensive agreement included such major components as Columbia
Transmission's total allowed recovery of environmental remediation program costs
and the disposition of any proceeds received by Columbia Transmission from
insurance carriers and others. Columbia Transmission filed the stipulation and
agreement with the FERC on April 5, 1999, and on September 15, 1999, the FERC
approved the settlement. No requests for rehearing were filed. The approval of
the settlement did not have a material impact on Columbia's consolidated
financial results.
Proposed East Lateral Expansion and SunStar Pipeline Projects
Columbia Gulf announced plans in September 1998 to consider an expansion of its
onshore East Lateral system at Grand Isle, Louisiana. The expansion of the East
Lateral would provide additional capacity to shippers from Grand Isle. The
expansion, which would add approximately 600,000 Mcf per day of incremental firm
transportation capacity, would be accomplished by adding new facilities and
expanding existing facilities.
The proposed SunStar Pipeline Project, in which Columbia Gulf is participating
and will serve as the developer and operator, will transport gas from the deep
water areas of the Gulf of Mexico to Columbia Gulf's onshore lateral at Grand
Isle. This offshore pipeline project of approximately 56 miles would have
capacity of 660,000 Mcf per day and is complementary to the expansion of the
East Lateral system facilities, mentioned above.
Columbia Gulf conducted open seasons in the fall of 1998 to obtain binding
commitments from interested parties for the additional capacity from the East
Lateral expansion and the SunStar Pipeline Project. Based on the open season
interest, Columbia Gulf is reevaluating the design parameters of the proposed
pipelines and continuing its negotiations with potential shippers who are
drilling prospects in the proposed service area of the Gulf of Mexico.
Volunteer Pipeline
On April 14, 1999, Columbia Gulf, MCN Energy Group, Inc. and AGL Resources, Inc.
announced the start of an open season offering approximately 250,000 Mcf per day
of capacity in a proposed 24-inch natural gas pipeline extending approximately
160 miles from an interconnection near
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22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
Portland, Tennessee to an interconnection near Chattanooga, Tennessee. The
pipeline, to be called the Volunteer Pipeline (Volunteer), anticipates
additional interconnections with several pipeline companies including Columbia
Gulf.
Volunteer recently concluded the open season where nearly a dozen companies
requested more than 440,000 Mcf per day of capacity. Potentially expandable to
approximately 500,000 Mcf per day, Volunteer expects to provide firm natural gas
transportation from the mid-continent into the Atlanta, Georgia, and other
southeastern markets.
Subsequent to the open season, AGL Resources, Inc. withdrew its participation in
the project. Volunteer expects to file an application with the FERC in 2000 and
to be in service by November 2001. Columbia Gulf will serve as operator of the
new pipeline facilities.
Trailblazer
Effective November 30, 1999, Columbia Gulf sold its 100% interest in CGT
Trailblazer, L.L.C., which was formed for the sole purpose of holding Columbia
Gulf's one-third-partnership interest in the Trailblazer Pipeline Company. The
sale price was approximately $38 million in cash.
Competition and the Effect of LDC Unbundling Services
Columbia's transmission and storage subsidiaries compete with other interstate
pipelines for the transportation and storage of natural gas. Since the issuance
of FERC Order No. 636, various states throughout Columbia Transmission's service
area have initiated proceedings dealing with open access and unbundling of local
distribution companies' (LDC) services. Among other things, unbundling involves
providing all LDC customers with the choice of what entity will serve as
transporter as well as merchant supplier. While the scope and timing of these
various unbundling initiatives varies from state to state, retail choice
programs are being extended to increasing numbers of LDC customers throughout
Columbia Transmission's market area.
Among the issues being addressed in the state unbundling proceedings is the
treatment of the pipeline transmission and storage agreements that have
underpinned the traditional LDC merchant function. In the case of Columbia
Transmission and Columbia Gulf, contracts covering the majority of their firm
transportation and storage quantities with LDCs have primary terms that extend
to October 31, 2004. Management fully expects that the LDCs, or those entities
to which pipeline capacity may be assigned as a result of the LDC unbundling
process, will continue to fulfill their obligations under these contracts.
However, in view of the changing market and regulatory environment, Columbia's
transmission companies have commenced the process of discussing long-term
transportation and storage service needs with their firm customers. Those
discussions could result in the restructuring of some of these contracts on
mutually agreeable terms prior to 2004.
Regulatory Matters
Mainline '99
Columbia Gulf filed an application with the FERC on June 5, 1998, for authority
to increase the maximum certificated capacity of its mainline facilities. The
expansion project, referred to as Mainline '99, will increase Columbia Gulf's
certificated capacity to nearly 2.2 billion cubic feet per day (Bcf/day), by
replacing certain compressor units and increasing the horsepower capacity of
other compressor stations. It is expected that the total cost of the project
would be approximately $37.6 million. Various shippers contracted for the
additional service through an open bidding process held in late 1997 and early
1998. On February 10, 1999, the FERC issued an order approving Columbia Gulf's
June 1998 filing and construction commenced on March 3, 1999. On March 12, 1999,
requests for rehearing of the FERC order were filed by three parties. On January
31, 2000, the FERC issued an order denying the requests for rehearing and
validating the open season held in conjunction with Mainline '99. The FERC chose
to address the requirement of holding an additional open season in the Columbia
Gulf mainline capacity proceeding (see Columbia Gulf Mainline Capacity
Proceeding below). On December 1, 1999, approximately 270,000 Dth/day of
additional capacity was made available on Columbia Gulf's mainline. Additional
capacity of approximately 45,000 Dth/day is expected to be made available on
November 1, 2000.
Discussions with FERC
The transmission and storage subsidiaries are in confidential and informal
discussions with the staff of the FERC (Staff) concerning the scope of
authorization for certain past transactions under the relevant filed tariffs.
The transmission and storage subsidiaries initiated these discussions with the
FERC. These subsidiaries provided information concerning these transactions to
the Staff pursuant to an informal non-public inquiry being conducted by the
Staff. Because management does not yet know the position Staff will take,
management is unable to reasonably estimate the amount that will have to be paid
pursuant to reimbursement or other remedies.
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23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
Columbia Gulf Mainline Capacity Proceeding
In 1993, the FERC directed Columbia Gulf to show cause as to why it had not
sought FERC abandonment authorization to reduce capacity on its mainline
facility. In an August 8, 1997 order, the FERC approved a settlement between
Columbia Gulf and FERC's enforcement staff requiring Columbia Gulf to conduct a
30-day open season on additional firm mainline capacity up to its certificated
design. Although certain of Columbia Gulf's customers challenged the terms of
the settlement, Columbia Gulf concluded the open season on December 15, 1997
which resulted in requests for capacity that exceeded the capacity specified in
Columbia Gulf's FERC certificate. In orders issued in December 1998 and 1999,
the FERC has rejected challenges to the settlement and denied rehearing. In its
order issued December 22, 1999, the FERC affirmed the validity of the 1997 open
season but indicated that an additional open season in compliance with the
settlement will be necessary. In early February 2000, several appeals of the
FERC's orders in this proceeding were filed with the federal circuit court of
appeals.
Columbia Transmission's Voluntary Incentive Retirement Program
Columbia Transmission announced the introduction of a voluntary incentive
retirement plan on September 30, 1999. Approximately 600 Columbia Transmission
employees were eligible for the program, which provides a retirement incentive
for active employees who are age fifty and above with at least five years of
service as of March 1, 2000. During the acceptance period that began on January
1, 2000 and closed on January 31, 2000, 486 employees elected early retirement.
The majority of the retirements are scheduled to occur in the first quarter of
2000, at which time the cost of the program will be recorded. Retirement costs
for these employees are funded through the pension plan and will not have a
significant impact on Columbia's consolidated net income.
Sale of Facilities
During 1999, Columbia Transmission sold approximately 1,150 miles of gathering
pipelines and related properties. In addition, the Kanawha Separation Plant and
its appurtenances were sold to an affiliate. Agreements are in place for an
additional 970 miles of gathering and transmission pipelines to be sold to third
parties. Excluding these sales, there are approximately 150 miles of gathering
lines remaining to be sold or refunctionalized. The sale of these assets will
not have a material impact on Columbia's consolidated financial results.
Storage Base Gas Sales
Columbia Transmission has agreements to sell 4.8 billion cubic feet (Bcf) of
base gas volumes in the first quarter of 2000. Base gas represents storage
volumes that are maintained to ensure that adequate pressure exists to deliver
current inventory. However, as a result of ongoing improvements made in Columbia
Transmission's storage operations, from time-to-time certain of these storage
volumes are determined to be unnecessary to maintain deliverability of current
inventory. Columbia Transmission is allowed to retain approximately 95% of the
first $60 million pre-tax gain from any base gas sales and to share equally with
customers any gain after that level. As a result of such sales in the first
quarter of 2000, Columbia Transmission will reach the $60 million pre-tax gain
level. Gains from any future base gas sales will be shared equally with Columbia
Transmission's customers.
Capital Expenditure Program
The transmission and storage segment's net capital expenditure program was
$183.4 million in 1999 and is projected to be $148.4 million in 2000. New
business initiatives totaled approximately $86 million in 1999 and are expected
to be $44 million in 2000. The remaining expenditures are for modernizing and
upgrading facilities.
Environmental Matters
Columbia's transmission subsidiaries have implemented programs to continually
review compliance with existing environmental standards. In addition,
transmission subsidiaries continue to review past operational activities and to
formulate remediation programs where necessary.
Columbia Transmission is currently conducting assessment, characterization and
remediation activities at specific sites under a 1995 Environmental Protection
Agency (EPA) Administrative Order by Consent (AOC). The program pursuant to the
AOC covers approximately 240 facilities, approximately 13,000 liquid removal
points, approximately 2,200 mercury measurement stations and about 3,700 storage
well locations. As of December 31, 1999, field characterization has been
performed at most of these sites, and site characterization reports and
remediation plans which must be submitted to the EPA for approval, are in
various stages of development and completion. Characterization of the
approximately 40 remaining facilities and all of the storage well locations is
yet to be completed. Significant remediation has taken place only at mercury
measurement stations and at a limited number of the 240 facilities. Only those
site investigation, characterization and remediation costs currently known and
determinable can be considered "probable and reasonably estimable" under
Statement of Financial Accounting Standards No. 5, "Accounting for
Contingencies" (SFAS No. 5). As costs become probable and reasonably estimable,
the associated reserves will be adjusted as appropriate. Columbia Transmission
is unable, at this time, to
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24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
accurately estimate the time frame and potential costs of the entire program.
Management expects that as characterization is completed and additional
remediation work is performed and more facts become available, it will be able
to develop a probable and reasonable estimate for the entire program or a major
portion thereof consistent with U.S. Securities and Exchange Commission's Staff
Accounting Bulletin No. 92, SFAS No. 5, and American Institute of Certified
Public Accountants Statement of Position 96-1.
As a result of 1999 activities, actual expenditures of approximately $16.8
million were charged against the liability resulting in a remaining liability of
$121.4 million. Columbia Transmission's environmental cash expenditures are
expected to be approximately $17 million in 2000 and to remain at this level in
the foreseeable future. These expenditures will be charged against the
previously recorded liability. Consistent with Statement of Financial Accounting
Standards No. 71, a regulatory asset has been recorded to the extent
environmental expenditures are expected to be recovered through rates.
Management does not believe that Columbia Transmission's environmental
expenditures will have a material adverse effect on its operations, liquidity or
financial position, based on known facts and existing laws and regulations, its
cost recovery settlement with customers and the long time period over which
expenditures will be made.
In addition, predecessor companies of Columbia Transmission may have been
involved in the operation of manufactured gas plants. When such plants were
abandoned, material used and created in the process was sometimes buried at the
site. As of the date of this report, Columbia Transmission is unable to
determine if it will become liable for any characterization or remediation costs
at such sites.
Throughput
Columbia Transmission's throughput consists of transportation and storage
services for LDCs and other customers within its market area. Throughput for
Columbia Gulf reflects mainline transportation services from Rayne, Louisiana to
Leach, Kentucky and short-haul transportation services from the Gulf of Mexico
to Rayne, Louisiana.
In 1999, throughput for the transmission and storage segment increased 53.3 Bcf
from 1998 to 1,250.8 Bcf, due to the colder weather in 1999 and increased
transportation services from Columbia Transmission's market expansion project.
Market area transportation by Columbia Transmission increased 57.9 Bcf to
1,005.7 Bcf. Mainline transportation for Columbia Gulf increased 30.9 Bcf to
594.2 Bcf in 1999, reflecting the impact of colder weather in Columbia
Transmission's operating territory. Short-haul transportation of 220.2 Bcf in
1999 was down 11 Bcf from 1998, due to a decline in market demand in the area
south of Rayne, Louisiana.
Throughput for 1998 of 1,197.5 Bcf decreased 104 Bcf when compared to the year
earlier primarily due to warmer than normal weather in Columbia Transmission's
operating territory that reduced demand for natural gas. The warmer weather was
the principal reason that Columbia Transmission's market area transportation of
947.8 Bcf in 1998, decreased 84.8 Bcf. In addition, warmer weather in 1998 also
reduced transportation for Columbia Gulf's mainline transportation of 563.3 Bcf
by 44.2 Bcf from 1997 and Columbia Gulf's short-haul transportation of 231.2 Bcf
by 21.2 Bcf.
Operating Revenues
Operating revenues of $836.4 million in 1999 were down $2.3 million from 1998.
After adjusting for revenue items that are offset in operating expenses,
operating revenues increased by $6.1 million, primarily due to an increase in
Columbia Transmission's market expansion contracts.
Operating revenues in 1998 of $838.7 million were essentially unchanged from
1997. After adjusting for revenue items that are offset in operating expenses,
operating revenues in 1998 decreased $2.6 million. The effect of the sale of
gathering facilities and a lower cost-of-service level underlying Columbia
Transmission's rates in 1998 was only partially offset by increased revenues
from transportation and storage services. The sale of storage base gas volumes
that were part of Columbia Transmission's overall 1997 rate case settlement
improved revenues in both 1998 and 1997.
Operating Income
In 1999, operating income for the transmission and storage segment of $350.1
million increased $24 million over 1998. This increase primarily reflected the
pre-tax effect of a producer settlement and additional revenues primarily
resulting from Columbia Transmission's market expansion project. The 1998
results benefited from reduced postretirement benefit costs and Columbia Gulf's
regulatory settlement. Both periods included base gas sales, $14.7 million in
1999 and $13.9 million in 1998.
Operating income of $326.1 million for 1998 increased $67.8 million over 1997
due to a decline in operating expenses. Operation and maintenance expenses for
1998 declined $64.3 million compared with 1997, primarily reflecting
24
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
restructuring costs recorded in 1997 and the beneficial effect of implementing
those restructuring initiatives in 1998. Also making 1997 operation and
maintenance expense higher when compared to 1998 was a $10.1 million reserve
recorded in 1997 for the anticipated loss related to the sale of certain
pipeline facilities.
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION AND
STORAGE OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Transportation revenues $ 615.0 $ 620.4 $ 622.0
Storage revenues 182.4 186.0 179.8
Other revenues 39.0 32.3 36.8
- ----------------------------------------------------------------------------------------------------------
Total Operating Revenues 836.4 838.7 838.6
- ----------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 358.9 358.9 423.2
Settlement of gas supply charges (31.7) - -
Depreciation 106.2 101.8 104.3
Other taxes 52.9 51.9 52.8
- ----------------------------------------------------------------------------------------------------------
Total Operating Expenses 486.3 512.6 580.3
- ----------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 350.1 $ 326.1 $ 258.3
- ----------------------------------------------------------------------------------------------------------
TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 183.4 210.0 251.4 142.7 169.1
- --------------------------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Transportation
Columbia Transmission
Market area 1,005.7 947.8 1,032.6 1,102.4 1,106.1
Columbia Gulf
Mainline 594.2 563.3 607.5 633.7 605.0
Short-haul 220.2 231.2 252.4 266.5 221.4
Intrasegment eliminations (569.3) (544.8) (591.0) (624.5) (596.3)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL THROUGHPUT 1,250.8 1,197.5 1,301.5 1,378.1 1,336.2
- --------------------------------------------------------------------------------------------------------------------------------
25
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
DISTRIBUTION OPERATIONS
Columbia's five distribution subsidiaries (Distribution) provide natural gas
service to nearly 2.1 million residential, commercial and industrial customers
in Ohio, Pennsylvania, Virginia, Kentucky and Maryland.
Market Conditions
Weather in Distribution's market area during 1999 was 12% colder than the record
warm weather of 1998, but still 8% warmer than normal. As a result,
Distribution's weather-sensitive deliveries were up 25 Bcf from 1998.
Competition
Distribution competes with investor-owned, municipal, and cooperative electric
utilities throughout its five-state service area, and to a lesser extent with
propane and fuel oil suppliers. Electric competition is generally strongest in
the residential and commercial markets of Kentucky, southern Ohio, southwestern
Pennsylvania and western Virginia where rates are primarily driven by low-cost
coal-fired generation. The northern Ohio and Pittsburgh areas have less
competitive electric rates due to the use of higher-cost nuclear-generated
power. It is too soon to determine what impact, if any, deregulation of the
electric industry will have on the competitive situation. Distribution continues
to be a strong competitor in the energy market for new homes as a result of
strong customer preference for natural gas.
Approximately 38% of Distribution's industrial and commercial throughput, or 137
Bcf, is susceptible to bypass because these customers are located close to
multiple natural gas pipelines and local gas distribution companies. As a result
of Distribution's competitive strategies, substantial inroads by other natural
gas competitors have been avoided to date.
Regulatory Matters
In May 1998, Columbia Gas of Virginia, Inc. (Columbia of Virginia) filed a rate
case with the Virginia State Corporation Commission (VSCC) requesting an annual
revenue increase of $5.3 million over the revenues then being collected, subject
to refund, under a 1997 rate case filing. In April 1999, Columbia of Virginia
amended its May 1998 rate increase application to revise its rate design for
residential and small general service customers, effective January 1, 2000,
requesting recovery of most non-gas costs through monthly fixed charges rather
than the traditional combination fixed/volumetric charge. On December 23, 1999,
the VSCC issued an order approving a proposed settlement that provides for
additional annual revenue of approximately $4.4 million and rejecting Columbia
of Virginia's rate design proposal. The VSCC order did approve a 20% increase in
the fixed monthly customer charges for residential and small general service
customers which shifts about $4.9 million of annual revenues from the
weather-sensitive volumetric rate to the fixed monthly customer charge.
Distribution continues to pursue initiatives that give retail customers the
opportunity to purchase natural gas directly from marketers and to use
Distribution's facilities for transportation services. These opportunities are
being pursued through regulatory initiatives in all of its jurisdictions, which
resulted in transportation programs being initiated in all five of its service
areas. Once fully implemented, these programs would reduce Distribution's
merchant function and provide all customer classes with the opportunity to
obtain gas supplies from alternative merchants. As these programs expand to all
customers, regulations will have to be implemented to provide for the recovery
of transition capacity costs and other transition costs incurred by a utility
serving as the supplier of last resort if the marketing company cannot supply
the gas. Transition capacity costs are created as customers enroll in these
programs and purchase their gas from other suppliers, leaving Distribution with
pipeline capacity it has contracted for but no longer needs. The state
commissions in Distribution's five jurisdictions are at various stages in
addressing these issues and other transition considerations. Distribution is
currently recovering, or has the opportunity to recover, the costs resulting
from the unbundling of its services and believes that most of such future costs
and costs resulting from being the supplier of last resort will be mitigated or
recovered.
On October 25, 1999, Columbia Gas of Ohio, Inc. (Columbia of Ohio) and a group
comprising diverse interested parties, also known as the Collaborative, filed
with the Public Utilities Commission of Ohio (PUCO) a third amendment to its
1994 rate case. The filing, which was approved by the PUCO on December 2, 1999,
extends Columbia of Ohio's Customer CHOICE(SM) program through October 31, 2004,
freezes base rates through October 31, 2004 and resolves the issue of transition
capacity costs. Under the agreement, Columbia of Ohio would assume total
financial risk for mitigation of transition capacity costs at no additional cost
to customers. Among other items, Columbia of Ohio would have the opportunity to
utilize non-traditional revenue sources as a means of offsetting the costs. The
agreement also requires Columbia of Ohio to submit a proposal addressing issues
related to the merchant function, obligation to serve, and provider of last
resort by April 1, 2000. Columbia of Ohio extended its Customer CHOICE(SM)
program to all of its nearly 1.3 million customers in mid-1998 and there are now
over 519,000 customers
26
27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (continued)
participating, including approximately 445,000 residential customers. Of 41
marketers approved for participation, 32 are currently active.
In addition, the PUCO authorized Columbia of Ohio to revise its depreciation
accrual rates for the period January 1, 1999 through December 31, 2004. The
revised depreciation rates are lower than those that would have been utilized if
Columbia of Ohio were not subject to regulation. The amount of depreciation that
would have been recorded for 1999 had Columbia of Ohio not been subject to rate
regulation is $31.8 million, $18.8 million more than the $13 million recorded.
Over the six-year period, the amount of depreciation that would have been
recorded if Columbia of Ohio were not regulated is estimated to be approximately
$150 million higher than the regulatory depreciation to be recorded. A
regulatory asset will be established for this amount. Pursuant to the terms of
the agreement, rates were not reduced to reflect this reduction in depreciation
expense with most of the excess revenues generated being used to recover
Columbia of Ohio's transition capacity costs.
In Pennsylvania, legislation was signed by the governor in June 1999 that allows
consumers statewide to choose their natural gas supplier. Under the legislation,
all Pennsylvania natural gas utilities, upon approval of the Pennsylvania Public
Utility Commission (PPUC), must offer all of their customers the opportunity to
choose a supplier by July 1, 2000. Before offering choice programs to customers,
each company was required to submit a restructuring plan to the PPUC. The
legislation makes Pennsylvania one of the first states to offer customers both
gas and electric choice on a statewide level. Another major component of the
legislation is the repeal of the gross receipts tax on natural gas use,
effective January 1, 2000. On August 2, 1999, Columbia Gas of Pennsylvania, Inc.
(Columbia of Pennsylvania) filed an expanded statewide restructuring plan with
the PPUC. On August 12, 1999, the PPUC issued a preliminary order providing a
litigation schedule and directing Columbia of Pennsylvania to develop and
implement an interim program for the 1999-2000 heating season while the
permanent plan was being litigated. In October 1999, the PPUC approved the
interim plan, thereby allowing all of the company's residential and small
commercial customers the right to choose a new natural gas supplier, effective
November 1, 1999. Prior to this date, more than 70% of Columbia of
Pennsylvania's customers in seven counties could choose their supplier under a
program approved by the PPUC in 1998. Columbia of Pennsylvania subsequently
negotiated a settlement of the full restructuring plan with 26 parties. On
December 16, 1999, the PPUC unanimously approved the settlement making Columbia
of Pennsylvania the first company to receive PPUC approval of a permanent
statewide program under the guidelines of the June 1999 legislation. As part of
the settlement, Columbia of Pennsylvania will continue to deliver natural gas to
all 390,000 of its customers regardless of their supplier.
In Virginia, legislation was enacted in 1999 permitting Columbia of Virginia,
upon approval by the VSCC, to offer all of its 175,000 residential and
commercial customers the opportunity to choose their natural gas suppliers. This
legislation allows a natural gas distribution company to file for an unbundling
of its rates with the VSCC effective July 1, 2000. Moreover, the legislation
expires on June 30, 2000, unless reenacted by the Virginia General Assembly. In
January 2000, new legislation was introduced in the General Assembly that would
reenact last year's legislation. Columbia of Virginia has been providing a pilot
transportation program in the Gainesville market area of Northern Virginia since
late 1997. There are now over 7,500 customers and 11 marketers participating in
the program. Columbia of Virginia plans to file in 2000 for permission to expand
the Customer CHOICE(SM) program statewide.
In August 1998, the Maryland Public Service Commission approved a two-year
continuation of Columbia Gas of Maryland, Inc.'s (Columbia of Maryland) Customer
CHOICE(SM) program which allows all of its nearly 32,000 customers to select a
natural gas supplier other than Columbia of Maryland. There are approximately
2,900 customers and 5 marketers participating in the program.
In April 1999, Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) filed an
application with the Kentucky Public Service Commission (KPSC) seeking approval
to initiate a residential and small commercial transportation program. Under the
terms of the filing, all of Columbia of Kentucky's 142,000 residential and small
commercial customers would be eligible to choose a new supplier for gas
deliveries commencing in November 1999. In late May 1999, the KPSC issued an
order stating that more time was needed to determine the reasonableness of the
proposal and suspending the filing until March 31, 2000. However, the KPSC said
it could issue a final decision prior to the end of the suspension period. In
late January 2000, the KPSC issued an order approving the transportation program
on a pilot basis effective February 1, 2000 through January 31, 2005. Under the
order, Columbia of Kentucky would become the first utility in Kentucky, gas or
electric, to offer a choice of supplier to all of its customers. Under the terms
of the order, Columbia of Kentucky would have to assume the financial risk for
mitigating transition capacity costs through the utilization of non-traditional
revenue sources. Also, the order did not renew Columbia of
27
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Kentucky's gas cost incentive program, which had been temporarily continued by
the KPSC until the conclusion of the customer transportation case. On February
18, 2000, Columbia of Kentucky filed for rehearing of the order.
Capital Expenditure Program
Distribution's 1999 capital expenditures were approximately $145.5 million, a
decrease of $6.4 million from 1998. In addition to maintaining and upgrading
facilities to assure safe, reliable and efficient operation, 1999 expenditures
included $63.7 million for extending service to new areas and $61.5 million for
replacement and betterment projects. The estimated 2000 capital expenditure
program amounts to approximately $135.6 million, including $54 million for new
business and development, $59 million for replacement and betterment projects
with the remainder primarily for support services.
Environmental Matters
Distribution's primary environmental issues relate to 18 former manufactured gas
plant sites. Investigations or remedial activities are currently underway at six
sites and remedial construction has been completed at two sites. Additional site
investigations may be required at some of the remaining sites. To the extent
Distribution's site investigations have been conducted, remediation plans
developed and the responsibility for remediation established, the appropriate
estimated liabilities have been recorded. Regulatory assets have also been
recorded for a majority of these costs as rate recovery has been authorized or
is probable.
In June 1999, Columbia of Pennsylvania was notified by the Environmental
Protection Agency (EPA) Region 5 that it was a Potentially Responsible Party
(PRP) in a removal action pursuant to Section 106 of the Comprehensive
Environmental Response Compensation and Liability Act (CERCLA), also known as
Superfund, concerning a site in Wooster, Ohio, known as 7-7 Merger, Inc. Coal
tar materials sent by Columbia of Pennsylvania from the former manufactured gas
plant at York, Pennsylvania to 7-7 Merger, Inc. for recycling in 1997 are
potentially among the materials abandoned by 7-7 Merger, Inc. at the Wooster
site. There are approximately 28 parties that received a similar notice from
EPA. There is no reasonable way to estimate liability at this time. However, the
EPA preliminary estimate of the total costs of response is $702,000. Based upon
the EPA estimate and preliminary cost sharing discussions among a PRP group, a
reasonable lower bound estimate of Columbia of Pennsylvania's cost for the
removal action would be approximately $25,000. The PRP group has entered into an
administrative order with EPA Region 5 with work scheduled to begin in March
2000.
Voluntary Workforce Reduction Programs
As a result of Columbia's ongoing review of its various business units, the
utilization of improved technologies and process improvement initiatives,
management has identified a number of ways of working more efficiently. As
discussed below. Columbia is implementing a Voluntary Incentive Retirement
Program (VIRP) for the distribution subsidiaries and certain business units of
Columbia Energy Group Service Corporation, similar to the program discussed in
the Transmission and Storage Operations on page 23 for Columbia Transmission. In
early 1999 Columbia of Pennsylvania announced a Voluntary Severance Program
(VSP) for its employees.
In February 2000, the five distribution subsidiaries and Columbia Energy Group
Service Corporation announced the introduction of a VIRP. Approximately 880
employees are eligible for the program, which provides a retirement incentive
for certain active employees who are age fifty and above with at least five
years of service as of June 1, 2000. The acceptance period will end on April 30,
2000. The majority of the retirements are scheduled to occur on June 1, 2000, at
which time the cost of the program will be recorded. Retirement costs for these
employees are funded through the pension plan and will not have a significant
impact on Columbia's consolidated net income.
In January 1999, Columbia of Pennsylvania announced a VSP that was available to
all of its nearly 700 employees in its operations department. In total, 37
professional, manual and administrative/technical employees in the operations
department elected to participate in the program. By combining the VSP with
other workforce reduction measures, Columbia of Pennsylvania has reduced
staffing by about 45 full-time employees. These initiatives resulted in a first
quarter 1999 charge to operating expense of $1.5 million, representing severance
and benefit costs for the participating employees, most of whom left the company
by March 17, 1999.
Throughput
In 1999, total volumes sold and transported of 696.8 Bcf increased 138.6 Bcf
from 1998. The improved throughput reflects the colder weather in 1999 compared
to 1998, along with a 108 Bcf increase in off-system sales as Distribution took
advantage of higher spot prices in March 1999 to sell supplies available due to
warmer than normal weather.
Distribution's 1998 total volumes sold and transported of 558.2 Bcf decreased
13.9 Bcf from 1997 due to the record warm weather in 1998. Increased off-system
sales, the return to full production of a major customer idled by a 10-month
strike in 1997, increased industrial transportation volumes and customer growth
partially offset the adverse impact on sales of the record warm weather in 1998.
Net Revenues
Net revenues for 1999 of $852.6 million were up $5.6 million from 1998 as the
impact of the colder weather in 1999 and Columbia of Virginia's regulatory
settlement were largely offset by Columbia of Ohio's contribution of $23.8
million to the transition capacity cost pool pursuant to the 1999 rate
settlement. The revenue impact on operating income of this contribution is more
than offset by a related reduction in depreciation expense provided by the
28
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
settlement. Revenues in 1998 benefited from Columbia of Ohio's 1996 regulatory
settlement, which expired in December 1998.
In 1998, net revenues of $847 million were down $51.1 million from 1997. This
decline was primarily due to the record warm weather in 1998, which reduced net
revenues approximately $76 million from 1997. The beneficial impact of Columbia
of Ohio's 1997 regulatory settlement on net revenues in 1998 partially offset
the adverse impact of the warm weather.
Operating Income
Operating income for 1999 of $254.6 million increased $28.8 million over 1998,
primarily due to the increase in net revenues, reduced operating expenses
attributable to lower gross receipts and property taxes and, as noted above, the
terms of the 1999 Columbia of Ohio regulatory settlement resulted in reduced
depreciation expense. In 1998, operating expenses were reduced due to a $16.5
million settlement gain related to postretirement benefits costs that reflected
the purchase of insurance for a portion of those liabilities.
Operating income in 1998 of $225.8 million increased by $1.6 million from 1997,
as the decline in net revenues was more than offset by a $52.7 million decrease
in operating expenses primarily reflecting the reduction in postretirement
benefits costs and the beneficial impact of the restructuring initiatives
implemented in 1997.
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $ 1,705.5 $ 1,686.3 $ 2,153.1
Less: Cost of gas sold 1,137.6 1,005.4 1,385.6
- ----------------------------------------------------------------------------------------------------------------------------------
Net Sales Revenues 567.9 680.9 767.5
- ----------------------------------------------------------------------------------------------------------------------------------
Transportation revenues 317.3 183.2 143.2
Less: Associated gas costs 32.6 17.1 12.6
- ----------------------------------------------------------------------------------------------------------------------------------
Net Transportation Revenues 284.7 166.1 130.6
- ----------------------------------------------------------------------------------------------------------------------------------
Net Revenues 852.6 847.0 898.1
- ----------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 406.9 386.7 441.0
Depreciation 54.5 82.2 78.2
Other taxes 136.6 152.3 154.7
- ----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 598.0 621.2 673.9
- ----------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 254.6 $ 225.8 $ 224.2
- ----------------------------------------------------------------------------------------------------------------------------------
29
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
DISTRIBUTION OPERATING HIGHLIGHTS
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 145.5 151.9 159.5 148.4 151.8
- --------------------------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
Residential 132.5 149.1 190.9 209.4 196.6
Commercial 43.7 54.1 72.7 85.7 79.5
Industrial and Other 3.5 4.4 4.2 10.3 7.1
- --------------------------------------------------------------------------------------------------------------------------------
Total Sales 179.7 207.6 267.8 305.4 283.2
Transportation 346.2 287.7 258.9 248.8 255.9
- --------------------------------------------------------------------------------------------------------------------------------
Total Throughput 525.9 495.3 526.7 554.2 539.1
Off-System Sales 170.9 62.9 45.4 10.8 7.5
- --------------------------------------------------------------------------------------------------------------------------------
Total Sold and Transported 696.8 558.2 572.1 565.0 546.6
- --------------------------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
Spot market* 302.2 229.8 314.0 323.2 210.4
Producers 12.6 20.8 38.9 50.2 70.9
Storage withdrawals (injections) 15.5 12.4 4.0 (20.8) 23.6
Company use and other 20.3 7.5 (43.7) (36.4) (14.2)
- --------------------------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 350.6 270.5 313.2 316.2 290.7
Gas received for delivery to customers 346.2 287.7 258.9 248.8 255.9
- --------------------------------------------------------------------------------------------------------------------------------
Total Sources 696.8 558.2 572.1 565.0 546.6
- --------------------------------------------------------------------------------------------------------------------------------
CUSTOMERS
Sales
Residential 1,366,869 1,612,124 1,769,647 1,815,269 1,794,800
Commercial 123,673 148,529 168,413 173,689 172,114
Industrial and Other 2,264 2,295 2,340 2,285 2,265
- --------------------------------------------------------------------------------------------------------------------------------
Total Sales Customers 1,492,806 1,762,948 1,940,400 1,991,243 1,969,179
Transportation 603,901 298,107 93,923 12,804 6,789
- --------------------------------------------------------------------------------------------------------------------------------
Total Customers 2,096,707 2,061,055 2,034,323 2,004,047 1,975,968
- --------------------------------------------------------------------------------------------------------------------------------
DEGREE DAYS 5,171 4,635 5,736 5,975 5,692
- --------------------------------------------------------------------------------------------------------------------------------
* Reflects volumes under purchase contracts of less than one year.
30
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
EXPLORATION AND PRODUCTION OPERATIONS
Columbia's exploration and production subsidiary, Columbia Resources, is one of
the largest independent natural gas and oil producers in the Appalachian Basin
and also has production operations in Canada. Columbia Resources produced
approximately 47 Bcf equivalents (Bcfe) of natural gas and oil in 1999 and owns
and operates 8,188 wells, and has net proven reserve holdings of 965.8 Bcfe at
December 31, 1999. Columbia Resources also owns and operates approximately 6,069
miles of gathering pipelines.
Columbia Resources seeks to achieve asset and profitable growth through
acquisitions, expanded drilling activities and divestiture of under-performing
assets. During 1999, Columbia Resources completed the largest and most
successful exploration and development program in its history. Columbia
Resources exceeded its originally projected 230 well program by drilling 233
wells and participated in another 20 wells with joint venture partners. Also,
Columbia Resources had a well completion success rate of 82% in 1999 consistent
with its success rate over the last five years. Columbia Resources participated
in the drilling and completion of 263 wells during 1999. The success of these
wells added 70.5 net Bcfe to Columbia Resources' reserve base. An additional 68
Bcfe of oil and gas reserves were acquired from Wiser Oil and Meridian
Exploration, bringing Columbia Resources' reserve base to a record level of
965.8 Bcfe.
During 1999, Columbia Resources' acquisition strategy involved six transactions
totaling approximately $61 million and expansion of the gathering infrastructure
by more than 450 miles of pipeline. Also notable in 1999 was the discovery by
Columbia Resources of reserves in West Virginia in the Trenton-Black River
formation at depths exceeding 10,000 feet. Columbia Resources recently completed
construction of an eight-inch gathering pipeline and has connected the discovery
well at a flowing rate in excess of 7.4 million cubic feet per day. A
confirmation well, which has indicated strong production characteristics, was
tied into the same pipeline network at the end of December. Drilling on the
third prospect was completed in the first quarter of 2000.
Capital Expenditure Program
Columbia Resources' 1999 capital expenditures of $166.5 million primarily
reflect investments in drilling and acquisitions. The 2000 capital expenditure
program is estimated at $165.7 million and provides for the drilling of 330 new
wells in the Appalachian Basin and Canada. This investment will include the
expansion of Columbia Resources' gathering infrastructure in the Appalachian
Basin and the continued expansion of its acreage position.
Forward Sale of Natural Gas
On December 1, 1999, Columbia Resources entered into an agreement with a third
party whereby Columbia Resources received cash as a prepayment, and will sell
approximately 45,000 Mcf/d during the period February 2000 through October 2004.
This transaction, net of expenses, provided $148.5 million in cash proceeds for
funding future operating costs and acquisitions and provided a forward sale at
an average commodity price of $2.82 per Mcf exclusive of the basis differential.
Purchase of a Natural Gas Processing Plant
On November 1, 1999, Columbia Resources purchased certain carbon dioxide rights,
a separation plant, and certain natural gas pipelines and facilities located in
Kanawha County, West Virginia from Columbia Transmission. This facility, known
as the Kanawha Separation Plant, was acquired at a price of $3.5 million.
Production
Gas production of 45.8 Bcf in 1999 increased 6.7 Bcf over 1998, primarily due to
the acquisitions of Wiser Oil and Meridian Exploration, new drilling and
improvements to Columbia Resources' gathering facilities. From 1997 to 1998, gas
production increased by 13% reflecting the Alamco acquisition in mid-1997 and
new production brought online in 1998.
In 1999, oil and liquids production decreased 14% from 1998 to 185,207 barrels
due to normal production declines in Ohio wells. Oil and liquids production in
1998 increased 2% from 1997 to 214,000 barrels primarily reflecting new well
completions coming online.
Operating Revenues
Operating revenues for 1999 of $144.8 million increased $17.3 million over 1998
reflecting increased gas production that was partially offset by lower average
1999 gas prices. Columbia Resources manages the uncertainty of natural gas
prices by hedging a portion of its production using derivative instruments.
Columbia Resources hedged approximately 50% of its first quarter 2000 production
at an average price of $3.75 per Mcf. Also contributing to the
31
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
increase in operating revenues in 1999 was $6 million of revenues from the
termination of long-term sales contracts with two cogeneration facilities.
Operating revenues for 1998 were $127.5 million, an increase of $14.2 million
over 1997, primarily reflecting higher average prices and increased gas
production.
Operating Income
Operating income of $44.2 million for 1999 increased $7 million over 1998 as the
increase in operating revenues discussed above was partially offset by $10.3
million higher operating expenses associated with an expanded operation due in
part to recent acquisitions, additional gathering facilities and drilling
activity.
In 1998, operating income improved by $6.3 million to $37.2 million, also
primarily due to higher operating revenues, partially offset by higher operating
expense due largely to acquisitions and increased drilling activity.
STATEMENTS OF OPERATING INCOME FROM EXPLORATION AND PRODUCTION OPERATIONS
(UNAUDITED)
Year Ended December 31, (in millions) 1999 1998 1997
- ------------------------------------------------------------------------------------
OPERATING REVENUES
Gas revenues $123.1 $113.9 $109.5
Other revenues 21.7 13.6 3.8
- ------------------------------------------------------------------------------------
Total Operating Revenues 144.8 127.5 113.3
- ------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 53.9 44.6 45.7
Depreciation and depletion 36.9 36.5 27.6
Other taxes 9.8 9.2 9.1
- ------------------------------------------------------------------------------------
Total Operating Expenses 100.6 90.3 82.4
- ------------------------------------------------------------------------------------
OPERATING INCOME $ 44.2 $ 37.2 $ 30.9
- ------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS
1999 1998 1997 1996 1995*
- -----------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 166.5 75.7 135.6 12.1 86.8
- -----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf) 951.6 790.5 800.5 644.5 599.5
Oil and Liquids (000 Bbls) 2,375 1,835 1,700 774 1,651
- -----------------------------------------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf) 45.8 39.1 34.7 33.6 65.4
Oil and Liquids (000 Bbls) 185 214 210 281 2,849
- -----------------------------------------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf)** 2.66 2.91 2.63 2.84 1.96
Oil and Liquids ($ per barrel) 14.96 12.76 17.99 19.07 16.17
- -----------------------------------------------------------------------------------------------------------------------
* Include operating results from Columbia Gas Development Corporation,
which was sold effective December 31, 1995
** Includes the effect of hedging activities as discussed in Note 6 of
Notes to Consolidated Financial Statements.
32
33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
ENERGY MARKETING OPERATIONS
Energy marketing operations include the operations of Columbia Propane as well
as Columbia Energy Services' retail operations. The results of Columbia Energy
Services also include the operations of Columbia Service Partners, Inc., which
provides a range of warranty products to homeowners, and Energy.com Corporation,
an internet-based business that offers a variety of services to energy marketers
and consumers. Together, these businesses serve 750,000 residential and 70,000
commercial and industrial customers in 34 states.
Columbia Energy Services
The president and CEO of Columbia Energy Services has been conducting a
strategic assessment of all facets of Columbia Energy Services' businesses,
which began in the first quarter of 1999, including ongoing action taken with
company personnel and outside consultants to identify and address infrastructure
weaknesses.
After completing the initial phase of the strategic assessment, it was
determined that Columbia Energy Services would concentrate its efforts primarily
on the retail businesses, taking advantage of Columbia's existing geographic
presence in an area where deregulation of gas and electric power markets is
proceeding rapidly. In December 1999, the Wholesale and Trading operations,
based in Houston, Texas, were sold to Enron North America Corp., a wholly-owned
subsidiary of Enron Corp. for $38.3 million, subject to post-closing
adjustments. The Wholesale and Trading operations are reported as discontinued
operations in Columbia's consolidated financial statements.
Also, as a result of the strategic assessment, it was determined that Columbia
Energy Services should also exit the Major Accounts business that provides
energy services and products to industrial and large commercial customers. In
accordance with generally accepted accounting principles, the Major Accounts
business is also being reported as discontinued operations in Columbia's
consolidated financial statements.
In conjunction with management's ongoing assessment of the opportunities and
challenges facing Columbia's marketing operations, a letter of intent with
Metromedia Energy for a joint venture to market retail energy and related
services has expired and will not be renewed.
Columbia Propane Acquisitions
During 1999, Columbia Propane made several acquisitions to expand its
operations.
In May 1999, Columbia Propane, through its subsidiary, Columbia Petroleum
Corporation (Columbia Petroleum), completed a transaction to acquire certain
propane and petroleum product assets and associated properties from Carlos R.
Leffler, Inc. (Leffler) and other Leffler entities. Columbia Propane acquired
the propane assets, consisting of bulk storage facilities with a capacity of
over 1.5 million gallons, a pipeline terminal with over 1.2 million gallons of
storage, a propane distribution fleet and wholesale and retail operations
serving central and eastern Pennsylvania. This acquisition provided Columbia
Propane approximately 12,500 propane customers and 36,000 petroleum customers.
In June 1999, Columbia Propane completed its acquisition of Trentane Gas, Inc.
(Trentane Gas). The acquisition of Trentane Gas, a retail propane company
located in north-central Virginia, added approximately 4,300 customers to
Columbia Propane's customer base.
In July 1999, Columbia Propane, through its subsidiary, Columbia Propane, L.P.,
completed the acquisition of National Propane Partners, LP (National Propane),
which added approximately 210,000 customers in 24 states, 155 full service
centers, 101 satellite locations and bulk storage facilities with more than 33
million gallons of propane.
Also in July 1999, Columbia Propane completed its purchase of the propane assets
of ENC Propane and a related appliance sales and services business, both located
in eastern North Carolina. On September 21, 1999, Columbia Propane completed the
purchase of the propane and fuel oil assets of Baker & Russell, Inc. located in
Shippensburg, Pennsylvania. On September 23, 1999, Columbia Petroleum acquired
the assets of Dampman Sturges Oil, in Douglassville, Pennsylvania. In three
other transactions later in 1999, Columbia Propane, L.P. acquired the assets of
Pacer-Acmer Propane in Tekonsha, Michigan, Mid-State Energy in Tomahawk,
Wisconsin and Lewiston Propane in Lewiston, Maine. These acquisitions, together
with the acquisitions of National Propane, Leffler and Trentane Gas, raise the
total number of customers served by Columbia Propane to more than 350,600 in 31
states and the District of Columbia at December 31, 1999, which is more than
triple the number of propane customers served at the end of 1998. On January 7,
2000, Columbia Propane acquired all of the propane related assets of Zoe's
Bottled Gas in Colchester, Connecticut, adding 2,900 additional customers.
33
34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Columbia Petroleum owns and operates the petroleum assets acquired from Leffler
and Dampman Sturges. Columbia Petroleum currently serves 42,000 customers in
five states.
Environmental Activity
Columbia Propane's primary environmental issues relate to former manufactured
gas plant sites acquired in the acquisition of National Propane for which
accruals were made by National Propane. Investigations are currently underway at
one site. One other known former manufactured gas plant site is inactive. It is
possible that former manufactured gas plant sites exist at two other National
Propane properties. Management does not believe that Columbia Propane's
environmental expenditures will have a material adverse effect on Columbia's
consolidated financial results.
Commodity Hedging Activity
Columbia Propane purchases propane and petroleum and places it in storage for
future sale and hedges its inventory against the risk of decreasing prices.
Columbia Energy Services hedges anticipated fixed-price sales of its Mass
Markets business.
Capital Expenditures
A large portion of the $315.5 million capital expenditure program in 1999 was
allocated to propane acquisitions. The 2000 capital expenditure program is
estimated at $43.3 million, including $20 million for propane acquisitions.
Net Revenues
In 1999, net revenues were $90.1 million, up $47.9 million from 1998, primarily
due to Columbia Propane's acquisitions and colder weather in 1999. The
improvement in propane revenues due to additional volumes being sold was
partially offset by lower margins. Petroleum revenues reflect the results of the
acquisition of Leffler and Dampman Sturges in 1999, as discussed previously.
Columbia Energy Services' Mass Markets business reported revenues of $88.9
million, an increase of $67.3 million over 1998, due to a significant increase
in the number of customers being served. Other revenues of $27.2 million,
increased $15.7 million reflecting sales revenues from appliance, warranty and
lubricant products and other miscellaneous revenues, primarily as a result of
the National Propane and Leffler acquisitions.
In 1998, net revenues of $42.2 million improved $5.4 million over 1997 due
largely to net revenues generated by the Mass Markets business, which began in
1998.
Operating Income/Loss
In 1999, an operating loss of $54.5 million was recorded compared to an
operating loss of $13.6 million in 1998. The improvement in net revenues was
more than offset by higher operating costs for Columbia Energy Services' retail
operations that included additional investment in its infrastructure. The
operating loss for Columbia Energy Services for 1999 was $50.6 million compared
to $17.7 million in 1998. Included in the higher costs for Columbia Energy
Services was $14.3 million recorded in 1999 to reflect the write-down of certain
computer software no longer necessary for its operations and an adjustment for
uncollectible accounts. In addition, higher costs were incurred by Columbia
Propane due to its expanded operations and the ongoing process of integrating
recent propane and petroleum acquisitions.
An operating loss of $13.6 million was recorded in 1998 compared to operating
income of $6 million in 1997. The higher net revenues was more than offset by
additional costs to build Columbia Energy Services' infrastructure, customer
acquisition costs related to adding new Mass Markets customers, and increased
costs associated with expanded propane operations resulting from acquisitions.
34
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
STATEMENTS OF OPERATING INCOME FROM ENERGY MARKETING OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1999 1998 1997
- ----------------------------------------------------------------------------------
NET REVENUES
Propane $ 152.9 $ 63.1 $ 70.4
Gas 88.9 21.6 --
Petroleum 127.7 -- --
- ----------------------------------------------------------------------------------
Total 369.5 84.7 70.4
Less: Products purchased 306.6 54.0 43.4
- ----------------------------------------------------------------------------------
Gross Margin 62.9 30.7 27.0
Other revenues 27.2 11.5 9.8
- ----------------------------------------------------------------------------------
NET REVENUES 90.1 42.2 36.8
- ----------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 109.5 47.0 25.4
Depreciation 26.6 5.8 3.6
Other taxes 8.5 3.0 1.8
- ----------------------------------------------------------------------------------
Total Operating Expenses 144.6 55.8 30.8
- ----------------------------------------------------------------------------------
OPERATING INCOME (LOSS) $ (54.5) $ (13.6) $ 6.0
- ----------------------------------------------------------------------------------
ENERGY MARKETING OPERATING HIGHLIGHTS
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 315.5 27.9 10.4 5.2 5.7
- --------------------------------------------------------------------------------------------------------
SALES
Propane (millions of gallons) 178.3 66.5 70.9 75.9 68.9
Gas (billion cubic feet) 28.4 6.1 -- -- --
Petroleum (millions of gallons) 202.4 -- -- -- --
- --------------------------------------------------------------------------------------------------------
PROPANE CUSTOMERS 350,652 113,748 96,954 79,650 74,308
- --------------------------------------------------------------------------------------------------------
35
36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
POWER GENERATION, LNG AND OTHER OPERATIONS
Telecommunications Network
In the second quarter of 1999, Columbia Transmission Communication Corporation
(Transcom), a wholly-owned subsidiary of Columbia, began the construction of its
telecommunications network along the Washington, D.C. to New York City corridor.
Transcom will build and maintain a fiber optics network on rights-of-way of
Columbia's pipeline companies. Transcom expects to complete the D.C. to New York
fiber optics link in the first half of 2000. The route covers 260 miles and
provides access to 16 million people in the busiest telecommunications corridor
in the United States. The company is developing plans to extend the fiber optics
network beyond the initial route.
Power Generation Activities
Columbia Electric Corporation (Columbia Electric) is an unregulated electric
generation company whose primary focus is the development, ownership and
operation of clean, natural gas fueled power projects. Columbia currently has
three operating facilities totaling 248 megawatts, one 550-megawatt (equivalent)
plant under construction in Gregory, Texas and approximately 3,000 megawatts of
gas-fired generation under development. Publicly announced projects in Columbia
Electric's development portfolio include the Kelson Ridge Project in Charles
County, Maryland, the Liberty Electric Project in Eddystone, Pennsylvania, the
Grassy Point Energy Project in Haverstraw, New York, the Ceredo Electric
Generating Station in Ceredo, West Virginia and the Henderson Generating Station
in Henderson, Kentucky.
The Gregory Project, a partnership between subsidiaries of Columbia Electric and
LG&E Power, Inc., is anticipated to start operations in the summer of 2000.
Construction of the Liberty Electric Project is anticipated to commence in
spring 2000. Ownership of the Liberty Electric Project was jointly held by
Columbia Electric and subsidiaries of Westcoast Energy, Inc. (Westcoast). In
December 1999, the ownership agreement between Columbia and Westcoast was
terminated due to allocation of capital to other projects by Westcoast in
geographic areas more closely aligned with other Westcoast operating assets and
the desire of Westcoast to focus its resources in ventures that will generate
near-term operating income. Columbia Electric announced on February 16, 2000,
that it purchased Westcoast's 50% interest and now owns 100% of the Liberty
Electric Project.
In December 1999, a limited partnership established between Columbia Electric
and Atlantic Generation, Inc. completed a transaction terminating a long-term
power purchase contract. Columbia Electric's portion was approximately $71
million pre-tax under the terms of the buyout. The partners will continue to
operate the facility as a merchant power plant.
Liquified Natural Gas Operations
In January 2000, Columbia Atlantic Trading Corporation acquired Potomac Electric
Power Company's (Pepco) 50% interest in the Cove Point LNG Limited Partnership
for $40.7 million. This acquisition gives Columbia LNG Corporation (Columbia
LNG) and Columbia Atlantic Trading Corporation 100% ownership of the Cove Point
liquefied natural gas (LNG) terminal in Cove Point, Maryland and certain other
pipeline facilities, which had been owned equally by Columbia LNG and Pepco
since 1994.
The current operations include operating one of the largest natural gas peaking
and storage facilities in the United States. With approximately 5 Bcf of vapor
equivalent storage capacity, the facility enables LNG to be stored until needed
for the winter peak-day requirements of utilities and other large gas users. The
acquisition will facilitate Columbia's plans to reactivate the LNG receiving
facilities and expand the business to include LNG tanker unloading services at
the terminal. Cove Point LNG is holding an open season where potential customers
can bid for capacity. Based on the results of the open season, Cove Point LNG
expects to file a certificate application with the FERC to reactivate the
terminal's marine facilities. Pending approval by the FERC, Cove Point LNG plans
to begin LNG tanker discharging by late 2001.
Capital Expenditures
The capital expenditure program for 1999 was $51 million and included amounts
for the development of Transcom's fiber optics network. The 2000 program is
projected to be $376.5 million, which is primarily for fiber optics, Columbia
Electric's cogeneration projects and the acquisition of Pepco's interest in the
Cove Point LNG Limited Partnership.
36
37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Operating Revenues
In 1999, operating revenues increased $69.6 million from 1998 to $88.7 million
largely due to the $71 million gain from the termination of the cogeneration
power purchase contract, mentioned above.
In 1998, operating revenues of $19.1 million decreased $3.1 million from 1997.
The decrease largely reflected the net effect of Columbia Electric's $3.2
million revenue improvement recorded in the first quarter of 1997 from the
assumption of a cogeneration partnership fuel transportation contract.
Operating Income
Operating income for 1999 of $71.5 million increased $64.9 million over 1998
primarily reflecting the increase in operating revenues, which was partially
offset by a $4.5 million increase in operation and maintenance expense due to
increased staffing levels and development activity for the cogeneration
business.
In 1998, operating income of $6.6 million declined $2.6 million from 1997 as the
decrease in operating revenues was only partially offset by a $500,000 decrease
in operating expenses.
STATEMENTS OF POWER GENERATION, LNG AND OTHER OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1999 1998 1997
- --------------------------------------------------------------------------------
OPERATING REVENUES
Power generation $78.5 $ 8.3 $10.6
LNG 9.3 10.3 11.2
Other 0.9 0.5 0.4
- --------------------------------------------------------------------------------
Operating Revenues 88.7 19.1 22.2
- --------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 16.7 12.2 12.6
Depreciation 0.1 0.1 0.1
Other taxes 0.4 0.2 0.3
- --------------------------------------------------------------------------------
Total Operating Expenses 17.2 12.5 13.0
- --------------------------------------------------------------------------------
OPERATING INCOME $71.5 $ 6.6 $ 9.2
- --------------------------------------------------------------------------------
POWER GENERATION, LNG AND OTHER OPERATING HIGHLIGHTS
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 51.0 2.7 1.0 0.3 3.3
- ---------------------------------------------------------------------------------
37
38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Bankruptcy MatterS
On November 28, 1995, Columbia and its wholly-owned subsidiary, Columbia
Transmission emerged from Chapter 11 protection of the United States Bankruptcy
Code under the jurisdiction of the United States Bankruptcy Court for the
District of Delaware (Bankruptcy Court). Both Columbia and Columbia Transmission
had operated under Chapter 11 protection since July 31, 1991. Certain residual
unresolved bankruptcy-related matters are still within the jurisdiction of the
Bankruptcy Court.
In July 1998, the Bankruptcy Court, granting a motion by Columbia Transmission,
entered an order allowing the claim of the New Bremen Corporation in accordance
with the Claims Mediator's Report and Recommendations and the decision of the
U.S. 5th Circuit Court of Appeals. In August 1998, New Bremen filed a notice of
appeal of this order to the U.S. District Court for the District of Delaware.
This litigation was the last remaining producer claim in Columbia Transmission's
bankruptcy proceeding. During the first quarter of 1999, Columbia Transmission
reached a settlement with New Bremen. The improvement to Columbia's first
quarter 1999 consolidated net income was $20.6 million. The settlement was
approved by the Bankruptcy Court on April 12, 1999, and on April 26, 1999,
Columbia Transmission distributed the producer holdback amounts in accordance
with its Plan of Reorganization and the New Bremen settlement.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information required by this item is in Item 7 beginning on page 18.
38
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index Page
- ----------------------------------------------------------------------------------
Report of Independent Public Accountants ................................ 40
Statements of Consolidated Income ...................................... 41
Consolidated Balance Sheets ............................................. 42
Statements of Consolidated Cash Flows ................................... 44
Statements of Consolidated Common Stock Equity .......................... 45
Notes of Consolidated Financial Statements .............................. 46
Schedule V - Valuation and Qualifying Accounts .......................... 71
- ----------------------------------------------------------------------------------
39
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Columbia Energy Group.:
We have audited the accompanying consolidated balance sheets of Columbia Energy
Group (a Delaware corporation, the "Corporation") and subsidiaries as of
December 31, 1999 and 1998, and the related statements of consolidated income,
cash flows and common stock equity for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Corporation's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Corporation and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedule listed in the
Index to Item 8, Financial Statements and Supplementary Data, is presented for
purposes of complying with the Securities and Exchange Commission's rules and is
not part of the basic consolidated financial statements. This schedule has been
subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
New York, New York
January 25, 2000
40
41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
STATEMENTS OF CONSOLIDATED INCOME
Columbia Energy Group and Subsidiaries
Year Ended December 31, (in millions,
except per share amounts) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
NET REVENUES
Energy sales $ 2,085.5 $ 1,725.5 $ 2,215.7
Less: Products purchased 1,194.4 766.1 1,117.2
- ------------------------------------------------------------------------------------------------------------------------
Gross Margin 891.1 959.4 1,098.5
Transportation 706.3 577.2 532.4
Production gas sales 120.2 111.8 98.4
Other 277.2 213.5 167.6
- ------------------------------------------------------------------------------------------------------------------------
Total Net Revenues 1,994.8 1,861.9 1,896.9
- ------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 937.5 829.2 934.0
Settlement of gas supply charges (31.7) -- --
Depreciation and depletion 229.0 231.9 219.9
Other taxes 211.6 219.5 221.5
- ------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,346.4 1,280.6 1,375.4
- ------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 648.4 581.3 521.5
- ------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
Interest income and other, net (Note 15) 29.2 12.3 39.4
Interest expense and related charges (Note 16) (164.4) (144.5) (157.4)
- ------------------------------------------------------------------------------------------------------------------------
Total Other Income (Deductions) (135.2) (132.2) (118.0)
- ------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 513.2 449.1 403.5
Income Taxes (Note 8) 158.2 148.8 123.2
- ------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS 355.0 300.3 280.3
- ------------------------------------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS - NET OF TAXES
(Loss) from operations (80.0) (31.1) (7.0)
Estimated (loss) on disposal (25.8) -- --
- ------------------------------------------------------------------------------------------------------------------------
(Loss) from Discontinued Operations - net of taxes (105.8) (31.1) (7.0)
- ------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 249.2 $ 269.2 $ 273.3
- ------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE
Continuing operations $ 4.31 $ 3.60 $ 3.37
(Loss) from discontinued operations (0.97) (0.37) (0.08)
Estimated (loss) on disposal (0.31) -- --
- ------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 3.03 $ 3.23 $ 3.29
- ------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE
Continuing operations $ 4.29 $ 3.58 $ 3.35
(Loss) from discontinued operations (0.97) (0.37) (0.08)
Estimated (loss) on disposal (0.31) -- --
- ------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE $ 3.01 $ 3.21 $ 3.27
- ------------------------------------------------------------------------------------------------------------------------
DIVIDENDS PAID PER SHARE* $ 0.875 $ 0.77 $ 0.60
- ------------------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (thousands)* 82,210 83,382 83,100
DILUTED AVERAGE COMMON SHARES (thousands)* 82,709 83,748 83,594
- ------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
* All per share amounts, average common shares outstanding and diluted average
common shares have been restated to reflect a three-for-two common stock
split, in the form of a stock dividend, effective June 15, 1998. See Note 3A
of Notes to Consolidated Financial Statements.
41
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CONSOLIDATED BALANCE SHEETS
Columbia Energy Group and Subsidiaries
ASSETS as of December 31, (in millions) 1999 1998
- ----------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant, at original cost $ 8,150.6 $ 7,673.9
Accumulated depreciation (3,708.8) (3,588.7)
- ----------------------------------------------------------------------------------------------
Net Gas Utility and Other Plant 4,441.8 4,085.2
- ----------------------------------------------------------------------------------------------
Gas and oil producing properties, full cost method
United States cost center 823.5 714.1
Canadian cost center 12.6 5.0
Accumulated depletion (251.6) (225.4)
- ----------------------------------------------------------------------------------------------
Net Gas and Oil Producing Properties 584.5 493.7
- ----------------------------------------------------------------------------------------------
Net Property, Plant and Equipment 5,026.3 4,578.9
- ----------------------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
Unconsolidated affiliates 67.6 81.6
Net assets of discontinued operations (9.7) 235.8
Other 61.6 40.5
- ----------------------------------------------------------------------------------------------
Total Investments and Other Assets 119.5 357.9
- ----------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 62.6 22.9
Accounts receivable
Customer (less allowance for doubtful accounts
of $15.8 and $13.9, respectively) 465.4 344.5
Other 87.0 55.2
Gas inventory 144.9 186.0
Other inventories - at average cost 71.1 26.8
Prepayments 74.3 65.6
Regulatory assets 52.7 59.5
Underrecovered gas costs 40.5 24.5
Deferred property taxes 79.8 80.0
Exchange gas receivable 275.4 197.5
Other 39.5 62.8
- ----------------------------------------------------------------------------------------------
Total Current Assets 1,393.2 1,125.3
- ----------------------------------------------------------------------------------------------
REGULATORY ASSETS 358.1 391.4
DEFERRED CHARGES 198.8 77.9
- ----------------------------------------------------------------------------------------------
TOTAL ASSETS $ 7,095.9 $ 6,531.4
- ----------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
42
43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CAPITALIZATION AND LIABILITIES as of
December 31, (in millions) 1999 1998
- --------------------------------------------------------------------------------------------
COMMON STOCK EQUITY
Common stock, par value $.01 per share - issued
83,786,942 and 83,511,878 shares, respectively $ 0.8 $ 835.1
Additional paid in capital 1,611.6 761.8
Retained earnings 586.9 409.5
Unearned employee compensation (0.6) (0.9)
Accumulated Other Comprehensive Income:
Foreign currency translation adjustment 0.3 (0.2)
Treasury stock (135.0) --
- --------------------------------------------------------------------------------------------
Total Common Stock Equity 2,064.0 2,005.3
LONG-TERM DEBT (Note 11) 1,639.7 2,003.1
- --------------------------------------------------------------------------------------------
Total Capitalization 3,703.7 4,008.4
- --------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Short-term debt (Note 12) 465.5 144.8
Current maturities of long-term debt 311.3 0.4
Accounts and drafts payable 267.5 180.9
Accrued taxes 199.0 238.3
Accrued interest 32.5 17.3
Estimated rate refunds 21.4 59.2
Supplier obligations -- 72.4
Overrecovered gas costs 14.6 34.3
Transportation and exchange gas payable 297.5 139.2
Other 406.7 367.8
- --------------------------------------------------------------------------------------------
Total Current Liabilities 2,016.0 1,254.6
- --------------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Deferred income taxes - noncurrent 674.1 655.0
Investment tax credits 32.6 34.1
Postretirement benefits other than pensions 96.4 103.7
Regulatory liabilities 36.4 44.0
Deferred revenue 177.4 191.4
Other 359.3 240.2
- --------------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits 1,376.2 1,268.4
- --------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 14) -- --
- --------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $7,095.9 $6,531.4
- --------------------------------------------------------------------------------------------
43
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
Columbia Energy Group and Subsidiaries
Year Ended December 31, (in millions) 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 249.2 $ 269.2 $ 273.3
Adjustments to reconcile net income to net
cash from continuing operations:
Loss from discontinued operations 80.0 31.1 7.0
Loss on disposal 25.8 -- --
Depreciation and depletion 229.0 231.9 219.9
Deferred income taxes 45.1 38.6 28.9
Earnings from equity investment, net of distributions 23.0 (8.5) 2.4
Other - net 53.5 135.0 26.8
- -----------------------------------------------------------------------------------------------------------
705.6 697.3 558.3
Changes in components of working capital:
Accounts receivable, net of sale (191.7) 43.8 69.7
Sale of accounts receivable 81.1 -- --
Gas inventory 41.1 40.8 11.0
Prepayments (8.7) (6.0) (4.5)
Accounts payable 98.2 7.4 (8.6)
Accrued taxes 72.0 50.9 (25.2)
Accrued interest 15.2 (12.1) (1.2)
Estimated rate refunds (37.8) (9.2) (45.6)
Estimated supplier obligations (40.6) (1.5) (41.2)
Under/Overrecovered gas costs (35.7) (33.4) 147.9
Exchange gas receivable/payable 80.4 60.1 (85.3)
Other working capital 46.7 7.6 (0.8)
- -----------------------------------------------------------------------------------------------------------
Net Cash From Continuing Operations 825.8 845.7 574.5
Net Cash From Discontinued Operations 5.8 (138.1) (70.4)
- -----------------------------------------------------------------------------------------------------------
Net Cash From Operating Activities 831.6 707.6 504.1
- -----------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
Capital expenditures (462.3) (455.2) (415.7)
Acquisitions and other investments - net (368.2) (12.5) (108.5)
- -----------------------------------------------------------------------------------------------------------
Net Investment Activities (830.5) (467.7) (524.2)
- -----------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Retirement of long-term debt (52.5) (0.9) (0.6)
Dividends paid (71.8) (63.9) (49.9)
Issuance of common stock 15.5 10.5 11.7
Issuance (repayment) of short-term debt 320.7 (182.4) 77.1
Purchase of treasury stock (135.0) -- --
Other financing activities (38.3) (8.8) (39.3)
- -----------------------------------------------------------------------------------------------------------
Net Financing Activities 38.6 (245.5) (1.0)
- -----------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and temporary cash investments 39.7 (5.6) (21.1)
Cash and temporary cash investments at beginning of year 22.9 28.5 49.6
- -----------------------------------------------------------------------------------------------------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 62.6 $ 22.9 $ 28.5
- -----------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest $ 149.3 $ 147.0 $ 145.4
Cash paid for income taxes (net of refunds) $ 61.7 $ 38.3 $ 90.7
- -----------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
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45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
Columbia Energy Group and Subsidiaries
Common Stock*
---------------------------------------------
Shares Additional
Outstanding ** Par Treasury Paid In Retained
(in millions, except for share amounts) (Thousands) Value Stock Capital Earnings
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 55,264 $ 552.6 $ -- $ 743.2 $ 259.3
Net income 273.3
Cash dividends:
Common stock (49.9)
Common stock issued:
Long-term incentive plan 232 2.3 11.0
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 55,496 554.9 -- 754.2 482.7
Comprehensive income:
Net income 269.2
Foreign currency translation adjustment
Comprehensive income
Cash dividends:
Common stock (63.9)
Common stock issued:
Long-term incentive plan 231 2.3 7.6
Three-for-two stock split 27,785 277.9 (278.5)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 83,512 835.1 761.8 409.5
Comprehensive income:
Net income 249.2
Foreign currency translation adjustment
Comprehensive income
Cash dividends:
Common stock (71.8)
Reduction in par from $10 to $.01 per share (834.3) 834.3
Common stock issued:
Long-term incentive plan 275 15.5
Purchase of treasury stock (2,479) (135.0)
- ---------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1999 81,308 $ 0.8 $ (135.0) $1,611.6 $ 586.9
- ---------------------------------------------------------------------------------------------------------------------------------
Accumulated
Unearned Other
Employee Comprehensive
(in millions, except for share amounts) Compensation Income Total
- ---------------------------------------------------------------------------------------------
Balance at December 31, 1996 $ (1.5) $ -- $ 1,553.6
Net income 273.3
Cash dividends:
Common stock (49.9)
Common stock issued:
Long-term incentive plan 0.4 13.7
- ---------------------------------------------------------------------------------------------
Balance at December 31, 1997 (1.1) -- 1,790.7
Comprehensive income:
Net income
Foreign currency translation adjustment (0.2)
Comprehensive income 269.0
Cash dividends:
Common stock (63.9)
Common stock issued:
Long-term incentive plan 0.2 10.1
Three-for-two stock split (0.6)
- ---------------------------------------------------------------------------------------------
Balance at December 31, 1998 (0.9) (0.2) 2,005.3
Comprehensive income:
Net income
Foreign currency translation adjustment 0.5
Comprehensive income 249.7
Cash dividends:
Common stock (71.8)
Reduction in par from $10 to $.01 per share --
Common stock issued: --
Long-term incentive plan 0.3 15.8
Purchase of treasury stock (135.0)
- ---------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1999 $ (0.6) $ 0.3 $ 2,064.0
- ---------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
* Effective May 19, 1999, the authorized number of shares of common stock
increased from 100 million to 200 million and the par value of common stock
decreased from $10 to $.01 per share.
** The common shares outstanding at December 31, 1997 and 1996 do not reflect
the three-for-two common stock split, in the form of a stock dividend,
effective June 15, 1998.
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46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
the accounts of the Columbia Energy Group (Columbia) and all subsidiaries. All
intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to the 1998 and 1997 financial statements to
conform to the 1999 presentation.
B. CASH AND CASH EQUIVALENTS. Columbia considers all highly liquid short-term
investments to be cash equivalents.
C. DILUTED AVERAGE COMMON SHARES COMPUTATION. Financial Accounting Standards
Board Statement of Financial Accounting Standards No. 128, "Earnings Per Share"
(SFAS No. 128), requires dual presentation of basic and diluted earnings per
share (EPS). Basic EPS includes no dilution and is computed by dividing income
available to common stockholders by the weighted-average number of common shares
outstanding for the period. Diluted EPS reflects the potential dilutive effect
of stock options.
The numerator in calculating both basic and diluted earnings per share for each
year is reported net income. The computation of diluted average common shares
follows:
Diluted Average Common Shares Computation 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Denominator (thousands)
Basic average common shares outstanding 82,210 83,382 83,100
Dilutive potential common shares - options 499 366 494
- ---------------------------------------------------------------------------------------------------------------------
DILUTED AVERAGE COMMON SHARES 82,709 83,748 83,594
- ---------------------------------------------------------------------------------------------------------------------
D. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71), provides that rate-regulated public utilities account
for and report assets and liabilities consistent with the economic effect of the
way in which regulators establish rates, if the rates established are designed
to recover the costs of providing the regulated service and if the competitive
environment makes it probable that such rates can be charged and collected.
Columbia's transmission and gas distribution subsidiaries follow the accounting
and reporting requirements of SFAS No. 71. Certain expenses and credits subject
to utility regulation or rate determination normally reflected in income are
deferred on the balance sheet and are recognized in income as the related
amounts are included in service rates and recovered from or refunded to
customers.
In Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) 1999 rate agreement (See Note
2), the Public Utilities Commission of Ohio (PUCO) authorized Columbia of Ohio
to revise its depreciation accrual rates for the period January 1, 1999 through
December 31, 2004. The revised depreciation rates are lower than those which
would have been utilized if Columbia of Ohio were not subject to regulation. The
amount of depreciation that would have been recorded for 1999 had Columbia of
Ohio not been subject to rate regulation is $31.8 million, an $18.8 million
increase over the $13 million reflected in rates. Accordingly, a regulatory
asset has been established in the amount of $18.8 million at December 31, 1999.
46
47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Information for assets and liabilities subject to utility regulation and rate
determination are as follows:
TRANSMISSION DISTRIBUTION
SUBSIDIARIES SUBSIDIARIES
----------------------------------------------------------
At December 31, ($ in millions) 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
ASSETS
- ----------------------------------------------------------------------------------------------------------------------
Environmental costs 95.5 136.7 5.0 6.2
Postemployment and postretirement benefits costs 56.2 60.3 105.5 113.6
Percent of income plan receivables -- -- 8.0 15.3
Retirement income plan costs 12.7 15.2 14.9 16.6
Regulatory effects of accounting for income taxes -- -- 64.4 55.8
Post in-service carrying charges -- -- 16.0 16.9
Underrecovered gas costs -- -- 40.5 24.5
Depreciation -- -- 18.8 --
Other 7.9 8.1 5.9 6.2
- ----------------------------------------------------------------------------------------------------------------------
TOTAL REGULATORY ASSETS 172.3 220.3 279.0 255.1
- ----------------------------------------------------------------------------------------------------------------------
LIABILITIES
Rate refunds and reserves 5.3 49.1 16.1 10.1
Overrecovered gas costs -- -- 14.6 34.3
Regulatory effects of accounting for income taxes 15.2 17.3 21.0 21.9
Other 23.1 22.7 2.0 6.6
- ----------------------------------------------------------------------------------------------------------------------
TOTAL REGULATORY LIABILITIES 43.6 89.1 53.7 72.9
- ----------------------------------------------------------------------------------------------------------------------
Regulatory assets of approximately $359.7 million are not presently included in
the rate base and consequently are not earning a return on investment. These
regulatory assets are being recovered through cost of service. The remaining
recovery periods generally range from one to fifteen years. Regulatory assets of
approximately $35.1 million require specific rate action. All regulatory assets
are probable of recovery.
E. GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property, plant and
equipment (principally utility plant) are stated at original cost. The cost of
gas utility and other plant of the rate-regulated subsidiaries includes an
allowance for funds used during construction (AFUDC). Property, plant and
equipment of other subsidiaries includes interest during construction (IDC). The
1999 before-tax rates for AFUDC and IDC were 5.91% and 6.94%, respectively. The
1998 and 1997 before-tax rates for AFUDC were 7.43% and 7.09%, respectively, and
for IDC were 6.96% and 7.05%, respectively.
Improvements and replacements of retirement units are capitalized at cost. When
units of property are retired, the accumulated provision for depreciation is
charged with the cost of the units and the cost of removal, net of salvage.
Maintenance, repairs and minor replacements of property are charged to expense.
Columbia's subsidiaries provide for annual depreciation on a composite
straight-line basis. The average annual depreciation rate for the transmission
subsidiaries' property was 2.4% in 1999 and 2.4% in 1998 and 2.5% in 1997. The
average annual depreciation rate for the distribution subsidiaries' property was
2.8% in 1999 and 3.1% in 1998 and 3.2% in 1997.
F. GAS AND OIL PRODUCING PROPERTIES. Columbia's subsidiaries engaged in
exploring for and developing gas and oil reserves follow the full cost method of
accounting. Under this method of accounting, all productive and nonproductive
costs directly identified with acquisition, exploration and development
activities including certain payroll and other internal costs are capitalized.
Depletion is based upon the ratio of current year revenues to expected total
revenues, utilizing current prices, over the life of production. If costs exceed
the sum of the estimated present value of the net future gas and oil revenues
and the lower of cost or estimated value of unproved properties, an amount
equivalent to the excess is charged to current depletion expense. Gains or
losses on the sale or other disposition of gas and oil properties are normally
recorded as adjustments to capitalized costs, except in the case of a sale of a
significant amount of properties, which would be reflected in the income
statement.
G. INTANGIBLE ASSETS. Intangible assets are recorded at original cost and are
amortized on a straight line basis. Goodwill represents the excess of the
purchase price over assets acquired and is being amortized over 40 years.
47
48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Customer lists are being amortized over periods of 10 to 20 years. Intangible
assets are immaterial to the consolidated financial statements.
H. ACCOUNTING FOR RISK MANAGEMENT ACTIVITIES. Subsidiaries in Columbia's
exploration and production, marketing and propane operations are exposed to
market risk due primarily to fluctuations in commodity prices. In order to help
minimize this risk, Columbia has adopted a policy that provides for the use of
commodity derivative instruments to help ensure stable cash flow, favorable
prices and margins. In accordance with Statement of Financial Accounting
Standards No. 80, "Accounting for Futures Contracts," a futures contract
qualifies as a hedge if the commodity to be hedged is exposed to price risk and
the futures contract reduces that exposure and is designated as a hedge. The
hedging objectives include assurance of stable and known cash flows, fixing
favorable prices and margins when they become available.
Columbia's exploration and production company and propane operations utilize
futures and options as well as commodity price swaps and basis swaps. Futures
help manage commodity price risk by fixing prices for future production volumes
as well as protecting the value and margins of propane and petroleum products
inventories. The options provide a price floor for future production volumes and
the opportunity to benefit from any increases in prices. Swaps are negotiated
and executed over-the-counter and are structured to provide the same risk
protection as futures and options. Basis swaps are used to manage risk by fixing
the basis or differential that exists between a delivery location index and the
commodity futures prices.
Premiums paid for option agreements are included as current assets in the
consolidated balance sheets until they are exercised or expire. Margin
requirements for natural gas and propane and petroleum products futures are also
recorded as current assets. Unrealized gains and losses on all futures contracts
are deferred on the consolidated balance sheets as either current assets or
other deferred credits. Realized gains and losses from the settlement of natural
gas futures, options and swaps are included in revenues or products purchased as
appropriate, concurrent with the associated physical transaction. Realized gains
and losses from the settlement of propane and petroleum products futures
contracts are included in products purchased. The cash flows from commodity
hedging are included in operating activities in the consolidated statements of
cash flows.
Columbia and its subsidiaries are exposed to credit losses in the event of
nonperformance by the counterparties to its various financial contracts.
Management has evaluated such risk and believes that overall business risk is
significantly reduced as these financial contracts are primarily with major
investment grade financial institutions or their affiliates.
Columbia utilizes fixed-to-floating interest rate swap agreements to modify the
interest characteristics of a portion of its outstanding long-term debt. The
differentials between amounts received and paid under the agreements are
recorded as adjustments to interest expense.
I. GAS INVENTORY. The distribution subsidiaries' gas inventory is carried at
cost on a last-in, first-out (LIFO) basis. The excess of replacement cost of gas
inventory at December 31, 1999, over the carrying value is approximately $37.9
million. Liquidation of LIFO layers related to gas delivered by the distribution
subsidiaries does not affect income since the effect is passed through to
customers as part of purchased gas adjustment tariffs.
J. INCOME TAXES AND INVESTMENT TAX CREDITS. Columbia and its subsidiaries record
income taxes to recognize full interperiod tax allocations. Under the liability
method of income tax accounting, deferred income taxes are recognized for the
tax consequences of temporary differences by applying enacted statutory tax
rates applicable to future years to differences between the financial statement
carrying amounts and the tax basis of existing assets and liabilities.
Previously recorded investment tax credits of the regulated subsidiaries were
deferred and are being amortized over the life of the related properties to
conform with regulatory policy.
K. ESTIMATED RATE REFUNDS. Certain rate-regulated subsidiaries collect revenues
subject to refund pending final determination in rate proceedings. In connection
with such revenues, estimated rate refund liabilities are recorded which reflect
management's current judgment of the ultimate outcome of the proceedings. No
provisions are made when, in the opinion of management, the facts and
circumstances preclude a reasonable estimate of the outcome.
48
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
L. DEFERRED GAS PURCHASE COSTS. Columbia's gas distribution subsidiaries defer
differences between gas purchase costs and the recovery of such costs in
revenues, and adjust future billings for such deferrals on a basis consistent
with applicable tariff provisions.
M. REVENUE RECOGNITION. Columbia's gas distribution subsidiaries bill customers
on a monthly cycle billing basis. Revenues are recorded on the accrual basis and
include an estimate for gas delivered but unbilled at the end of each accounting
period.
N. ENVIRONMENTAL EXPENDITURES. Columbia accrues for costs associated with
environmental remediation obligations when such costs are probable and can be
reasonably estimated, regardless of when expenditures are made. The undiscounted
estimated future expenditures are based on currently enacted laws and
regulations, existing technology and, when possible, site-specific costs. The
reserve is adjusted as further information is developed or circumstances change.
Rate-regulated subsidiaries applying SFAS No. 71 establish a regulatory asset on
the balance sheet to the extent that future recovery of environmental
remediation costs is probable through the regulatory process.
O. ACCOUNTS RECEIVABLE SALES PROGRAM. Columbia enters into agreements with third
parties to sell certain accounts receivable without recourse. These sales are
reflected as reductions of accounts receivable in the accompanying consolidated
balance sheets and as operating cash flows in the accompanying consolidated
statements of cash flows. The costs of this program, which are based upon the
purchasers' level of investment and borrowing costs, will be charged to interest
expense and related charges in the accompanying consolidated statements of
income.
P. USE OF ESTIMATES. The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Q. STOCK OPTIONS AND AWARDS. Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation" (SFAS No. 123), encourages, but
does not require, entities to adopt the fair value method of accounting for
stock-based compensation plans. This statement requires the value of the option
at the date of grant be amortized over the vesting period of the option.
Columbia continues to apply Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB Opinion No. 25).
For stock appreciation rights, compensation expense is recognized on the
aggregate difference between the market price of Columbia's stock and the option
price. Restricted stock awards are recorded as deferred compensation in the
consolidated balance sheets at the date of grant. Compensation expense related
to restricted stock awards is recognized ratably over the vesting period.
Compensation expense related to contingent stock awards is recognized over the
vesting period. Columbia sets the grant price of the options at the market price
of the stock on the grant date. In accordance with APB Opinion No. 25, expense
related to stock options is measured by the difference between the grant price
and Columbia's stock price on the measurement date (grant date). Since the
difference between the grant price and Columbia's stock price on the measurement
date is de minimis, no compensation expense is recognized. When stock options
are exercised, common stock is credited for the par value of shares issued and
additional paid in capital is credited with the consideration in excess of par.
2. REGULATORY MATTERS
In 1993, the FERC directed Columbia Gulf to show cause as to why it had not
sought FERC abandonment authorization to reduce capacity on its mainline
facility. In an August 8, 1997 order, the FERC approved a settlement between
Columbia Gulf and FERC's enforcement staff requiring Columbia Gulf to conduct a
30-day open season on additional firm mainline capacity up to its certificated
design. Although certain of Columbia Gulf's customers challenged the terms of
the settlement, Columbia Gulf concluded the open season on December 15, 1997
which resulted in requests for capacity that exceeded the capacity specified in
Columbia Gulf's FERC certificate. In orders issued in December 1998 and 1999,
the FERC has rejected challenges to the settlement and denied rehearing. In its
order issued December 22, 1999, the FERC affirmed the validity of the 1997 open
season but indicated that an additional open season in compliance with the
settlement will be necessary. In early February 2000, several appeals of the
FERC's orders in this proceeding were filed.
Columbia Gulf filed an application with the FERC on June 5, 1998, for authority
to increase the maximum certificated capacity of its mainline facilities. The
expansion project, referred to as Mainline '99, will increase Columbia Gulf's
certificated capacity to nearly 2.2 Bcf/day, by replacing certain compressor
units and increasing the horsepower capacity of other compressor stations.
Various shippers contracted for the additional service through an
49
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
open bidding process held in late 1997 and early 1998. On February 10, 1999, the
FERC issued an order approving Columbia Gulf's June 1998 filing and construction
commenced on March 3, 1999. On March 12, 1999, requests for rehearing of the
FERC order were filed by three parties. On January 31, 2000, the FERC issued an
order denying the requests for rehearing and validating the open season held in
conjunction with Mainline '99. The FERC said it had previously addressed the
validity of the open season in the show cause proceeding discussed above.
Columbia Transmission's rate case settlement, approved by the FERC in April
1997, provided for a hearing in the fall of 1998 to address environmental cost
recovery that was excluded from the settlement. As a result of settlement
discussions, the active parties reached an agreement on the overall components
of an environmental settlement. The comprehensive agreement includes such major
components as Columbia Transmission's total allowed recovery of environmental
remediation program costs and the disposition of any proceeds received by
Columbia Transmission from insurance carriers and others. Columbia Transmission
filed the stipulation and agreement with the FERC on April 5, 1999 and on
September 15, 1999, the FERC approved the settlement. No requests for rehearing
were filed. The approval of the settlement did not have a material impact on
Columbia's consolidated financial results.
The transmission and storage subsidiaries are in confidential and informal
discussions with the staff of the FERC (Staff) concerning the scope of
authorization for certain past transactions under the relevant filed tariffs.
The transmission and storage subsidiaries have initiated these discussions with
the FERC. These subsidiaries provided information concerning these transactions
to the Staff pursuant to an informal non-public inquiry being conducted by the
Staff. Because management does not yet know the position Staff will take,
management is unable to reasonably estimate the amount that will have to be paid
pursuant to reimbursement or the other remedies.
The distribution subsidiaries (Distribution) continue to pursue initiatives that
give retail customers the opportunity to purchase natural gas directly from
marketers and to use Distribution's facilities for transportation services.
These opportunities are being pursued through regulatory initiatives in all of
its jurisdictions, which resulted in transportation programs being initiated in
all five of its service areas. Once fully implemented, these programs would
reduce Distribution's merchant function and provide all customer classes with
the opportunity to obtain gas supplies from alternative merchants. As these
programs expand to all customers, regulations will have to be implemented to
provide for the recovery of transition capacity costs and other transition costs
incurred by a utility serving as the supplier of last resort if the marketing
company cannot supply the gas. Transition capacity costs are created as
customers enroll in these programs and purchase their gas from other suppliers,
leaving Distribution with pipeline capacity it has contracted for but no longer
needs. The state commissions in Distribution's five jurisdictions are at various
stages in addressing these issues and other transition considerations.
Distribution is currently recovering, or has the opportunity to recover, the
costs resulting from the unbundling of its services and believes that most of
such future costs and costs resulting from being the supplier of last resort
will be mitigated or recovered.
On October 25, 1999, Columbia of Ohio and a group comprising diverse interested
parties, also known as the Collaborative, filed with the Public Utilities
Commission of Ohio (PUCO) a third amendment to its 1994 rate case. The filing,
which was approved by the PUCO on December 2, 1999, extends Columbia of Ohio's
CHOICE(SM) program through October 31, 2004, freezes base rates through October
31, 2004 and resolves the issue of transition capacity costs. Under the
agreement, Columbia of Ohio would assume total financial risk for mitigation of
transition capacity costs at no additional cost to customers. Among other items,
Columbia of Ohio would have the opportunity to utilize non-traditional revenue
sources as a means of offsetting the costs. The agreement also requires Columbia
of Ohio to submit a proposal addressing issues related to the merchant function,
obligation to serve, and provider of last resort by April 1, 2000.
3. COMMON STOCK EQUITY
A. STOCK SPLIT EFFECTED IN THE FORM OF A STOCK DIVIDEND. On May 20, 1998,
Columbia's Board of Directors (Board of Directors or Columbia's Board) approved
a three-for-two common stock split, effected in the form of a 50% stock dividend
(stock split), on June 15, 1998, payable to shareholders of record as of June 1,
1998. In connection with the stock split, 27.8 million shares were issued on
June 15, 1998, and $277.9 million was transferred to common stock from retained
earnings. The value of fractional shares resulting from the stock split was
determined at the closing price on June 1, 1998, and $0.6 million was paid in
cash to the shareholders for fractional-share interests. All references in the
financial statements and notes to the number of common shares outstanding and
per-share amounts, except where otherwise noted, reflect the retroactive effect
of the stock split.
B. TREASURY STOCK. In February 1999, Columbia's Board authorized the purchase of
up to $100 million of its common stock, through February 29, 2000, in the open
market or otherwise. In July 1999, Columbia's Board authorized the purchase of
an additional $400 million of common stock through July 14, 2000. In October
1999, this
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
program was suspended pending consideration of strategic alternatives (see Note
5). There can be no assurance as to when the share repurchase program will
recommence or if it will resume. If the program were to resume, the timing and
terms of additional purchases, and the number of shares actually purchased, will
be determined by management based on several factors including market
conditions. Purchased shares are held in treasury at cost and are available for
general corporate purposes or resale at a future date, or may be retired. As of
December 31, 1999, Columbia had purchased 2,478,500 common shares at a cost of
$135 million.
C. COMMON STOCK - AMENDMENTS. At Columbia's Annual Meeting of Shareholders held
on May 19, 1999, the shareholders voted to approve an amendment of Columbia's
Restated Certificate of Incorporation to increase the authorized number of
shares of common stock from 100 million to 200 million and decrease the par
value of common stock from $10 to $.01 per share. This change resulted in a
transfer during the second quarter of 1999 of $834.3 million from Common Stock
to Additional Paid In Capital.
4. DISCONTINUED OPERATIONS
As a result of a strategic assessment commenced in early 1999, on August 30,
1999, Columbia Energy Services announced that it decided to sell its Wholesale
and Trading operations. On December 30, 1999, Columbia Energy Services completed
the sale of these operations to a wholly-owned subsidiary of Enron Corp.
(Enron). The proceeds from the sale were $38.3 million, which is subject to post
closing adjustments in the first quarter of 2000.
In November 1999, after analysis from such ongoing strategic assessment, it was
determined that Columbia Energy Services should focus on its Mass Markets
business and exit the Major Accounts business that provides energy services and
products to industrial and large commercial customers.
In accordance with generally accepted accounting principles, the Columbia Energy
Services Wholesale and Trading operations and Major Accounts business are
reported as discontinued operations, and therefore the financial statements for
prior periods have been reclassified accordingly. The revenues from discontinued
operations were $5,371.6 million, $4,684.9 million and $2,217.6 million for the
years ended 1999, 1998 and 1997, respectively. The loss from discontinued
operations - net of taxes were $105.8 million, $31.1 million and $7 million for
the years ended 1999, 1998 and 1997, respectively. The estimated loss on
disposal of discontinued operations is $25.8 million, net of income tax benefits
of $13.7 million. The net assets of the discontinued operations are as follows:
At December 31, ($ in millions) 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
NET ASSETS OF DISCONTINUED OPERATIONS
Accounts receivable, net 317.7 645.3
Other assets 18.3 158.8
Accounts payable (317.0) (566.7)
Other liabilities (28.7) (1.6)
- ---------------------------------------------------------------------------------------------------------------------
NET ASSETS OF DISCONTINUED OPERATIONS (9.7) 235.8
- ---------------------------------------------------------------------------------------------------------------------
5. MERGER AGREEMENT
On February 28, 2000, Columbia announced that it had entered into an Agreement
and Plan of Merger, dated as of February 27, 2000 (Merger Agreement), between
Columbia and NiSource, Inc., an Indiana corporation (NiSource). The Board of
Directors of Columbia determined to enter into the Merger Agreement after a
comprehensive evaluation of strategic alternatives that might generate value
greater than that which Columbia's business plan could create.
The terms of the Merger Agreement provide that NiSource will organize a new
company which shall serve as the holding company for both Columbia and NiSource
after the completion of the transaction. Pursuant to the terms of the Merger
Agreement, each of Columbia and NiSource will be merged into newly formed
special purpose subsidiaries of the new holding company, and each will become a
wholly owned subsidiary of the new holding company.
Subject to the terms and conditions of the Merger Agreement, upon completion of
the transaction, Columbia's shareholders will receive, for each share of
Columbia common stock, $70 in cash and a $2.60 face value SAILS(SM) (a unit
consisting of a zero coupon debt security with a forward equity contract).
Columbia's shareholders also have the option to elect to receive (in lieu of
cash and SAILS(SM)) shares in the new holding company in a tax-free exchange,
for up to 30% of the outstanding shares of Columbia common stock. Pursuant to
the stock election option, each Columbia share will be exchanged for up to $74
in new holding company stock, subject to a collar such that, if the average
closing price of NiSource shares during the 30 days prior to the closing of the
transaction is greater than $16.50, Columbia shareholders will receive shares of
the new holding company valued at $74 for each share of Columbia stock, and if
the average closing price of NiSource shares during the 30 days prior to closing
of the transaction is $16.50 or below, Columbia shareholders will receive 4.4848
shares of new holding company stock for each Columbia share. Upon completion of
the transaction, NiSource shareholders will receive one share of holding company
stock for each share of NiSource common stock that they own.
The Merger is conditioned upon, among other things, the approvals of the
shareholders of both companies and various regulatory commissions. However, if
the NiSource shareholder approval is not obtained, the transaction will
automatically be restructured so that, instead of each of NiSource and Columbia
becoming wholly-owned subsidiaries of the new holding company, Columbia will
become a wholly owned subsidiary of NiSource, and Columbia shareholders will
receive $70 in cash and a $3.02 face value SAILS(SM) unit of NiSource with no
option for Columbia shareholders to elect new holding company stock.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
6. RISK MANAGEMENT ACTIVITIES
Subsidiaries in Columbia's exploration and production and energy marketing
segments are exposed to market risk due primarily to fluctuations in commodity
prices. In order to help minimize this risk, Columbia has adopted a policy that
provides for commodity hedging activities to help ensure stable cash flow,
favorable prices and margins. Financial instruments authorized for use by
Columbia for hedging include futures, swaps and options.
Columbia's energy marketing subsidiary utilized financial instruments to help
assure adequate margins for its Mass Markets business on the purchase and resale
of natural gas and electric power. At December 31, 1999, there were 25 open
contracts to purchase natural gas maturing from January 2000 to December 2008,
representing a notional quantity amounting to 128 Bcf. Also at December 31,
1999, there were five future equivalent contracts to purchase electric power
maturing from January 2000 to May 2000 representing a notional quantity
amounting to 85 Gigawatts hours. Unrealized gains or losses deferred on the
consolidated balance sheets, at December 31, 1999, with respect to these open
contracts were immaterial. During the year ended December 31, 1999, the gains or
losses realized on contracts settled were immaterial. Based on a 95% confidence
interval and a one-day time horizon, the value-at-risk for Columbia's energy
marketing operations was insignificant for both 1999 and 1998. At December 31,
1998, there were 27 open contracts to purchase natural gas maturing from January
1999 to December 2008 representing a notional quantity amounting to 115 Bcf.
Unrealized gains or losses deferred on the consolidated balance sheets, at
December 31, 1998, with respect to these contracts were immaterial. During the
year ended December 31, 1998, the gains or losses realized on contracts settled
were immaterial.
Columbia's exploration and production subsidiary hedged a portion of its gas
production that was subject to price volatility. At December 31, 1999, there
were 4,214 open contracts representing a notional quantity amounting to 6.6 Bcf
of commodity contracts and 30.4 Bcf of basis contracts for natural gas
production through February and October 2000, respectively at a combined average
price of $3.61 per Mcf. A total of $6.1 million of unrealized gains have been
deferred on the consolidated balance sheets, at December 31, 1999, with respect
to these open contracts. During the year ended December 31, 1999, $0.5 million
of losses were realized on contracts settled. At December 31, 1998, there were
6,896 open contracts representing a notional quantity amounting to 16.4 Bcf of
commodity contracts and 44.1 Bcf of basis contracts for natural gas production
through October 1999 at a combined average price of $2.79 per Mcf. A total of
$9.1 million of unrealized gains were deferred on the consolidated balance
sheets with respect to these open contracts. During the year ended December 31,
1998, $11 million of gains were realized on contracts settled.
Columbia's propane subsidiary hedges a portion of its inventory at the time of
purchase against the risk of decreasing prices. At December 31, 1999, there were
930 open contracts through March 2000 representing a notional quantity amounting
to 22.9 million gallons of petroleum products and 16.2 million gallons of
propane at an average price of $0.68 and $0.43 per gallon, respectively. The
unrealized gain deferred on the consolidated balance sheets, with respect to
these open contracts, is immaterial at December 31, 1999. During the year ended
December 31, 1999, $6.1 million of losses were realized on contracts settled. At
December 31, 1998, there were 620 open contracts through March 1999 representing
a notional quantity amounting to 26 million gallons of propane at an average
price of $0.24 per gallon. A total of $0.4 million of unrealized losses were
deferred on the consolidated balance sheets with respect to these open
contracts. During the year ended December 31, 1998, $1 million of losses were
realized on contracts settled.
52
53
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
7. NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS No. 133). This statement, as amended, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. SFAS No. 133 requires an entity to
recognize all derivatives as either assets or liabilities in the balance sheet
and measure those instruments at fair value. If certain conditions are met, a
derivative may be specifically designated as (a) a hedge of the exposure to
changes in the fair value of a recognized asset or liability or an unrecognized
firm commitment, (b) a hedge of the exposure to variable cash flows of a
forecasted transaction, or (c) a hedge of the foreign currency exposure of a net
investment in a foreign-currency-denominated forecasted transaction. The
accounting for changes in the fair value of a derivative depends on the intended
use of the derivative and resulting designation. A company may implement SFAS
No. 133 as of the beginning of any fiscal quarter, however the statement cannot
be applied retroactively. Columbia plans on adopting the statement on January 1,
2001. Columbia does not anticipate that the adoption of this statement will have
a significant impact on the consolidated financial statements.
8. INCOME TAXES
The components of income tax expense are as follows:
Year Ended December 31, ($ in millions) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
INCOME TAXES
Current
Federal 109.9 108.4 86.8
State 3.2 1.8 7.5
- ------------------------------------------------------------------------------------------------------------------------------
Total Current 113.1 110.2 94.3
- ------------------------------------------------------------------------------------------------------------------------------
Deferred
Federal 68.4 53.3 50.0
State (21.8) (13.2) (19.6)
- ------------------------------------------------------------------------------------------------------------------------------
Total Deferred 46.6 40.1 30.4
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Investment Credits (1.5) (1.5) (1.5)
- ------------------------------------------------------------------------------------------------------------------------------
Income Taxes Included in Continuing Operations 158.2 148.8 123.2
- ------------------------------------------------------------------------------------------------------------------------------
Income Taxes Related to Discontinued Operations (57.0) (17.0) (4.3)
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAXES 101.2 131.8 118.9
- ------------------------------------------------------------------------------------------------------------------------------
Total income taxes from continuing operations are different from the amount that
would be computed by applying the statutory Federal income tax rate to book
income before income tax. The major reasons for this difference are as follows:
Year Ended December 31, ($ in millions) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
Book income before income taxes 513.2 449.1 403.5
Tax expense at statutory Federal income tax rate 179.6 35.0% 157.2 35.0% 141.2 35.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal income tax benefit (12.1) (2.4) (7.4) (1.6) (7.9) (2.0)
Estimated non-deductible expenses 1.3 0.3 1.6 0.4 0.7 0.2
Effect of change in deferred taxes previously provided (3.5) (0.7) 1.5 0.3 (1.9) (0.5)
Other (7.1) (1.4) (4.1) (1.0) (8.9) (2.2)
- ------------------------------------------------------------------------------------------------------------------------------
INCOME TAXES FROM CONTINUING OPERATIONS 158.2 30.8% 148.8 33.1% 123.2 30.5%
- ------------------------------------------------------------------------------------------------------------------------------
53
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Deferred income taxes result from temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities.
The principal components of Columbia's net deferred tax liability are as
follows:
At December 31, ($ in millions) 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities
Property basis differences 733.0 688.1
Gas purchase costs 67.7 55.0
Investment in Partnerships 5.4 27.8
Other 28.1 33.1
- ---------------------------------------------------------------------------------------------------------------------
Gross Deferred Tax Liabilities 834.2 804.0
- ---------------------------------------------------------------------------------------------------------------------
Deferred tax assets
Estimated supplier obligations (2.7) (28.2)
Estimated rate refunds (12.7) (21.8)
Inventory (16.7) (22.1)
Unbilled utility revenue (20.1) (20.9)
Benefit plan accruals (15.7) (16.2)
Environmental liabilities (14.2) (10.5)
Tax loss carryforwards (43.7) (43.9)
Deferred revenue (20.8) (18.4)
Other (46.7) (43.3)
- ---------------------------------------------------------------------------------------------------------------------
Gross Deferred Tax Assets (193.3) (225.3)
- ---------------------------------------------------------------------------------------------------------------------
Deferred Tax Asset Valuation Allowance 11.4 31.3
- ---------------------------------------------------------------------------------------------------------------------
NET DEFERRED TAX LIABILITY* 652.3 610.0
- ---------------------------------------------------------------------------------------------------------------------
* Includes net current deferred tax assets of $21.8 million and $45.3 million
reflected in Current Assets for 1999 and 1998, respectively.
As reflected by the valuation allowance in the table above, Columbia had
potential tax benefits of $11.4 million and $31.3 million at December 31, 1999
and 1998, respectively, which were not recognized in the statements of
consolidated income when generated. These benefits result primarily from state
income tax operating loss carryforwards which are available to reduce future tax
liabilities. The net decrease of $19.9 million in the valuation allowance
reflects management's belief that it is now likely that the majority of the
state net operating loss carryforwards will be utilized before they expire. The
expiration of the tax loss carryforward benefits, net of federal taxes, in 2000
is $1.4 million, in 2001 is $0.5 million, in 2002 is $0.2 million, in 2003 is
$0.3 million, in 2004 is $0.3 million and beyond is $41.0 million.
9. PENSION AND OTHER POSTRETIREMENT BENEFITS
Columbia has a noncontributory, qualified defined benefit pension plan covering
essentially all employees. Benefits are based primarily on years of credited
service and employees' highest three-year average annual compensation in the
final five years of service. Effective January 1, 2000, Columbia adopted a cash
balance feature to the pension plan that provides benefits based on a
percentage, which may vary with age and years of service, of current eligible
compensation and current interest credits. Columbia's funding policy complies
with Federal law and tax regulations. In addition, Columbia has a nonqualified
pension plan that provides benefits to some employees in excess of the qualified
plan's Federal tax limits. Columbia also provides medical coverage and life
insurance to retirees. Essentially all active employees are eligible for these
benefits upon retirement after completing ten consecutive years of service after
age 45. Normally, spouses and dependents of retirees are also eligible for
medical benefits. Columbia is reflecting the information presented below as of
September 30, rather than December 31. The effect of utilizing September 30,
rather than December 31, is not significant.
On September 30, 1999, Columbia Transmission announced the introduction of a
voluntary incentive retirement plan. Approximately 600 Columbia Transmission
employees were eligible for the program, which provides a retirement incentive
for active employees who are age fifty and above with at least five years of
service as of March 1, 2000. During the acceptance period that began on January
1, 2000 and closed on January 31, 2000, 486 employees elected early retirement.
The majority of the retirements are scheduled to occur in the first quarter of
2000, at which time the cost of the program will be recorded. In February 2000,
the five distribution subsidiaries and Columbia Energy Group Service Corporation
announced the introduction of a VIRP. Approximately 880 employees are eligible
for the program, which provides a retirement incentive for certain active
employees who are age fifty and above with at least five years of service as of
June 1, 2000. The acceptance period will end on April 30, 2000. The majority of
the retirements are scheduled to occur on June 1, 2000, at which time the cost
of the program will be recorded. Retirement costs for these employees are funded
through the pension plan and will not have a significant impact on Columbia's
consolidated net income.
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55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following tables provide a reconciliation of the plans' funded status and
amounts reflected in Columbia's consolidated balance sheets at December 31:
PENSION BENEFITS OTHER BENEFITS
------------------------ ------------------------
($ in millions) 1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year 946.8 888.9 198.9 309.8
Service cost 30.6 31.3 12.6 13.0
Interest cost 62.9 64.7 14.0 23.4
Plan participants' contributions -- -- 2.4 2.8
Plan amendments 3.9 -- 4.5 (2.2)
Actuarial (gain) loss (59.8) 56.0 (12.2) 6.1
Settlements -- -- (24.5) (130.3)
Actual expense paid (4.7) (5.2) -- --
Benefits paid (95.9) (88.9) (13.5) (23.7)
- ---------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 883.8 946.8 182.2 198.9
- ---------------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year 1,091.5 1,164.6 117.0 242.9
Actual return on plan assets 210.0 20.8 26.0 11.2
Columbia contributions -- -- 15.5 32.4
Plan participants' contributions -- -- 2.4 2.8
Settlements -- -- (31.6) (146.9)
Actual expense paid (4.7) (5.2) -- (1.7)
Benefits paid (95.7) (88.7) (13.5) (23.7)
- ---------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 1,201.1 1,091.5 115.8 117.0
- ---------------------------------------------------------------------------------------------------------------------------
Funded status of plan at end of year 317.3 144.7 (66.4) (81.9)
Unrecognized actuarial net gain (403.4) (237.8) (54.1) (41.5)
Unrecognized prior service cost 45.2 45.1 2.6 (2.2)
Unrecognized transition obligation 3.5 4.6 -- --
Fourth quarter contributions -- -- 3.3 4.5
- ---------------------------------------------------------------------------------------------------------------------------
ACCRUED BENEFIT COST (37.4) (43.4) (114.6) (121.1)
- ---------------------------------------------------------------------------------------------------------------------------
PENSION BENEFITS OTHER BENEFITS
----------------------- ------------------------
1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF
SEPTEMBER 30,
Discount rate assumption 7.75% 6.75% 7.75% 6.75%
Compensation growth rate assumption 4.50% 4.40% 4.50% 4.40%
Medical cost trend assumption -- -- 5.50% 5.50%
Assets earnings rate assumption 9.00% 9.00% 9.00%* 9.00%*
- ---------------------------------------------------------------------------------------------------------
* One of the several established medical trusts is subject to taxation which
results in an after-tax asset earnings rate that is less than 9.00%
55
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides the components of the plans expense for each of the
three years:
PENSION BENEFITS OTHER BENEFITS
----------------------------------- ----------------------------------
($ in millions) 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------------
NET PERIODIC COST
Service cost 30.6 31.3 28.7 12.6 13.0 11.2
Interest cost 62.9 64.7 67.6 14.0 23.5 23.1
Expected return on assets (94.1) (99.7) (88.2) (9.4) (18.3) (13.1)
Amortization of transition obligation 1.2 1.2 1.2 -- -- --
Recognized gain (10.2) (17.5) (11.3) (2.1) (10.3) (9.6)
Prior service cost amortization 3.7 3.7 3.7 (0.4) -- --
Settlement gain -- -- -- (6.1) (46.6) --
- ---------------------------------------------------------------------------------------------------------------------------------
NET PERIODIC BENEFITS COST (BENEFIT) (5.9) (16.3) 1.7 8.6 (38.7) 11.6
- ---------------------------------------------------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects:
1% point 1% point
increase decrease
- ---------------------------------------------------------------------------------------------------------------------
Effect on service and interest components of net periodic cost $ 2.6 $ (2.4)
Effect on accumulated postretirement benefit obligation $ 15.0 $ (13.8)
- ---------------------------------------------------------------------------------------------------------------------
During 1999 and 1998, trusts established by Columbia purchased insurance
policies that provide both medical and life insurance with respect to
liabilities to a selected class of current retirees. As a result, pre-tax gains
in the amount of $6.1 million and $46.6 million were recorded in 1999 and 1998,
respectively. The 1999 gain is reflected in the consolidated financial
statements as a $4 million reduction to benefits expense, and a $2.1 million
liability of certain rate-regulated companies. The 1998 gain is reflected in the
consolidated financial statements as a $25.4 million reduction to benefits
expense, and a $21.2 million liability of certain rate-regulated companies.
10. LONG-TERM INCENTIVE PLAN
Columbia has two Long-Term Incentive Plans. Columbia's 1996 Long-Term Incentive
Plan (1996 LTIP) which is effective for ten years, beginning February 21, 1996,
provides for the granting of nonqualified stock options and incentive stock
options, contingent stock awards, stock appreciation rights and restricted stock
awards to officers and key employees. The 1996 LTIP also provides for the
granting of nonqualified stock options to outside directors. A total of
8,585,000 shares of Columbia's authorized common stock is available under the
1996 LTIP's provisions.
Columbia also provides an incentive compensation plan for outside directors
under which they may receive benefits in lieu of a retirement plan and defer
current compensation in the form of phantom stock units, which equates the
amounts granted to the directors with the performance of Columbia's stock.
Columbia's 1985 Long-Term Incentive Plan (1985 LTIP), in effect from 1985
through 1995, provided for the granting of nonqualified stock options, stock
appreciation rights and contingent stock awards as determined by the
Compensation Committee of the Board of Directors. That committee also had the
right to modify any outstanding award. A total of 1,500,000 shares of Columbia's
authorized common stock was available under the 1985 LTIP's provisions.
Stock appreciation rights, which were granted in connection with certain
nonqualified stock options, entitle the holders to receive stock, cash or a
combination thereof equal to the excess market value over the grant price. Stock
options and related stock appreciation rights granted under the 1985 LTIP
generally have a maximum term of ten years and vest over two to four years.
56
57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Transactions for the three years ended December 31, 1999, are as follows:
Options
-----------------------------------
Without Stock With Stock Weighted Average
Appreciation Appreciation Exercise Price
Rights Rights Per Share
- -------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 1996 405,675 75,930 $42.88
Granted 1,133,350 -- $63.40
Exercised (183,138) (48,790) $44.31
Forfeited (43,462) (3,240) $62.01
- -------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 1997 1,312,425 23,900 $59.37
Granted 853,300 -- $76.22
Exercised (92,821) -- $53.47
Forfeited (9,000) -- $65.48
Adjustment for three-for-two stock split 1,032,700 11,950 $44.32*
Granted 20,800 -- $54.14
Exercised (114,579) (26,190) $36.76
Forfeited (22,950) -- $50.77
- -------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 1998 2,979,875 9,660 $44.79
Granted 1,585,200 -- $49.76
Exercised (268,280) (4,860) $41.81
Forfeited (121,795) -- $48.52
- -------------------------------------------------------------------------------------------------------------
OUTSTANDING AT DECEMBER 31, 1999 4,175,000 4,800 $46.76
- -------------------------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 1999 1,884,734 4,800 $42.71
- -------------------------------------------------------------------------------------------------------------
* Reflects repricing of outstanding stock options for the effect of the
three-for-two common stock split.
Regarding the stock options granted in 1999, 1998 and 1997, such options vest
ratably over three years.
The following table summaries information on stock options outstanding and
exercisable at December 31, 1999:
Options Outstanding Options Exercisable
---------------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Remaining Average
Range of Exercise Number Exercise Price Contractual Life Number Exercise Price
Prices Per Share Outstanding Per Share in Years Exercisable Per Share
- ------------------------------------------------------------------------------------------------------------------------
$19.33-$20.70 36,000 $19.62 5.43 36,000 $19.62
$31.12-$42.4583 1,430,275 $40.89 6.94 1,430,275 $40.89
$47.3958-$59.938 2,713,525 $50.21 8.74 423,259 $50.84
- ------------------------------------------------------------------------------------------------------------------------
$19.33-$59.938 4,179,800 $46.76 8.09 1,889,534 $42.71
- ------------------------------------------------------------------------------------------------------------------------
There were no contingent stock awards granted in 1999, 1998 or 1997. Restricted
stock awards totaling 44,677 shares were granted to one key executive in 1996 of
which 8,395 shares vested during 1999, 1998 and 1997, respectively.
During 1999, 1998, and 1997, $4.5 million, $2.4 million, and $3.2 million were
expensed for the long-term incentive plans, respectively.
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58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Had compensation cost been determined consistent with the provisions of the SFAS
No. 123 fair value method (See Note 1), Columbia's net income and earnings per
share would have been the pro forma amounts below:
Year Ended December 31 ($ in millions, except per share data) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
Net Income
As reported 249.2 269.2 273.3
Pro forma 232.4 258.4 266.8
Earnings per share
Basic - as reported 3.03 3.23 3.29
- pro forma 2.83 3.10 3.21
Diluted - as reported 3.01 3.21 3.27
- pro forma 2.81 3.09 3.19
Weighted-average fair value of options granted during the year 17.53 17.79 24.85
- ----------------------------------------------------------------------------------------------------------------------
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with a dividend yield of zero percentage and
the following assumptions used for grants in 1999, 1998, and 1997:
1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------------
Expected Life 7 YRS. 7 yrs. 7 yrs.
Interest Rate 5.19%-6.27% 4.90%-5.77% 5.86%-6.89%
Volatility 18.18%-21.67% 14.97%-17.40% 18.41%-19.29%
- -----------------------------------------------------------------------------------------------------------------------
11. LONG-TERM DEBT
The long-term debt (exclusive of current maturities) of Columbia and its
subsidiaries is as follows:
At December 31, ($ in millions) 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
Columbia Energy Group Debentures
6.39% Series A due November 28, 2000 -- 311.0
6.61% Series B due November 28, 2002 281.5 281.5
6.80% Series C due November 28, 2005 281.5 281.5
7.05% Series D due November 28, 2007 281.5 281.5
7.32% Series E due November 28, 2010 281.5 281.5
7.42% Series F due November 28, 2015 281.5 281.5
7.62% Series G due November 28, 2025 229.2 281.5
- -----------------------------------------------------------------------------------------------------------------------
Total Debentures 1,636.7 2,000.0
Subsidiary Debt:
Capitalized lease obligations 2.8 3.1
Other 0.2 --
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 1,639.7 2,003.1
- -----------------------------------------------------------------------------------------------------------------------
During 1999, Columbia repurchased $52.45 million of its 7.62% Series G
Debentures due November 28, 2025 at a price of approximately 99% of par value.
The net impact of the early extinguishment of such debt was immaterial.
During 1998, Columbia entered into interest rate swap agreements to modify the
interest characteristics of its outstanding long-term debt. At December 31,
1999, Columbia has outstanding four interest rate swap agreements effective
through November 28, 2002, on $200 million notional amounts of its 6.61% Series
B Debentures due November 28, 2002. In addition, Columbia has outstanding an
interest rate swap agreement effective through November 28, 2005, on a $100
million notional amount of its 6.80% Series C Debentures due November 28, 2005.
Under the terms of the agreements, Columbia pays interest based on a floating
rate index and receives interest based on a fixed rate. The effect of these
agreements is to modify the interest rate characterization of a portion of
Columbia's long-term debt from fixed to variable. The effect of these interest
rate swaps on interest expense in 1999 and 1998 was immaterial.
58
59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The aggregate maturities of long-term debt and capitalized lease obligations
during the next five years are as follows:
($ in millions)
- ---------------------------------------------------------------------------------------------------------------------
2000 311.3
2001 0.4
2002 281.7
2003 0.2
2004 0.3
- ---------------------------------------------------------------------------------------------------------------------
12. SHORT-TERM DEBT AND CREDIT FACILITIES
Columbia has two unsecured bank revolving credit facilities available that total
$1.35 billion (Credit Facilities). The Credit Facilities consist of a $900
million five-year revolving credit facility and a $450 million 364-day revolving
credit facility with a one-year term loan option. The five-year facility
provides for the issuance of up to $300 million of letters of credit. Interest
rates on borrowings under the Credit Facilities are based upon the London
Interbank Offered Rate, Certificate of Deposit rate or Citibank's publicly
announced "base rate." Facility fees and borrowing margins are based on
Columbia's public debt ratings. At Columbia's current rating, the facility fee
charged on the $900 million credit facility is 0.09% and on the $450 million
credit facility is 0.06%. The Credit Facilities contain certain covenants that
must be met to borrow funds, including restrictions on the incurrence of liens
and a maximum leverage ratio. Compensating balances are not required.
At December 31, 1999, Columbia had no borrowings outstanding under the Credit
Facilities. The maximum indebtedness outstanding during the year occurred on May
11, 1999, in the amount of $32.6 million at an average interest rate of 5.69%.
At December 31, 1998, Columbia had no borrowings outstanding under the Credit
Facilities.
On October 28, 1999, Columbia issued a note payable outside of the Credit
Facilities in the amount of $125 million at an interest rate of 6.70%. The note
matured on January 28, 2000.
As of December 31, 1999, Columbia had $54.7 million of letters of credit
outstanding under the Credit Facilities. Fees for letters of credit issued are
calculated at rates that are based on Columbia's public debt rating plus a
commission of 0.125% to the issuing bank. In addition, Columbia had
approximately $4 million of letters of credit outstanding to guarantee certain
transactions of an affiliate. Fees for the letter of credit issued were at a
rate of 0.625%. At December 31, 1998, Columbia had $44.4 million of letters of
credit outstanding under the Credit Facilities.
Columbia has an $850 million commercial paper program authorized and rated by
the rating agencies. The commercial paper program is supported by the Credit
Facilities. At December 31, 1999, Columbia had commercial paper outstanding of
$340.5 million (net of discount) at a weighted-average interest rate of 6.34%.
The maximum commercial paper indebtedness outstanding during the year occurred
on October 25, 1999, in the amount $642.2 million at an average interest rate of
5.72%. At December 31, 1998, Columbia had commercial paper outstanding of $144.8
million (net of discount) at a weighted-average interest rate of 6.12%.
Columbia was the guarantor on certain contracts of its marketing affiliate that
were sold to Enron effective December 30, 1999. These contracts had not been
legally assigned to Enron as of the balance sheet date, therefore the guarantees
are still outstanding. Enron has provided Columbia guarantees and
indemnification should Columbia be required to perform under the guarantees. At
December 31, 1999, Columbia had a $75 million letter of credit outstanding and
has issued other guarantees and indemnities in the amount of $646.6 million. As
of February 18, 2000, this amount has been reduced to $585.3 million.
At December 31, 1999, approximately $12.5 million of investments were pledged as
collateral on outstanding letters of credit related to Columbia's wholly-owned
insurance company.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
Statement of Financial Accounting Standards No. 107, "Disclosures about Fair
Value of Financial Instruments," requires all entities to disclose the fair
value of financial instruments, both assets and liabilities, recognized and not
recognized in the consolidated balance sheets, for which it is practicable to
estimate a fair value. For purposes of this disclosure, the fair value of a
financial instrument is the amount at which the instrument could be exchanged in
a current transaction between willing parties, other than in a forced or
liquidation sale. Fair value may be based on
59
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
quoted market prices for the same or similar financial instruments or on
valuation techniques, such as the present value of estimated future cash flows
using a discount rate commensurate with the risks involved.
As cash and temporary cash investments, current receivables, current payables,
and certain other short-term financial instruments are all short-term in nature,
their carrying amount approximates fair value. Columbia utilizes standby letters
of credit (See Note 12) and does not believe it is practicable to estimate their
fair value.
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:
LONG-TERM INVESTMENTS
Long-term investments include loans receivable ($7.7 million for 1999 and $3.3
million for 1998) whose estimated fair values are based on the present value of
estimated future cash flows using an estimated rate for similar loans. Long-term
investments also include pledged assets ($14.4 million for 1999 and $11.8
million for 1998), whose estimated fair value is based on the trading value
provided by a financial institution. The financial instruments included in
long-term investments are primarily reflected in Investments and Other Assets on
the consolidated balance sheets. Long-term investments for which it is
practicable to estimate fair value had carrying amounts of $22.1 million and
$15.1 million, and estimated fair values of $21.7 million and $14.7 million at
December 31, 1999 and 1998, respectively. There are no long-term investments for
which it is not practicable to estimate fair value at December 31, 1999 and
1998.
LONG-TERM DEBT
The estimated fair value of Columbia's debentures, including current maturities
and accrued interest, is based on estimates provided by brokers. Long-term debt
of $1,960.1 million and $2,012.9 million at December 31, 1999 and 1998, have
estimated fair values of $1,858.4 million and $2,088.1 million, respectively.
The fair value of Columbia's interest rate swaps agreements are based on the
amounts estimated to terminate or settle the agreements. At December 31, 1999
and December 31, 1998, Columbia had interest rate swaps agreements with notional
amounts of $300 million. Columbia would have paid $18 million to terminate the
agreements at December 31, 1999. The amount that Columbia would have paid to
terminate the agreements at December 31, 1998 was immaterial.
ACCOUNTS RECEIVABLE SALES PROGRAM
In October 1999, Columbia of Ohio entered into an agreement to sell, without
recourse, substantially all of its trade accounts receivable to Columbia
Accounts Receivable Corporation (CARC), a wholly-owned subsidiary of Columbia.
At the same time, CARC entered into an agreement, with a third party, Canadian
Imperial Bank of Commerce (CIBC), to sell a percentage ownership interest in a
defined pool of accounts receivable (Sales Program). Under this Sales Program,
CARC can transfer an undivided interest in a designated pool of its accounts
receivable on an ongoing basis up to a maximum of $125 million until April 30,
2000, at which time the maximum decreases to $100 million. The amount available
at any measurement date varies based upon the level of eligible receivables.
Under this agreement, approximately $81 million of receivables were sold as of
December 31, 1999.
Under a separate agreement, in conjunction with the Sales Program, Columbia of
Ohio acts as agent for CIBC, the ultimate purchaser of the receivables, by
performing record keeping and cash collection functions for the accounts
receivable sold by CARC. Columbia of Ohio receives a fee, which provides
adequate compensation, for such services.
14. OTHER COMMITMENTS AND CONTINGENCIES
A. BANKRUPTCY MATTERS. On November 28, 1995, Columbia and its wholly-owned
subsidiary, Columbia Transmission emerged from Chapter 11 protection of the
United States Bankruptcy Code under the jurisdiction of the United States
Bankruptcy Court for the District of Delaware (Bankruptcy Court). Both Columbia
and Columbia Transmission had operated under Chapter 11 protection from July 31,
1991, until emergence. Certain residual unresolved bankruptcy-related matters
are still within the jurisdiction of the Bankruptcy Court.
During the first quarter of 1999, Columbia Transmission resolved its last
remaining producer claim in its bankruptcy proceeding. The improvement to
Columbia's first quarter 1999 consolidated net income was $20.6 million. The
settlement was approved by the Bankruptcy Court on April 12, 1999 and on April
26, 1999, Columbia Transmission distributed the producer holdback amounts in
accordance with its Plan of Reorganization and a producer settlement.
60
61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
There remain four non-producer claims to be resolved, all of which are being
litigated outside of the Bankruptcy Court. Columbia believes adequate reserves
have been established for resolution of the remaining non-producer claims.
B. CAPITAL EXPENDITURES. Capital expenditures for 2000 are currently estimated
at $874.7 million. Of this amount, $148.4 million is for transmission and
storage operations, $135.6 million for distribution operations, $165.7 million
for exploration and production operations, $43.3 million for energy marketing
operations, $376.5 million for power generation, LNG and other operations and
$5.2 million for corporate purposes.
C. OTHER LEGAL PROCEEDINGS. In the normal course of its business, Columbia and
its subsidiaries have been named as defendants in various legal proceedings. In
the opinion of management, the ultimate disposition of these currently asserted
claims will not have a material adverse impact on Columbia's consolidated
financial position or results of operations.
D. ASSETS UNDER LIEN. Substantially all of Columbia Transmission's properties
have been pledged to Columbia as security for debt owed by Columbia Transmission
to Columbia.
Columbia Electric holds indirectly through various subsidiaries, both general
and limited partnership interests in the following electric power generation
projects:
Vineland Cogeneration Limited Partnership (the "Partnership") owns and operates
a project-financed non-utility power generation facility in New Jersey. The
assets of the Partnership, including plant facilities and contract rights, have
been pledged as collateral to an indenture trustee for the benefit of certain
bondholders.
Gregory Power Partners owns a 550-megawatt equivalent electric power generation
plant that is currently under construction in Gregory, Texas. The assets and
contract rights have been pledged as collateral for the construction loan.
Columbia Electric's investment in these partnerships, as of December 31, 1999,
amounted to $13.2 million.
E. GUARANTEES AND INDEMNITIES. In connection with the purchase of National
Propane Partners, L.P. (National Propane) interests, Columbia has provided an
indemnity to reimburse the former Managing General Partner for income taxes that
would be due if certain actions by Columbia result in the recognition of certain
types of income or gain by the former Managing General Partner.
To secure certain partnership transactions, Columbia Electric has provided
financial support through letters of credit, indemnification agreements, and
guarantees. As of December 31, 1999, agreements for approximately $57 million
have been executed.
F. INTERNAL REVENUE SERVICE (IRS) AUDIT. The field audit of Columbia's 1995
federal income tax return has been finalized and discussions on all unagreed
issues have begun. The audit of tax years 1996 and 1997 began in February 1999.
Management believes adequate reserves have been established for issues related
to these returns.
G. OPERATING LEASES. Payments made in connection with operating leases are
primarily charged to operation and maintenance expense as incurred. Such amounts
were $61.5 million in 1999, $63.8 million in 1998 and $62.9 million in 1997.
Future minimum rental payments required under operating leases that have initial
or remaining noncancellable lease terms in excess of one year are:
($ in millions)
- ---------------------------------------------------------------------------------------------------------------------
2000 34.7
2001 29.4
2002 27.2
2003 26.4
2004 24.1
After 162.7
- ---------------------------------------------------------------------------------------------------------------------
61
62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
H. PURCHASE COMMITMENTS. Columbia has service agreements that provide for
pipeline capacity, transportation and storage services. These agreements which
have expiration dates ranging from 2000 to 2017, provide for Columbia to pay
fixed monthly charges. The estimated aggregate amounts of such payments at
December 31, 1999, were:
($ in millions)
- ---------------------------------------------------------------------------------------------------------------------
2000 58.0
2001 52.9
2002 47.8
2003 36.0
2004 32.7
After 185.2
- ---------------------------------------------------------------------------------------------------------------------
Costs incurred under these contracts are recovered under Columbia's regulatory
cost recovery mechanisms.
I. ENVIRONMENTAL MATTERS. Columbia's subsidiaries are subject to extensive
federal, state and local laws and regulations relating to environmental matters.
These laws and regulations, which are constantly changing, require expenditures
for corrective action at various operating facilities, waste disposal sites and
former gas manufacturing sites for conditions resulting from past practices that
have subsequently become subject to environmental regulation.
Columbia's transmission subsidiaries have implemented programs to continually
review compliance with existing environmental standards. In addition, the
transmission subsidiaries have reviewed past operational activities and
conducted remediation programs where necessary.
Columbia Transmission is currently conducting assessment, characterization and
remediation activities at specific sites under a 1995 Environmental Protection
Agency (EPA) Administrative Order by Consent (AOC). The program pursuant to the
AOC covers approximately 240 facilities, approximately 13,000 liquid removal
points, approximately 2,200 mercury measurement stations, and about 3,700
storage wells. As of December 31, 1999, field characterization has been
performed at many of these sites, and site characterization reports and
remediation plans which must be submitted to EPA for approval are in various
stages of development and completion. Significant remediation has taken place
only at mercury measurement stations and at a limited number of the 240
facilities.
Only those site investigation, characterization and remediation costs currently
known and determinable can be considered "probable and reasonably estimable"
under Statement of Financial Accounting Standards No. 5, "Accounting for
Contingencies" (SFAS No. 5). As costs become probable and reasonably estimable,
the associated reserves will be adjusted as appropriate. Columbia Transmission
is unable, at this time, to accurately estimate the time frame and potential
costs of the entire program. Management expects that as additional work is
performed and more facts become available, it will be able to develop a probable
and reasonable estimate for the entire program or a major portion thereof
consistent with U.S. Securities and Exchange Commission's Staff Accounting
Bulletin No. 92, SFAS No. 5, and American Institute of Certified Public
Accountants Statement of Position 96-1.
During 1999, actual expenditures of $16.8 million were charged to the liability
resulted in a remaining liability of $121.4 million. Columbia Transmission's
environmental cash expenditures are expected to be approximately $17 million in
2000 and to remain at this level for the foreseeable future. These expenditures
will be charged against the previously recorded liability. Consistent with
Statement of Financial Accounting Standards No. 71, a regulatory asset has been
recorded to the extent environmental expenditures are probable of recovery
through rates. Management does not believe that Columbia Transmission's
environmental expenditures will have a material adverse effect on its
operations, liquidity or financial position, based on known facts and existing
laws and regulations and the long time period over which expenditures will be
made.
In addition, predecessor companies of Columbia Transmission may have been
involved in the operation of manufactured gas plants. When such plants were
abandoned, material used and created in the process was sometimes buried at the
site. As of the date of this report, Columbia Transmission is unable to
determine if it will become liable for any characterization or remediation costs
at such sites.
Distribution's primary environmental issues relate to 18 former manufactured gas
plant sites. Investigations or remedial activities are currently underway at six
sites and remedial construction has been completed at two sites. Additional site
investigations may be required at some of the remaining sites. To the extent
Distribution's site investigations have been conducted, remediation plans
developed and any responsibility for remediation established,
62
63
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
the appropriate estimated liabilities have been recorded. Regulatory assets have
also been recorded for a majority of these costs as rate recovery has been
authorized or is anticipated.
Columbia Propane's primary environmental issues relate to former manufactured
gas plant sites acquired in the acquisition of National Propane for which
accruals have been made. Investigations are currently underway at one site. One
other known former manufactured gas plant site is inactive. It is possible that
former manufactured gas plant sites exist at two other National Propane
properties. Management does not believe that Columbia Propane's environmental
expenditures will have a material adverse effect on Columbia's consolidated
financial results.
The eventual total cost of full future environmental compliance for Columbia is
difficult to estimate due to, among other things: (1) the possibility of as yet
unknown contamination, (2) the possible effect of future legislation and new
environmental agency rules, (3) the possibility of future litigation, (4) the
possibility of future designations as a potential responsible party by the EPA
and the difficulty of determining liability, if any, in proportion to other
responsible parties, (5) possible insurance and rate recoveries, and (6) the
effect of possible technological changes relating to future remediation.
However, reserves have been established based on information currently
available, which resulted in a total recorded net liability of approximately
$124.7 million for Columbia at December 31, 1999. As new issues are identified,
additional liabilities will be recorded.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve mutually
acceptable compliance plans. However, there can be no assurance that fines and
penalties will not be incurred. Management expects most environmental assessment
and remediation costs to be recoverable through rates.
15. INTEREST INCOME AND OTHER, NET
Year Ended December 3l, ($ in millions) 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
Interest income 13.5 12.5 19.9
Miscellaneous 15.7 (0.2) 19.5
- -----------------------------------------------------------------------------------------------------------------
TOTAL INTEREST INCOME AND OTHER, NET 29.2 12.3 39.4
- -----------------------------------------------------------------------------------------------------------------
16. INTEREST EXPENSE AND RELATED CHARGES
Year Ended December 31, ($ in millions) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------
Interest on debentures 138.0 140.4 140.4
Interest on short-term debt 18.4 10.8 8.0
Discount on prepayment transactions 2.3 - -
Interest on rate refunds 3.1 2.3 3.4
Interest on prior years' taxes 6.2 (6.3) 9.1
Allowance for borrowed funds used
and interest during construction (3.6) (2.7) (3.5)
- -----------------------------------------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE AND RELATED CHARGES 164.4 144.5 157.4
- -----------------------------------------------------------------------------------------------------------------
17. BUSINESS SEGMENT INFORMATION
Columbia is a registered holding company under the Public Utility Holding
Company Act of 1935, as amended, and derives substantially all of its revenues
and earnings from the operating results of its 19 direct subsidiaries. During
1999, in accordance with generally accepted accounting principles, Columbia
revised the presentation of its business segments and accordingly, all prior
periods have been restated. Columbia's operations are divided into five primary
business segments. The transmission and storage segment offers transportation
and storage services for local distribution companies, marketers and industrial
and commercial customers located in northeastern, mid-Atlantic, midwestern and
southern states and the District of Columbia. The distribution segment provides
natural gas service and transportation for residential, commercial and
industrial customers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland. The
exploration and production segment explores for, develops, produces and markets
gas and oil in the United States and in Canada. The energy marketing segment
provides gas and electric power to smaller volume retail customers and sells
propane and petroleum to wholesale and retail customers in 35 states and the
District of Columbia. The power generation, LNG and other segment participates
in natural gas fueled electric cogeneration projects, peaking and storage
services as well as a telecommunications business.
The following tables provide information concerning Columbia's major business
segments. Revenues include intersegment sales to affiliated subsidiaries, which
are eliminated when consolidated. Affiliated sales are recognized
63
64
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
on the basis of prevailing market or regulated prices. Operating income is
derived from revenues and expenses directly associated with each segment.
($ in millions) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
REVENUES
Transmission and Storage
Unaffiliated 571.3 546.1 519.9
Intersegment 265.1 292.6 318.7
- ---------------------------------------------------------------------------------------------------------------------
TOTAL 836.4 838.7 838.6
- ---------------------------------------------------------------------------------------------------------------------
Distribution
Unaffiliated 2,022.1 1,858.8 2,293.9
Intersegment 0.7 10.7 2.4
- ---------------------------------------------------------------------------------------------------------------------
TOTAL 2,022.8 1,869.5 2,296.3
- ---------------------------------------------------------------------------------------------------------------------
Exploration and Production
Unaffiliated 143.4 125.4 112.3
Intersegment 1.4 2.1 1.0
- ---------------------------------------------------------------------------------------------------------------------
TOTAL 144.8 127.5 113.3
- ---------------------------------------------------------------------------------------------------------------------
Energy Marketing
Unaffiliated 396.0 95.6 78.7
Intersegment 0.7 0.6 1.5
- ---------------------------------------------------------------------------------------------------------------------
TOTAL 396.7 96.2 80.2
- ---------------------------------------------------------------------------------------------------------------------
Power Generation, LNG and Other
Unaffiliated 89.0 19.2 22.0
Intersegment (0.3) (0.1) 0.2
- ---------------------------------------------------------------------------------------------------------------------
TOTAL 88.7 19.1 22.2
- ---------------------------------------------------------------------------------------------------------------------
Adjustments and eliminations
Intersegment (267.6) (305.9) (323.8)
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED 3,221.8 2,645.1 3,026.8
- ---------------------------------------------------------------------------------------------------------------------
64
65
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued
($ in millions) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS)
Transmission and Storage 350.1 326.1 258.3
Distribution 254.6 225.8 224.2
Exploration and Production 44.2 37.2 30.9
Energy Marketing (54.5) (13.6) 6.0
Power Generation, LNG
and Other 71.5 6.6 9.2
Corporate (17.5) (0.8) (7.1)
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED 648.4 581.3 521.5
- ---------------------------------------------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
Transmission and Storage 106.2 101.8 104.3
Distribution 54.5 82.2 78.2
Exploration and Production 36.9 36.5 27.6
Energy Marketing 26.6 5.8 3.6
Power Generation, LNG
and Other 0.1 0.1 0.1
Corporate 4.2 5.0 5.5
Adjustments and eliminations 0.5 0.5 0.6
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED 229.0 231.9 219.9
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
Transmission and Storage 2,814.1 2,837.6 2,775.4
Distribution 2,831.3 2,665.1 2,753.2
Exploration and Production 774.3 590.9 564.6
Energy Marketing 576.0 354.0 175.9
Power Generation, LNG
and Other 240.9 103.3 85.6
Corporate 4,848.8 4,298.0 4,221.4
Adjustments and eliminations (4,989.5) (4,317.5) (4,316.7)
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED 7,095.9 6,531.4 6,259.4
- ---------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Transmission and Storage 183.4 210.0 251.4
Distribution 145.5 151.9 159.5
Exploration and Production 166.5 75.7 135.6
Energy Marketing 315.5 27.9 10.4
Power Generation, LNG
and Other 51.0 2.7 1.0
Corporate 5.4 11.0 5.3
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED 867.3 479.2 563.2
- ---------------------------------------------------------------------------------------------------------------------
65
66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued
18. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data does not always reveal the trend of Columbia's business
operations due to nonrecurring items and seasonal weather patterns which affect
earnings and related components of net revenues and operating income.
First Second Third Fourth
($ in millions, except per share data) Quarter Quarter Quarter Quarter
- ---------------------------------------------------------------------------------------------------------------------
1999
Net Revenues 650.3 384.2 351.0 609.3
Operating Income 283.7 71.0 39.9 253.8
Income from Continuing Operations 160.4 32.6 6.7 155.3
(Loss) from Discontinued Operations - net (10.0) (6.5) (29.4) (59.9)
of taxes
Net Income (Loss) 150.4(a) 26.1(b) (22.7) 95.4(c)
Basic Earnings (Loss) Per Share
Continuing Operations 1.93 0.40 0.08 1.91
Discontinued Operations (0.12) (0.08) (0.36) (0.74)
--------- ------- ------- -------
Basic Earnings (Loss) per Share 1.81 0.32 (0.28) 1.17
========= ======= ======= =======
Diluted Earnings (Loss) Per Share
Continuing Operations 1.92 0.40 0.08 1.89
Discontinued Operations (0.12) (0.08) (0.36) (0.73)
--------- ------- ------- -------
Diluted Earnings (Loss) Per Share 1.80 0.32 (0.28) 1.16
========= ======= ======= =======
- ---------------------------------------------------------------------------------------------------------------------
1998
Net Revenues 613.2 375.6 337.7 535.4
Operating Income 257.3 77.2 56.1 190.7
Income from Continuing Operations 150.4 27.8 13.8 108.3
(Loss) from Discontinued Operations - net (2.9) (5.0) (2.6) (20.6)
of taxes
Net Income 147.5(d) 22.8 11.2 87.7
Basic Earnings (Loss) Per Share
Continuing Operations 1.80 0.33 0.16 1.30
Discontinued Operations (0.03) (0.06) (0.03) (0.25)
--------- ------- ------- -------
Basic Earnings Per Share 1.77 0.27 0.13 1.05
========= ======= ======= =======
Diluted Earnings (Loss) Per Share
Continuing Operations 1.80 0.33 0.16 1.29
Discontinued Operations (0.03) (0.06) (0.03) (0.24)
--------- ------- ------- -------
Diluted Earnings Per Share 1.77 0.27 0.13 1.05
========= ======= ======= =======
- ---------------------------------------------------------------------------------------------------------------------
(a) Includes $20.6 million gain from the producer contract settlement stemming
from Columbia's bankruptcy proceedings concluded in 1995.
(b) Includes $6.9 million benefit from the reduction in tax expense for state
net operating loss carryforwards.
(c) Includes $49 million gain recorded in connection with the termination of a
cogeneration power purchase contract and $7.8 million gain on the sale of
Columbia's interest in the Trailblazer pipeline system.
(d) Includes $15 million gain on settlement of postretirement benefit costs and
a $10 million benefit from state tax planning initiatives.
19. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
During 1999, Columbia Resources' acquisition strategy involved six transactions
totaling approximately $61 million, added reserves of 65 Bcfe and expanded the
gathering infrastructure by more than 450 miles of pipeline. Also in 1999,
Columbia Resources discovered reserves in West Virginia in the Trenton-Black
river formation at depths exceeding 10,000 feet.
On August 7, 1997, Columbia Resources acquired Alamco, Inc. (Alamco), a gas and
oil production company operating in the Appalachian Basin. The information
contained in the following tables includes amounts attributable to the
operations and reserves of Alamco from August 7, 1997.
Reserve information contained in the following tables for the U.S. and Canadian
properties is management's estimate, which was reviewed by the independent
consulting firms of Ryder Scott Company Petroleum Engineers for the U.S.
reserves and Sproule Associates Limited for the Canadian reserves. Reserves are
reported as net working interest. Gross revenues are reported after deduction of
royalty interest payments.
66
67
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued
RESERVE QUANTITY INFORMATION United States Canada
- ---------------------------------------------------------------------------------------------------------------------
Oil & Other Oil & Other
Gas Liquids Gas Liquids
Proved Reserves (Bcf) (000 Bbls) (Bcf) (000 Bbls)
- ---------------------------------------------------------------------------------------------------------------------
Reserves as of December 31, 1996 644.5 774 - -
Revisions of previous estimate 69.5 (139) - -
Extensions, discoveries
and other additions 33.2 59 - -
Production (34.7) (210) - -
Purchase of reserves-in-place(a) 88.0 1,216 - -
- ---------------------------------------------------------------------------------------------------------------------
Reserves as of December 31, 1997 800.5 1,700 - -
Revisions of previous estimate (23.1) 178 - -
Extensions, discoveries
and other additions 60.7 94 - -
Production (39.0) (201) (0.1) (13)
Purchase of reserves-in-place - - 1.1 77
Sale of reserves-in-place (9.6) - - -
- ---------------------------------------------------------------------------------------------------------------------
Reserves as of December 31, 1998 789.5 1,771 1.0 64
Revisions of previous estimate 34.4 99 - 9
Extensions, discoveries
and other additions 116.8 38 0.3 40
Production (45.6) (175) (0.2) (10)
Purchase of reserves-in-place 58.2 539 - -
Sale of reserves-in-place (2.8) - - -
- ---------------------------------------------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1999 950.5 2,272 1.1 103
- ---------------------------------------------------------------------------------------------------------------------
Proved developed reserves as of
December 31,
1997 653.2 1,330 - -
1998 586.2 1,436 1.0 64
1999 697.2 1,953 1.1 103
- ---------------------------------------------------------------------------------------------------------------------
(a) Includes the purchase of Alamco.
CAPITALIZED COSTS United States Canada Total
- ---------------------------------------------------------------------------------------------------------------------
($ in millions) 1999 1998 1997 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
CAPITALIZED COSTS AT YEAR END
Proved properties 762.5 673.2 628.4 1.7 1.4 - 764.2 674.6 628.4
Unproved properties (a) 61.0 40.8 31.8 10.9 3.7 - 71.9 44.5 31.8
- ---------------------------------------------------------------------------------------------------------------------
Total capitalized costs 823.5 714.0 660.2 12.6 5.1 - 836.1 719.1 660.2
Accumulated depletion (251.3) (225.2) (196.0) (0.3) (0.2) - (251.6) (225.4) (196.0)
- ---------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS 572.2 488.8 464.2 12.3 4.9 - 584.5 493.7 464.2
- ---------------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR (b)
Acquisition properties
Proved 1.2 - - - 0.7 - 1.2 0.7 -
Unproved 8.6 0.6 0.1 2.9 3.0 - 11.5 3.6 0.1
Exploration 6.7 2.3 1.0 1.3 - - 8.0 2.3 1.0
Development 99.4 62.1 132.4 2.9 1.4 - 102.3 63.5 132.4
- ---------------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED 115.9 65.0 133.5 7.1 5.1 - 123.0 70.1 133.5
- ---------------------------------------------------------------------------------------------------------------------
(a) Represents expenditures associated with properties on which evaluations have
not been completed.
(b) Includes internal costs capitalized pursuant to the accounting policy
described in Note 1(F) of Notes to Consolidated Financial Statements of $3.5
million in 1999, $3.3 million in 1998 and $1.4 million in 1997.
67
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
OTHER EXPLORATION AND PRODUCTION DATA United States Canada
- ---------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Average sales price per Mcf of gas ($)(a) 2.66 2.91 2.63 2.25 2.61 -
Average sales price per barrel
of oil and other liquids ($) 14.69 12.53 17.99 19.43 16.42 -
Production (lifting) cost per
dollar of gross revenue ($) 0.19 0.21 0.24 0.18 0.32 -
Depletion rate per dollar
of gross revenue ($) 0.26 0.29 0.28 0.24 0.27 -
- ---------------------------------------------------------------------------------------------------------------------
(a) Includes the effect of hedging activities.
HISTORICAL RESULTS OF OPERATIONS
- ---------------------------------------------------------------------------------------------------------------------
United States Canada Total
($ in millions) 1999 1998 1997 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Gross revenues
Unaffiliated 122.4 53.7 27.4 0.5 0.6 - 122.9 54.3 27.4
Affiliated 1.4 62.3 69.0 - - - 1.4 62.3 69.0
Production costs 23.7 24.2 23.3 0.1 0.2 - 23.8 24.4 23.3
Depletion 32.8 33.5 26.6 0.1 0.2 - 32.9 33.7 26.6
Income tax expense 25.0 20.7 14.3 0.1 0.1 - 25.1 20.8 14.3
- ---------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 42.3 37.6 32.2 0.2 0.1 - 42.5 37.7 32.2
- ---------------------------------------------------------------------------------------------------------------------
Results of operations for exploration and production activities exclude
administrative and general costs, corporate overhead and interest expense.
Income tax expense is expressed at statutory rates less Section 29 credits.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
- ---------------------------------------------------------------------------------------------------------------------
United States Canada Total
($ in millions) 1999 1998 1997 1999 1998 1997 1999 1998 1997
- ----------------------------- ---------------------------------------------------------------------------------------
Future cash inflows 2,805.4 2,094.4 2,503.0 5.5 3.4 - 2,810.9 2,097.8 2,503.0
Future production costs (739.8) (585.5) (719.9) (2.1) (1.5) - (741.9) (587.0) (719.9)
Future development costs (258.3) (200.4) (182.7) (0.1) (0.1) - (258.4) (200.5) (182.7)
Future income tax expense (697.5) (487.8) (557.5) (0.9) (0.7) - (698.4) (488.5) (557.5)
- ----------------------------- ---------------------------------------------------------------------------------------
Future net cash flows 1,109.8 820.7 1,042.9 2.4 1.1 - 1,112.2 821.8 1,042.9
Less: 10% discount 600.6 440.1 582.2 0.9 0.3 - 601.5 440.4 582.2
- ----------------------------- ---------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF
DISCOUNTED FUTURE
NET CASH FLOW 509.2 380.6 460.7 1.5 0.8 - 510.7 381.4 460.7
- ----------------------------- ---------------------------------------------------------------------------------------
Future cash inflows are computed by applying year-end prices to estimated future
production of proved gas and oil reserves. Future expenditures (based on
year-end costs) represent those costs to be incurred in developing and producing
the reserves. Discounted future net cash flows are derived by applying a 10%
discount rate, as required by the Financial Accounting Standards Board, to the
future net cash flows. This data is not intended to reflect the actual economic
value of Columbia's gas and oil producing properties or the true present value
of estimated future cash flows since many arbitrary assumptions are used. The
data does provide a means of comparison among companies through the use of
standardized measurement techniques.
68
69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
A reconciliation of the components resulting in changes in the standardized
measure of discounted cash flows attributable to proved gas and oil reserves for
the three years ending December 31, follows:
United States Canada Total
- --------------------------------------------------------------------------------------------------------------------------------
($ in millions) 1999 1998 1997 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Beginning of year 380.6 460.7 433.7 0.8 - - 381.4 460.7 433.7
Gas and oil sales,
net of production costs (100.1) (91.9) (73.1) (0.4) (0.4) - (100.5) (92.3) (73.1)
Net changes in prices
and production costs 74.7 (108.5) (107.8) 0.6 - - 75.3 (108.5) (107.8)
Change in future
development costs (35.8) (10.0) (16.9) - - - (35.8) (10.0) (16.9)
Extensions, discoveries
and other additions,
net of related costs 107.5 77.5 51.9 0.6 - - 108.1 77.5 51.9
Revisions of previous
estimates, net of
related costs 33.7 (18.0) 64.0 0.1 - - 33.8 (18.0) 64.0
Sales of reserves-in-place (2.9) (12.0) (4.1) - - - (2.9) (12.0) (4.1)
Purchases of reserves-in-
place 54.6 - 67.0 - 1.7 - 54.6 1.7 67.0
Accretion of discount 60.0 70.1 64.3 0.1 - - 60.1 70.1 64.3
Net change in income taxes (91.3) 21.1 (30.5) (0.2) (0.5) - (91.5) 20.6 (30.5)
Timing of production
and other changes 28.2 (8.4) 12.2 (0.1) - - 28.1 (8.4) 12.2
- ---------------------------------------------------------------------------------------------------------------------------------
END OF YEAR 509.2 380.6 460.7 1.5 0.8 - 510.7 381.4 460.7
- ---------------------------------------------------------------------------------------------------------------------------------
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Schedule V
VALUATION AND QUALIFYING ACCOUNTS
Columbia Energy Group and Subsidiaries
Year Ended December 31,
($ in millions)
Additions - Charged to
---------------------------------
Beginning Other Ending
Description Balance Income Accounts (a) Deductions (b) Balance
- ----------------------------------------------------------------------------------------------------------------------------------
Reserves deducted in the balance sheet
from the assets to which they apply:
Allowance for doubtful accounts
1999 13.9 24.8 31.8 54.7 15.8
1998 16.6 19.2 26.8 48.7 13.9
1997 15.6 27.9 30.5 57.4 16.6
- ----------------------------------------------------------------------------------------------------------------------------------
(a) Primarily reflects reclassifications to a regulatory asset of the
uncollectible accounts related to the Percent of Income Plan (PIP) of Columbia
Gas of Ohio, Inc.
(b) Principally reflects amounts charged off as uncollectible less amounts
recovered.
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ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
There has not been a change of accountants nor any disagreements concerning
accounting and financial disclosure within the past two years.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Certain information required by this item is contained in Columbia's Proxy
Statement related to the 2000 Annual Meeting of Stockholders, to be filed
pursuant to Section 14 of the Securities Exchange Act of 1934 and is
incorporated herein by reference.
Information regarding Columbia's current executive officers, is as follows:
OLIVER G. RICHARD III, 47, Chairman, President and Chief Executive Officer of
Columbia (since April 28, 1995). Chairman of New Jersey Resources Corporation
from 1992 to 1995; President and Chief Executive Officer from 1991 to 1995.
President and Chief Executive Officer of Northern Natural Gas Company from 1989
to 1991. Senior Vice President and subsequently Executive Vice President of
Enron Gas Pipeline Group from 1987 to 1989. Vice President and General Counsel
of Tenngasco, a subsidiary of Tenneco Corporation, from 1985 to 1987. Federal
Energy Regulatory Commission Commissioner from 1982 to 1985.
PETER M. SCHWOLSKY, 53, Senior Vice President and Chief Legal Officer of
Columbia and Columbia Energy Group Service Corporation since August 1995. Senior
Vice President from June 1995 to August 1995. Executive Vice President, Law and
Corporate Development, for New Jersey Resources Corporation from 1991 to 1995.
Of counsel and then Partner with Steptoe & Johnson from 1986 to 1991.
MICHAEL W. O'DONNELL, 55, Senior Vice President and Chief Financial Officer of
Columbia and Columbia Energy Group Service Corporation since October 1993.
Senior Vice President and Assistant Chief Financial Officer of Columbia and
Columbia Energy Group Service Corporation from 1989 to 1993.
CATHERINE GOOD ABBOTT, 49, Chief Executive Officer and President of Columbia Gas
Transmission Corporation and Chief Executive Officer of Columbia Gulf
Transmission Company since January 1996. Principal with Gem Energy Consulting,
Inc. from 1995 to January 1996. Vice President for various business units of
Enron Corporation from 1985 to 1995.
PATRICIA A. HAMMICK, 53, Senior Vice President for Strategy and Communications
for Columbia since May 1998. Vice President, Strategy Implementation from 1997
through May 1998. Vice President of the Natural Gas Supply Association from 1983
through 1996. Manager, Energy Liaison for the Gulf Oil Exploration and
Production Company from 1979 to 1983.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in Columbia's Proxy Statement
related to the 2000 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is contained in Columbia's Proxy Statement
related to the 2000 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is contained in Columbia's Proxy Statement
related to the 2000 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
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72
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Exhibits
Reference is made to pages 75 through 77 for the list of exhibits filed as part
of this Annual Report on Form 10-K.
Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain
instruments representing long-term debt of Columbia or its subsidiaries have not
been included as Exhibits because such debt does not exceed 10% of the total
assets of Columbia and its subsidiaries on a consolidated basis. Columbia agrees
to furnish a copy of any such instrument to the U.S. Securities and Exchange
Commission upon request.
Financial Statement Schedules
All of the financial statements and financial statement schedules filed as a
part of the Annual Report on Form 10-K are included in Item 8.
Reports on Form 8-K
Financial
Item Statements
Reported Included Date of Event Date Filed
5 Yes* October 21, 1999 October 21, 1999
5 No October 24, 1999 October 26, 1999
* Summary of Financial and Operational data for three and nine months ended
September 30, 1999.
Undertaking made in Connection with 1933 Act Compliance on Form S-8
For purposes of complying with the amendments to the rules governing Form S-8
under the Securities Act of 1933, as amended (the Act), Columbia undertakes the
following, which is incorporated by reference into the registration statements
on Form S-8, Nos. 333-80797 (filed June 6, 1999), 333-03869 (filed May 16, 1996)
and 33-42776 (filed September 13, 1991).
Insofar as indemnification for liabilities arising under the Act may be
permitted to directors, officers and controlling persons of the registrant
pursuant to the foregoing provisions, or otherwise, the registrant has been
advised that in the opinion of the U.S. Securities and Exchange Commission such
indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the questions whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.
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73
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.
COLUMBIA ENERGY GROUP
-----------------------
(Registrant)
Dated: March 2, 2000
By:/s/Oliver G. Richard III
-----------------------
(Oliver G. Richard III)
Director (Principal
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 and on the dates indicated.
March 2, 2000 /s/ Oliver G. Richard III
-------------------------
Oliver G. Richard III
Director (Principal
Executive Officer)
March 2, 2000 /s/ Richard F. Albosta
-------------------------
Richard F. Albosta
Director
March 2, 2000 /s/ Robert H. Beeby
-------------------------
Robert H. Beeby
Director
March 2, 2000 /s/ Wilson K. Cadman
-------------------------
Wilson K. Cadman
Director
March 2, 2000 /s/ Jeffrey W. Grossman
-------------------------
Jeffrey W. Grossman
Vice President & Controller
(Principal Accounting Officer)
March 2, 2000 /s/ James P. Heffernan
-------------------------
James P. Heffernan
Director
March 2, 2000 /s/ Karen L. Hendricks
-------------------------
Karen L. Hendricks
Director
March 2, 2000 /s/ Malcolm T. Hopkins
-------------------------
Malcolm T. Hopkins
Director
March 2, 2000 /s/ J. Bennett Johnston
-------------------------
J. Bennett Johnston
Director
March 2, 2000 /s/ Malcolm Jozoff
-------------------------
Malcolm Jozoff
Director
March 2, 2000 /s/ William E. Lavery
-------------------------
William E. Lavery
Director
March 2, 2000 /s/ Gerald E. Mayo
-------------------------
Gerald E. Mayo
Director
March 2, 2000 /s/ Michael W. O'Donnell
-------------------------
Michael W. O'Donnell
Senior Vice President
(Chief Financial Officer)
March 2, 2000 /s/ Douglas E. Olesen
-------------------------
Douglas E. Olesen
Director
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EXHIBIT INDEX
Reference is made in the two right-hand columns below to those
exhibits which have heretofore been filed with the U.S. Securities and
Exchange Commission. Exhibits so referred to are incorporated herein by
reference.
Reference
File No. Exhibit
2-A* - Agreement and Plan of Merger dated February 27, 2000 between
Columbia Energy Group and NiSource Inc.
3-A - Restated Certificate of Incorporation of The Columbia 1-1098 3-A
Gas System, Inc., as amended dated as of November 28, 1995.
3-B - By-Laws of The Columbia Gas System, Inc., as amended dated 1-1098 3-B
November 18, 1987.
3-C - Certificate of Ownership and Merger, Merging Columbia 1-1098 3-C
Energy Group, Inc. into The Columbia Gas System, Inc.
3-D* - Amended and Restated By-Laws of Columbia Energy Group as of
February 22, 2000.
4-A - Indenture between The Columbia Gas System, Inc. 33-64555 4-S
and Marine Midland Bank, N.A. Trustee, dated as of
November 28, 1995.
4-B - First Supplemental Indenture, between The Columbia Gas 33-64555 4-T
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-C - Second Supplemental Indenture, between The Columbia Gas 33-64555 4-U
System, Inc., and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-D - Third Supplemental Indenture, between The Columbia Gas 33-64555 4-V
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-E - Fourth Supplemental Indenture, between The Columbia Gas 33-64555 4-W
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-F - Fifth Supplemental Indenture, between The Columbia Gas 33-64555 4-X
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-G - Sixth Supplemental Indenture, between The Columbia Gas 33-64555 4-Y
System, Inc. and Marine Midland Bank, N.A. Trustee, dated
as of November 28, 1995.
4-H - Seventh Supplemental Indenture, between The Columbia 33-64555 4-Z
Gas System, Inc. and Marine Midland Bank, N.A., Trustee,
dated as of November 28, 1995.
4-I - Instrument of Resignation, Appointment and Acceptance dated as 1-1098 4-I
of March 1, 1999, between Columbia Energy Group and Marine
Midland Bank, as Resigning Trustee and The First National Bank
of Chicago, as Successor Trustee
10-P(a) - Pension Restoration Plan of The Columbia Gas 1-1098 10-P
System, Inc., amended October 9, 1991.
10-Q(a) - Thrift Restoration Plan of The Columbia Gas 1-1098 10-Q
System, Inc. dated January 1, 1989.
10-T - Agreement and Bridge Agreement dated 1-1098 10-T
December 1, 1993, between Columbia Gas
Transmission Corporation and Consol
Pennsylvania Coal Company.
10-AE - U.S. Environmental Protection Agency Administrative 1-1098 10-AE
Order by Consent for Removal Actions for Columbia Gas
Transmission Corporation dated September 22,1994.
10-AF - Amended and Restated Indenture of Mortgage and 1-1098 10-AF
Deed of Trust by Columbia Gas Transmission
Corporation to Wilmington Trust Company,
dated as of November 28, 1995
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
* Filed herewith.
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75
EXHIBIT INDEX (continued)
Reference
File No. Exhibit
10-BB(a) - Annual Incentive Compensation Plan of The Columbia Gas 1-1098 10-BB
System, Inc., as amended, dated as of November 16, 1988.
10-BC(a) - Employment Agreement between Oliver G. Richard III 1-1098 10-BC
and The Columbia Gas System, Inc., dated March 15, 1995.
10-BE(a) - Employment Agreement between Peter M. Schwolsky 1-1098 10-BE
and The Columbia Gas System, Inc., dated May 30, 1995.
10-BF(a) - Employment Agreement between Catherine Good Abbott and The 1-1098 10-BF
Columbia Gas System, Inc., dated January 17, 1996.
10-BU - Share Sale and Purchase Agreement between The 1-1098 10-BU
Columbia Gas System, Inc. and Anderson Exploration
Ltd. dated November 25, 1991.
10-BV - Security Agreement dated as of January 15, 1992, 1-1098 10-BV
between The Columbia Gas System, Inc. and
Anderson Exploration Ltd. and Montreal Trust
Company of Canada.
10-BW - Kotaneelee Litigation Indemnity Agreement dated 1-1098 10-BW
as of December 31, 1991, among The Columbia
Gas System, Inc. and Columbia Gas Development
of Canada Ltd. and Anderson Exploration Ltd.
10-BX - Specified Litigation Indemnity Agreement made 1-1098 10-BX
as of December 31, 1991, among The Columbia
Gas System, Inc. and Columbia Gas Development
of Canada Ltd. and Anderson Exploration Ltd.
10-BY(a) - Columbia Gas Restoration Security Trust 1-1098 10-BY
Agreement dated June 1, 1991, with Dauphin
Deposit Bank and Trust Company.
10-CA(a) - The Columbia Gas System, Inc. Retirement Plan 1-1098 10-CA
for Outside Directors, as amended, August 21, 1991.
10-CB - Credit Agreement, dated as of November 28, 1995, 1-1098 10-CB
among The Columbia Gas System, Inc., certain banks party
thereto and Citibank, N.A.
10-CC - First Amendment and Supplement to Credit 1-1098 10-CC
Agreement, dated December 6, 1995
10-CD - Credit Agreement for $450,000,000, dated March 11, 1998, 1-1098 10-CD
among Columbia Energy Group and certain banks party thereto
and Citibank, N.A. as Administrative and Syndication Agent.
10-CE - Credit Agreement for $900,000,000, dated March 11, 1998, 1-1098 10-CE
among Columbia Energy Group and certain banks party thereto
and Citibank, N.A. as Administrative and Syndication Agent.
10-CF - Memorandum of Understanding among the Millennium Pipeline 1-1098 10-CF
Project partners (Columbia Transmission, West Coast Energy, MCN
Investment Corp. and TransCanada Pipelines Limited) dated
December 1, 1997.
10-CG - Agreement of Limited Partnership of Millennium Pipeline 1-1098 10-CG
Company, L.P. dated May 31, 1998.
10-CH - Contribution Agreement Between Columbia Gas Transmission 1-1098 1-1098 10-CH
10-CH Corporation and Millennium Pipeline Company, L.P. dated
July 31, 1998
10-CI - Regulations of Millennium Pipeline Management Company, L.L.C. 1-1098 10-CI
dated May 31, 1998
10-CJ - Amended and Restated Agreement of Cove Point 1-1098 10-CJ
LNG Limited Partnership between Columbia LNG and
PEPCO Energy Company, Inc. dated January 27, 1994.
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
75
76
EXHIBIT INDEX (continued)
Reference
File No. Exhibit
10-CK - Amended and Restated 364-Day Credit Agreement among Columbia 1-1098 10-CK
Energy Group and certain banks party thereto and Citibank, N.
A. as Administrative and Syndication Agent dated as of
March 10, 1999.
10-CM - Plan of Reorganization for Columbia Gas Transmission 1-1098 10-CM
Corporation 1-1098 10-CM as filed with the United States
Bankruptcy Court for the District of Delaware on January 18,
1994.
10-CO* - Amendment No. 1 to the $450,000,000 Amended and Restated
364-Day Credit Agreement, dated as of March 10,1999, among
Columbia Energy Group and certain banks party thereto and
Citibank N.A. as administrative and syndication agent.
10-CP* - Amendment No. 1 to the $900,000,000 Credit Agreement, dated
as of March 11,1999, among Columbia Energy Group and certain
banks party thereto and Citibank N.A. as administrative and
syndication agent.
12 * - Statements of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends.
21 * - Subsidiaries of Columbia Energy Group
23-A * - Written consent, dated January 24, 2000, to the filing and use
of information contained in such letter report, in Reports and
Registration Statements filed during 1999, of Ryder Scott
Company Petroleum Engineers, independent petroleum and natural
gas consultants.
23-B * - Written consent of Arthur Andersen LLP, independent public
accountants, to the incorporation by reference of their report
included in the 1999 Annual Report on Form 10-K of Columbia
Energy Group and their report included in Columbia Energy
Group's 1999 Annual Report to Shareholders in the registration
Statements on Form S-3 (File No. 33-64555 and Form S-8 (File
Nos. 333-80797, 333-03869 and 33-42776).
23-C* Written consent, dated January 20, 2000, to the filing and
use of information contained in such letter report, in Reports
and Registration Statements filed during 1999, of Sproule
Associates Limited, independent petroleum and natural gas
consultants.
27 * - Financial Data Schedule for the period ended December 31, 1999.
* Filed herewith.
76