Back to GetFilings.com
1
Commission File No. 1-1098
As filed with the United States Securities and
Exchange Commission on March 26, 1999.
================================================================================
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, 1998
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 (I.R.S. Employer
incorporation or organization) (Identification No.)
13880 Dulles Corner Lane, Herndon, VA 20171-4600
- ----------------------------------------- --------------------
(Address of principal executive officers) (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, $10 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. |X|
The aggregate market value of the outstanding common shares of the Registrant
held by nonaffiliates as of February 28, 1999, was $4,189,550,000. 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 February
28, 1999, was: Common Stock $10 Par Value: 83,507,697 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 1999 Annual Meeting of
Stockholders.
2
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........................... 12
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters..... 12
Item 6. Selected Financial Data....................................................... 13
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................................... 15
Item 8. Financial Statements and Supplementary Data................................... 40
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure.......................................................... 71
Part III
Item 10. Directors and Executive Officers of the Registrant............................ 71
Item 11. Executive Compensation........................................................ 71
Item 12. Security Ownership of Certain Beneficial Owners and Management................ 71
Item 13. Certain Relationships and Related Transactions................................ 71
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............... 72
Undertaking made in Connection with 1933 Act Compliance on Form S-8.................... 72
Signatures............................................................................. 73
Exhibits............................................................................... 74
2
3
PART 1
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 marketing of natural gas and electricity, the
generation of electricity, primarily fueled by natural gas, and the distribution
of propane. 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 18 direct
subsidiaries. Columbia owns all of the securities of these direct subsidiaries
except for approximately 8 percent of the stock in Columbia LNG Corporation.
Columbia and its subsidiaries are sometimes collectively referred to herein as
the Columbia Group.
On January 20, 1998, Columbia announced that its name had been changed from The
Columbia Gas System, Inc. to Columbia Energy Group to better reflect its
expanded participation in the energy marketplace.
Columbia and its principal pipeline subsidiary, Columbia Gas Transmission
Corporation (Columbia Transmission), emerged from bankruptcy on November 28,
1995, after filing separate petitions for protection under Chapter 11 of the
Federal Bankruptcy Code (Bankruptcy Code) on July 31, 1991. During the
bankruptcy period, both Columbia and Columbia Transmission were
debtors-in-possession under the Bankruptcy Code and continued to operate their
businesses in the normal course subject to the jurisdiction of the United States
Bankruptcy Court for the District of Delaware.
Transmission and Storage Operations
Columbia's two interstate pipeline subsidiaries, Columbia Transmission
and Columbia Gulf Transmission Company (Columbia Gulf), operate a 16,700-mile
pipeline network 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 fifteen
northeastern, midatlantic, 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).
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.
During 1998, Columbia Transmission continued construction of the
largest ever expansion of its storage and transportation system. In April 1998,
the second phase of storage service began and transportation service started in
November 1998. Upon completion, which is expected in 1999, the expansion will
add approximately 500,000 Mcf per day of firm service 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 per day of natural gas from
the Lake Erie region to eastern markets. For additional information regarding
the transmission and storage operation's expansion projects see Item 7, page
22.
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 32,000 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 "Competition" on page 27 for additional information.
3
4
ITEM 1. BUSINESS (Continued)
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, 1998, Columbia
Resources held interests in approximately 2.7 million net acres of gas and oil
leases and had proved gas reserves of 802 billion cubic feet of natural gas
equivalent. In August 1997, Columbia Resources acquired Alamco, Inc. (Alamco),
an Appalachian gas and oil exploration and development company. During the first
quarter of 1998, Columbia Resources purchased 26 producing wells and
approximately 5,000 undeveloped acres in Ontario, Canada. Through its operations
in north-central West Virginia, southern Kentucky and northern Tennessee,
Columbia Resources is one of the largest-volume independent natural gas and oil
producers in the Appalachian Basin. For additional information, see Item 7, page
32.
Marketing Operations
Columbia Energy Services Corporation (Columbia Energy Services), and its
subsidiaries conduct Columbia's nonregulated natural gas and electric power
marketing operations and provide an array of energy supply and fuel management
services to distribution companies, independent power producers and other large
end-users both on and off Columbia's transmission and distribution pipeline
systems. Columbia Energy Services is also providing natural gas supplies to
retail customers as a result of the unbundling of services that is occurring at
the local distribution level. Columbia Energy Services, through its subsidiary,
Columbia Service Partners, Inc. (Columbia Service), provides a variety of
energy-related services to both homeowners and businesses. In 1997, Columbia
Energy Services acquired PennUnion Energy Services L.L.C. (PennUnion), an
energy-marketing affiliate of the Pennzoil Company. See Item 7, page 34, for
additional information.
Propane, Power Generation and LNG Operations
Columbia Propane Corporation (Columbia Propane) sells propane at wholesale and
retail to nearly 113,750 customers in parts of 10 states and the District of
Columbia. In 1998, Columbia Propane purchased the propane assets of three
companies that added approximately 12,500 new customers and 6.4 million gallons
of annual propane sales to Columbia Propane.
Columbia Electric Corporation's (Columbia Electric) primary focus has been the
development, ownership and operation of natural gas-fueled cogeneration power
plants that sell electric power to local electric utilities under long-term
contracts. Columbia Electric is part owner in three cogeneration projects. These
facilities produce both electricity and useful thermal energy fueled principally
by natural gas. Columbia Electric holds various interests in these facilities
that have a total capacity of approximately 250 megawatts.
In June 1998, Columbia Electric and LG&E Power Inc., a subsidiary of LG&E Energy
Corporation, announced an agreement for Columbia to participate in the
development of a gas-fired cogeneration project that would have a total
equivalent capacity of approximately 550 megawatts. The facility will provide
steam and electric services to a Reynolds Metals plant in Gregory, Texas, and
will also provide electricity to the Texas energy market. Construction began in
August 1998 and financing for the $257 million project was secured in November
of 1998.
In January 1998, Columbia Electric and Westcoast Energy Inc. signed a joint
ownership agreement to develop three gas-fired electric generation plants by
2001. In total, the three plants would provide approximately 1,000 megawatts of
electricity using approximately 160 MMcf per day of natural gas. In August 1998,
a site was purchased in Pennsylvania to build the first plant that will cost
about $300 million to develop and would produce 500 megawatts of electricity and
consume approximately 80 MMcf per day of natural gas. Each of the sponsors will
own a 50% interest in the project. The exact locations of the other two plants
have yet to be determined.
Columbia LNG Corporation is a partner with Potomac Electric Power Company in the
Cove Point LNG Limited Partnership (Partnership). The Partnership owns one of
the largest natural gas peaking and storage facilities in the United States
located in Cove Point, Maryland. The facility has the capacity to liquefy
natural gas at a rate of 15,000 Mcf of natural gas per day. The facility enables
liquefied natural gas 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 services and other
microwave radio service licensees in locating and constructing antenna
facilities.
Columbia Transmission Communications Corporation, another Columbia subsidiary,
is involved in the development of a dark fiber optics network for voice and data
communications.
4
5
ITEM 1. BUSINESS (Continued)
For additional discussion of the Columbia Group's business segments, including
financial information for the last three fiscal years, see Item 7, pages 22
through 38 and Note 16 on pages 64 through 65 of Item 8.
Competition and Business Strategies
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 this period, local distribution
(LDC) customers and marketers began to purchase gas directly from producers and
marketers and an open competitive market for gas supplies 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. Open access to interstate transmission of
electricity was approved by the FERC in 1997 and is providing for increased
competition in the market for electricity as well. For additional information
regarding competition, see Item 7.
In order to capitalize on the opportunities presented by this increasingly
competitive environment, Columbia's management has been implementing a more
responsive, entrepreneurial, customer-focused organization that will utilize
Columbia's core asset strengths, its expansive customer base and its knowledge
and experience in the energy markets and expects to establish Columbia as a
"total energy company," a leading provider of energy and energy-related
services.
An integral part of Columbia's financial strategy is the application of a value
added approach, called Columbia Value Added (CVA), to all of its businesses. CVA
is a financial process as well as a financial measure that determines whether
the anticipated return on a business activity or project exceeds its risk
adjusted capital cost. All discretionary capital expenditures are subject to the
CVA process. CVA is also being employed in Columbia's strategic planning process
and is one of the tools used to set management compensation levels.
One of management's objectives is to continue to improve the quality of its
credit rating and to better position Columbia to take advantage of business
opportunities as they arise. To further enhance its financial flexibility,
Columbia has a $900 million five-year revolving credit facility and a $450
million 364-day revolving credit facility with a one-year loan option. The
five-year facility provides for the issuance of up to $300 million of letters of
credit. In 1998, Moody's Investors Service, Inc. (Moody's) and Fitch Investors
Service (Fitch), upgraded Columbia's long-term debt rating to A3 and A,
respectively. Standard & Poor's Ratings Group (S&P) rates Columbia's long-term
debt at BBB+. Columbia's commercial paper ratings are F-1 by Fitch, P-2 by
Moody's and A-2 by S&P.
The foregoing discussion and Item 3 include statements regarding market risk
sensitive instruments and contains "forward-looking statements," within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Investors and prospective investors should
understand that several 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 herein. These
forward-looking statements include, but are not limited to, statements
concerning Columbia's plans, objectives, expected performance, expenditures and
recovery of expenditures through rates, stated on either a consolidated or
segment basis, and including 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, competition,
weather, regulatory and legislative changes as well as changes in general
economic and capital and commodity market conditions many of which are beyond
the control of Columbia. In addition, the relative contributions to
profitability by 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 at
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 these rating agencies. Credit
5
6
ITEM 1. BUSINESS (Continued)
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 February 28, 1999, the Columbia Group had 8,564 full-time employees of
which 1,715 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 24 and 29, and in Item 8, Note 13(H) on
page 62.
For a listing of the direct subsidiaries of Columbia refer to Exhibit 21.
6
7
ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed below and
on page 8 and page 48 of Item 8 under Note 1(F). Assets under lien and other
guarantees are described on page 61 in Note 13D 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, 1998
Developed Acreage Undeveloped Acreage
---------------------- ----------------------
Gross Net Gross Net
----- --- ----- ---
United States .. 1,431,245 1,407,557 842,405 721,999
Canada ......... -- -- 5,432 4,002
--------- --------- ------- -------
Total .......... 1,431,245 1,407,557 847,837 726,001
========= ========= ======= =======
Net Wells Completed - 12 Months Ended December 31,
Exploratory Development Total
------------------- -------------------- ---------------------
Productive Dry Productive Dry Productive(a) Dry
---------- --- ---------- --- ------------- ---
United States ..
1998 ...... 5 1 136 32 141 33
1997 ...... -- -- 84 18 84 18
1996 ...... -- -- 19 18 19 8
Canada .........
1998 ...... -- 1 -- 1 -- 2
Productive and Drilling Wells - At December 31, 1998
Production Wells
------------------------------------------------------
Gross Net Wells Drilling
----------------------- --------------------- ------------------
Gas Oil Gas Oil Gross Net
--- --- --- --- ----- ---
United States .. 7,059(b) 126 6,650 72 84 61
Canada ......... 14 11 7 5 4 3
--- ----- -- -- --
Total .......... 7,073 137 6,657 77 88 64
===== === ===== == == ==
(a) Includes 1 net horizontal well in 1996.
(b) Includes 600 multiple completion gas wells, all of which are included as
single wells in the table. Also includes 1 gross productive horizontal
well.
7
8
ITEM 2. PROPERTIES (continued)
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1998
Miles of Pipeline
Underground Storage ------------------------------------------------
----------------------------- Gathering
Subsidiaries State Acreage Wells and Storage Transmission Distribution
------------ ----- ------- ----- ----------- ------------ ------------
Columbia Gas of Kentucky, Inc. KY - - - - 2,404
Columbia Gas of Maryland, Inc. MD - - - - 595
Columbia Gas of Ohio, Inc. OH - - - - 18,140
Columbia Gas of Pennsylvania, Inc. PA 3,300 8 4 - 6,895
Columbia Gas of Virginia, Inc. VA - - - - 3,960
Columbia Gas Transmission Corporation DE - - - 3 -
KY - - 2 711 -
MD 945 - 5 229 -
NJ - - - 69 -
NY 26,084 143 55 486 -
NC - - - 1 -
OH 486,517 2,472 972 4,028 -
PA 63,268 240 570 2,045 -
VA - - - 1,123 -
WV 294,268 809 715 2,445 -
Columbia Gulf Transmission Company AR - - - 8 -
KY - - - 716 -
LA - - - 1,480 -
MS - - - 659 -
TN - - - 556 -
TX - - - 44 -
WY - - - 10 -
Columbia Energy Resources, Inc. KY - - 1,882 - -
MI - - 6 - -
NY - - 34 - -
OH - - 118 - -
PA - - 37 - -
TN - - - - -
VA - - 394 - -
WV - - 2,539 - -
Columbia Pipeline Company DE - - 3 - -
Columbia LNG Corporation MD - - - 48 -
VA - - - 39 -
------- ----- ----- ------ ------
Total 874,382 3,672 7,336 14,700 31,994
======= ===== ===== ====== ======
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 - -
7 18,270
1 12,000
- -
4 6,040
1 1,200
27 102,532
27 68,913
11 79,480
45 311,874
Columbia Gulf Transmission Company - -
2 70,000
5 192,500
3 121,400
2 85,600
- -
- -
Columbia Energy Resources, Inc. 6 210
- -
- -
1 10
- -
2 100
- -
7 211
Columbia Pipeline Company - -
Columbia LNG Corporation - -
- -
--- ---------
Total 152 1,071,140
=== =========
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.
8
9
I. Purchase and Production Matters
A. Estimation Proceedings. Claims by certain producers for damages resulting
from the rejection of gas purchase contracts remain unresolved as discussed
in Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations section of this Report.
B. New Ulm and Fox v. Mobil Oil Corp., Columbia Gas Transmission Corp. and
Columbia Gulf Transmission Co., C.A. No. 88-V-655 (155th Judicial Dist. Ct.
of Austin County, TX). As reported in the Annual Report on Form 10-K for
1997, Columbia Transmission and New Ulm settled the litigation and New
Ulm's claims for a proposed allowed amount of $2.25 million in December
1997, subject to Columbia Transmission's Plan of Reorganization. The
Bankruptcy Court approved the settlement on January 26, 1998. This matter
is now concluded.
C. 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.). On November 16,
1988, New Bremen filed a complaint alleging it is entitled to a higher
price than the market-out price Columbia Transmission paid for past periods
under the same gas purchase contract price provision involved in the New
Ulm case discussed above. On January 10, 1989, Columbia Transmission
removed the case to the United States District Court for the Southern
District of Texas (No. H-89-0072).
By order entered December 7, 1992, the Bankruptcy Court modified the
automatic stay provided under the Bankruptcy Code to allow the U.S.
District Court to decide the pending motions for summary judgment regarding
a contract interpretation issue raised by both parties. Other issues raised
by New Bremen's claim and Columbia Transmission's response thereto were
referred to the claims mediator. On August 11, 1995, an order was entered
granting Columbia Transmission's motion for partial summary judgment and
denying New Bremen's motion for partial summary judgment on the issue of
contract interpretation. On August 29, 1995, the U.S. District Court denied
New Bremen's motion to withdraw and set aside its August 11, 1995 order,
but stated that it would withdraw and vacate its order if the Bankruptcy
Court determined that it was in violation of the automatic stay. On
November 2, 1995, the Bankruptcy Court denied New Bremen's motion for an
order that the August 11, 1995 order was a violation of the automatic stay.
The U.S. District Court, on March 12, 1996, acting upon a motion filed by
Columbia Transmission, entered an order finding that there was no just
reason to delay entry of judgment and therefore entered final judgment of
its August 11, 1995 order which granted Columbia Transmission's motion for
partial summary judgment.
New Bremen appealed the U.S. District Court's grant of partial summary
judgment to the U.S. Court of Appeals for the Fifth Circuit. On February
10, 1997, the Fifth Circuit denied New Bremen's appeal and upheld the U. S.
District Court's grant of partial summary judgment in favor of Columbia
Transmission on the contract pricing issue. On February 3, 1997, the claims
mediator issued a recommendation as to issues not resolved by the decisions
of the U. S. District Court and the Fifth Circuit Court of Appeals. On
February 25, 1997, Columbia Transmission filed a motion with the Bankruptcy
Court seeking to have New Bremen's claim allowed by the Bankruptcy Court in
accordance with the Fifth Circuit decision and the claims mediator's report
and recommendations issued in the claims estimation proceedings (resolving
issues not covered by the Fifth Circuit decision).
On July 24, 1998, the Bankruptcy Court entered an Order allowing the claim
of New Bremen Corporation in accordance with the Claims Mediator's Report
and Recommendations and the decision of the U.S. Fifth Circuit Court of
Appeals. New Bremen failed to file a timely notice of appeal. On August 21,
1998, New Bremen filed a motion to extend its time for filing on the
grounds of excusable neglect. On August 24, 1998, the Bankruptcy Court
granted the motion and provided 10 days for New Bremen to file a notice of
appeal. On August 28, 1998, New Bremen filed a notice of appeal to the U.S.
District Court for the District of Delaware. The parties have executed a
settlement agreement, subject to approval by the Bankruptcy Court. The
completion of the briefing of the appeal has been adjourned until April 30,
1999, to allow for Bankruptcy Court approval of the settlement.
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
9
10
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.
III. Other
A. 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 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. Due to the complex nature of the
litigation, Columbia cannot predict the length of the trial. 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).
B. 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 issued a subpoena for 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. At this time Columbia is unable to determine the
likelihood or magnitude of any penalties that might be assessed.
C. 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). In the Settlement of Columbia Transmission's last
rate case in Docket No. RP95-408, approved by the FERC on April 17, 1997,
Columbia Transmission, MarkWest Hydrocarbon, Inc. (MarkWest) and other
parties agreed that Columbia Transmission's gathering and products
extraction rates and
10
11
services would be "unbundled" in compliance with Order No. 636 and that
MarkWest would acquire Columbia Transmission's interests in certain
products extraction facilities and provide gas processing services to
certain shippers on Columbia Transmission's system. In February 1998,
negotiations surrounding the transfer of facilities and processing services
to MarkWest reached an impasse, resulting in an arbitration proceeding and
a court proceeding, both of which are discussed below. Columbia
Transmission believes MarkWest's claims are essentially without merit, and
that any financial consequence to Columbia Transmission will not be
material. On September 16, 1998, the FERC issued an order pursuant to which
Columbia Transmission will retain certain quantities of gas from its
customers through its retainage adjustment mechanism but not deliver those
quantities to MarkWest pending resolution of the court and arbitration
proceedings. On December 7, 1998, MarkWest and Columbia Transmission
entered into a "standstill" agreement under which the parties essentially
agreed to continue the current operational status quo until the earlier of
a ruling by the Panel (as defined below) or July 1, 1999.
Arbitration Proceeding. On February 13, 1998, MarkWest filed a demand for
arbitration. In response to Columbia Transmission's request, the
Arbitration Panel (Panel), by orders dated June 10 and June 16, 1998,
directed MarkWest to file a more specific statement of the claims to be
arbitrated and to explain why the claims are arbitrable. MarkWest filed an
Amended Demand for Arbitration on June 19, wherein MarkWest seeks an order,
inter alia, declaring that certain pre-settlement agreements between
Columbia Transmission and MarkWest have not terminated and that specific
performance by Columbia Transmission is required. MarkWest also alleged
tortious interference with its existing and prospective contracts,
fraudulent concealment, misrepresentation and civil conspiracy by Columbia
Transmission, Columbia and Columbia Resources to interfere with MarkWest's
business. MarkWest seeks compensatory damages for past and future losses in
an amount not less than $391.6 million as well as exemplary damages.
Columbia Transmission answered and filed contingent counterclaims on July 2
and contested the arbitrability of all but three issues. On July 29, 1998,
the Panel issued an order whereby it found to be non-arbitrable all of
MarkWest's claims except those that relate to obligations arising directly
under two of the parties' agreements, some of which Columbia Transmission
agreed were subject to arbitration. On October 30, 1998, the Panel issued
its New Ruling on Arbitrable Issues and Vacation of Ruling of July 29,
1998. The ruling was issued in response to the U.S. District Court's order
dated August 3, 1998. The panel held that certain claims regarding contract
interpretation, asserted contractual obligations, and asserted breach
thereof arising under six specific agreements, including the Settlement
Agreement in RP95-408, are arbitrable. The Panel reaffirmed its earlier
ruling that dismissed MarkWest's tortious interference, fraudulent
concealment, misrepresentation and civil conspiracy claims described above
as being non-arbitrable. The Panel's decision will reduce, by an amount
Columbia Transmission cannot determine, MarkWest's alleged damages.
Although a hearing has not yet been held, the Panel has ruled that, with
respect to certain additional issues, it will hear evidence and argument
before ruling on arbitrability.
Court Proceeding. Columbia Transmission filed a complaint against MarkWest
on April 28, 1998, in Federal District Court for the Southern District of
West Virginia seeking, inter alia, (i) a declaratory order that certain gas
processing agreements are terminated in whole or in part, (ii) a
declaratory order that MarkWest has breached the Settlement of Docket No.
RP95-408, and (iii) an injunction against MarkWest interfering with
Columbia Transmission's efforts to spin off its products extraction
business. On August 3, 1998, the U.S. District Court issued a memorandum
opinion and order granting MarkWest's motion to stay proceedings and compel
arbitration.
11
12
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 is abbreviated as either ColumEngy or ColumEgy in trading
reports. The number of record shareholders on December 31, 1998, was
approximately 35,261 and the stock closed at $57.75 on December 31, 1998, as
reflected in the New York Stock Exchange Composite Transactions as reported by
The Wall Street Journal. On February 17, 1999, Columbia declared a quarterly
dividend of $0.20 per share for the first quarter of 1999, which was declared
payable on or about March 15, 1999, to holders of record on March 1, 1999.
See Item 7 on page 21 for additional information regarding Columbia's common
stock prices and dividends.
12
13
ITEM 6. SELECTED FINANCIAL DATA
Selected Financial Data
Columbia Energy Group and Subsidiaries
($ in millions, except per share amounts) 1998 1997 1996 1995* 1994* 1993*
- -----------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA($)
Total net revenues 1,897.1 1,915.5 1,872.9 1,814.6 1,762.9 1,736.1
Earnings (Loss) before extraordinary item
and accounting changes 269.2 273.3 221.6 (432.3) 246.2 152.2
Earnings (Loss) on common stock 269.2 273.3 221.6 (360.7) 240.6 152.2
- ------------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA**
Earnings (Loss) per share of common stock($):
Before extraordinary item and accounting changes 3.23 3.29 2.75 (5.71) 3.25 2.01
Earnings (Loss) per share of common stock 3.23 3.29 2.75 (4.76) 3.17 2.01
Average common shares outstanding(000) 83,382 83,100 80,681 75,708 75,838 75,838
Diluted earnings (loss) per share of common stock($):
Before extraordinary item and accounting changes 3.21 3.27 2.74 (5.71) 3.25 2.01
Diluted earnings (loss) per share of common stock 3.21 3.27 2.74 (4.76) 3.17 2.01
Diluted average common shares(000) 83,748 83,594 80,919 75,708 75,838 75,838
Dividends:
Per share($) 0.77 0.60 0.40 - - -
Payment ratio(%) 23.8 18.2 14.5 N/A N/A N/A
- ------------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA($)
Capitalization including debt subject to Chapter 11:
Common stock equity 2,005.3 1,790.7 1,553.6 1,114.0 1,468.0 1,227.3
Preferred stock - - - 399.9 - -
Long-term debt 2,003.1 2,003.5 2,003.8 2,004.5 4.3 4.8
Short-term debt N/A N/A N/A N/A - -
Current maturities of long-term debt 0.4 0.5 0.8 0.5 1.2 1.3
Debt subject to Chapter 11 - - - - 2,317.1 2,317.1
Total 4,008.8 3,794.7 3,558.2 3,518.9 3,790.6 3,550.5
Total assets 6,968.7 6,612.3 6,004.6 6,057.0 7,164.9 6,957.9
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio(%)(including current maturities***):
Common stock equity 50.0 47.2 43.7 31.7 38.7 34.6
Preferred stock - - - 11.4 - -
Debt 50.0 52.8 56.3 56.9 61.3 65.4
Capital expenditures($) 478.7 560.3 314.8 421.8 447.2 361.3
Net cash from operations($) 761.7 468.2 477.0 (804.1) 572.8 850.4
Book value per share of common stock($)** 24.01 21.51 18.74 15.09 19.36 16.18
Return on average common equity
before extraordinary item and accounting changes(%) 14.2 16.3 16.6 (33.5) 18.3 13.2
- ------------------------------------------------------------------------------------------------------------------------------------
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 13(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 $982.9 million
including write-off of unamortized discounts on debentures, was recorded in
the fourth quarter of 1995.
** All per share amounts, average common shares outstanding and diluted average
common shares have been restated to reflect a three-for-two common stock
split, in the form of a stock dividend, effective June 15, 1998.
*** Prior to 1991, Columbia made extensive use of variable rate debt since the
associated cost was normally less than our senior long-term debt. Inclusion
of the short-term debt in years prior to 1991 makes those historical ratios
more meaningful.
13
14
ITEM 6. SELECTED FINANCIAL DATA (continued)
SELECTED FINANCIAL DATA
Columbia Energy Group and Subsidiaries
($ in millions, except per share amounts) 1992* 1991* 1990 1989 1988
- --------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total net revenues 1,622.3 1,407.2 1,499.9 1,520.3 1,335.2
Earnings (Loss) before extraordinary item
and accounting changes 90.9 (794.8) 104.7 145.8 119.0
Earnings (Loss) on common stock 51.2 (694.4) 104.7 145.8 111.1
- --------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA**
Earnings (Loss) per share of common stock ($):
Before extraordinary item and accounting changes 1.20 (10.49) 1.48 2.14 1.64
Earnings (Loss) per share of common stock 0.68 (9.16) 1.48 2.14 1.64
Average common shares outstanding (000) 75,838 75,798 70,983 68,260 67,809
Diluted earnings (loss) per share of common stock ($):
Before extraordinary item and accounting changes 1.20 (10.49) 1.47 2.13 1.64
Diluted earnings (loss) per share of common stock 0.68 (9.16) 1.47 2.13 1.64
Diluted average common shares (000) 75,838 75,798 71,133 68,537 67,809
Dividends:
Per share ($) - 0.77 1.47 1.33 1.53
Payout ratio (%) N/A N/A 99.3 62.1 93.3
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 1,075.1 1,006.9 1,757.8 1,620.3 1,552.6
Preferred stock - - - - -
Long-term debt 5.4 6.1 1,428.7 1,196.0 1,038.4
Short-term debt - N/A 735.5 634.2 697.1
Current maturities of long-term debt 1.4 2.9 35.2 47.2 52.7
Debt subject to Chapter 11 2,317.1 2,317.1 - - -
Total 3,399.0 3,333.0 3,957.2 3,497.7 3,340.8
Total assets 6,505.9 6,332.2 6,196.3 5,878.4 5,641.0
- --------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including current maturities ***):
Common stock equity 31.6 30.2 44.4 46.3 46.5
Preferred stock - - - - -
Debt 68.4 69.8 55.6 53.7 53.5
Capital expenditures ($) 299.7 381.9 629.6 473.5 307.9
Net cash from operations ($) 765.4 531.6 420.1 400.5 429.4
Book value per share of common stock ($) ** 14.18 13.28 23.22 23.67 22.79
Return on average common equity
before extraordinary item and accounting changes (%) 8.7 (57.5) 6.2 9.2 7.2
- --------------------------------------------------------------------------------------------------------------------------------
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 13(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.
Inclusion of the short-term debt in years prior to 1991 makes those
historical ratios more meaningful.
14
15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Index Page
- ----- ----
Consolidated Review............................................................................. 15
Liquidity and Capital Resources................................................................. 17
Transmission and Storage Operations............................................................. 22
Distribution Operations......................................................................... 27
Exploration and Production Operations........................................................... 32
Marketing Operations............................................................................ 34
Propane, Power Generation and LNG Operations.................................................... 37
Bankruptcy Matters.............................................................................. 39
The Management's Discussion and Analysis, including statements regarding market
risk sensitive instruments and in the section "Impact of Year 2000 on Computer
and Other Systems," 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, 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, competition, weather, impact of
the year 2000 on computer, operating and other systems, regulatory and
legislative changes as well as changes in general economic, capital and
commodity market conditions, 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 Columbia's year 2000 program, the dates on
which Columbia believes it will be completed are based on management's best
estimates, which were derived utilizing numerous assumptions of future events.
However, there can be no guarantee that these estimates will be achieved, or
that there will not be a delay in, or increased costs associated with, the
implementation of the year 2000 program. Specific factors that might cause
differences between the estimates and actual results include, but are not
limited to, the availability and cost of personnel trained in these areas, the
ability to timely locate and correct all relevant computer codes for both
information technology (IT) and non-IT systems, the nature and amount of
programming and testing required to upgrade or replace IT and non-IT systems,
timely responses to, and corrections by, third-parties and suppliers, the
ability to implement interfaces between, and among, IT and non-IT systems for
which remediation or an upgrade is performed, the nature and amount of testing,
verification and reporting required by relevant government regulatory
authorities, including federal and state utility regulatory bodies, and other
similar uncertainties.
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
Net Income
Columbia Energy Group reported net income for 1998 of $269.2 million, or $3.23
per share, a decrease of $4.1 million, or 6 cents per share, from 1997.
The decrease was due largely to the impact of record warm weather in 1998 and
the costs of Columbia's continued investment in its marketing segment. These
decreases were largely offset by 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.
Several other key items also affected both years' results. In 1998, a $16.5
million 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
15
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
$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.
Columbia's 1997 net income was $273.3 million, or $3.29 per share, up $51.7
million, or 54 cents per share, over 1996. After adjusting for unusual items,
this improvement was due in large part to lower operating costs for the
regulated subsidiaries and increased revenues from transportation and storage
services and gas management activities.
Net Revenues
Total net revenues (revenues less associated product purchased costs) of
$1,897.1 million for 1998, reflected a decrease of $18.4 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 a
$22.1 million increase in the marketing segment's gross margin due to higher gas
sales and the addition of electric power sales in 1998, as well as 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. Natural
gas sales for Columbia's marketing segment in 1998 totaled 1,581 Billion cubic
feet (Bcf), nearly twice the level for the same period last year, while its 1998
electric power sales were 14,364 Gigawatt hours.
In 1997, total net revenues were $1,915.5 million, an increase of $42.6 million
over 1996. The higher net revenues were principally due to increased sales by
the marketing segment and higher rates in effect for the distribution segment
for the recovery of increased gas costs. Also improving revenues were the
effects of regulatory settlements reached in 1997 for Columbia Transmission and
Columbia Gas of Ohio, Inc. (Columbia of Ohio) and increased off-system sales,
transportation and storage services.
Expenses
Total operating expenses of $1,357.1 million for 1998 decreased $49 million
compared to 1997, largely reflecting a reduction of $60.7 million in operation
and maintenance expense. The reduction took place despite $64.6 million of
higher operation and maintenance expenses for the marketing segment to build
infrastructure, add and retain qualified staff and record a reserve stemming
from the continuing review of that segment's financial records. The lower
operation and maintenance expense was primarily the result of 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. The transmission and storage segment's and the distribution segment's
operation and maintenance expense also decreased in 1998 as a result of cost
conservation measures and efficiencies gained through recently implemented
restructuring activities. Overall depreciation and depletion expense increased
$13.9 million due primarily to an increase in depletion expense for the
exploration and production segment 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.
Operating expenses for 1997 of $1,406.1 million were $11.4 million higher than
for 1996. Despite acquisitions made in 1997 and higher startup costs for new
services, Columbia's 1997 operation and maintenance expense decreased $3.6
million from 1996. Total operating expenses for the marketing segment rose $21.8
million due in large part to expanding the marketing segment's operations
through the acquisition of PennUnion Energy Services L.L.C. (PennUnion) and
building the segment's infrastructure to support its growth. Operation and
maintenance costs for the rate-regulated subsidiaries decreased, after adjusting
for 1997 restructuring costs and a reserve of $10.1 million for the sale of
certain pipeline facilities in New York and Pennsylvania, reflecting the
beneficial effect of implementing restructuring initiatives.
16
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Other Income (Deductions)
Twelve Months Ended December 31, (in millions) 1998 1997 1996
- ------------------------------------------------------------------------------------------------------
Interest income and other, net $ 13.4 $ 40.4 $ 26.1
Interest expense and related charges (152.4) (157.6) (166.8)
- ------------------------------------------------------------------------------------------------------
TOTAL OTHER INCOME (DEDUCTIONS) $ (139.0) $ (117.2) $ (140.7)
- ------------------------------------------------------------------------------------------------------
For 1998, Other Income (Deductions) reduced income by $139 million compared to a
reduction of $117.2 million in 1997. Interest income and other, net of $13.4
million decreased $27 million when compared to 1997, due largely to two items
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 $152.4 million in 1998 decreased $5.2 million from 1997, primarily
reflecting a reduction to 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.
When comparing 1997 to 1996, Other Income (Deductions) reduced income $117.2
million in 1997 and $140.7 million in 1996. The income improvement in 1997 was
largely due to reduced interest expense on short-term borrowings, an $8.5
million pre-tax gain for the payment received from the deactivation of the
storage field and a $9.5 million gain from the sale of Columbia's coal assets.
Income Taxes
Income tax expense for 1998 was $131.8 million, up $12.9 million from the year
earlier, primarily reflecting tax benefits recorded in 1997 not available in
1998. In addition, net income benefited from 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.
Income tax expense in 1997 increased $3 million over 1996 due to higher income
that was largely offset by the $12.8 million reduction for implementing state
tax planning initiatives, mentioned previously.
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 operations for 1998 was $761.7 million, an increase of $293.5
million over 1997. The increase primarily reflects higher prepayments received
for the future delivery of natural gas by Columbia and working capital changes,
including an increase in accounts payable, 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 the current period 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.
Net cash from operations in 1997 decreased $8.8 million from 1996 to $468.2
million primarily reflecting higher cash needs for working capital purposes. The
increased use of cash for working capital in 1997 was caused by higher accounts
receivable, offset by the receipt of cash during the year related to income tax
refunds and a switch from being underrecovered to overrecovered for the
distribution segment's gas costs. Tempering these uses of cash was the full
period effect of higher base rates for Columbia Transmission.
Columbia satisfies its liquidity requirements primarily through internally
generated funds and from the sale of commercial paper, which is supported by the
use of two unsecured bank revolving credit facilities that total $1.35 billion
(Credit Facilities). In March 1998, the Credit Facilities replaced the $1
billion five-year revolving credit facility entered into by Columbia in November
1995.
17
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Columbia's 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.
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. During 1998,
Moody's Investors Service, Inc. (Moody's) and Fitch Investors Service (Fitch)
each 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). Under the Credit Facilities, 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 December 31, 1998, Columbia had $144.8 million of commercial paper
outstanding and approximately $127 million of letters of credit issued, of which
$44.4 million were issued under the Credit Facilities.
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%.
Columbia has an effective shelf registration statement on file with the U. S.
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.
In March 1996, Columbia issued 5,750,000 shares of common stock under the shelf
registration and used the proceeds to reduce borrowings incurred under the prior
credit facility and, together with other funds, to retire $400 million of
preferred stock issued in late 1995. No further issuances of the remaining $750
million available under the shelf registration are scheduled at this time.
At its February 1999 meeting, Columbia's Board of Directors authorized the
purchase of up to $100 million of Columbia's common stock through February 29,
2000, in the open market or otherwise. The source of funds for repurchases would
consist of available funds or short-term borrowings. The timing and terms of
purchases, and the number of shares actually purchased, will be determined by
management based on market conditions and other factors. Purchased shares will
be held in treasury to be made available for general corporate purposes, or
resale at a future date, or they may be retired.
Management believes that its sources of funding are sufficient to meet
short-term and long-term liquidity needs.
Presentation of Segment Information
Columbia revised its presentation of primary business segment information
beginning with the reporting of second quarter results for 1998. Marketing
operations are now reported in a separate segment rather than the former
marketing, propane and power generation segment. Columbia LNG Corporation's
results are now reported in the propane, power generation and LNG segment,
rather than the transmission and storage segment. Prior periods have been
restated to reflect this change.
Capital Expenditures
The table below reflects actual capital expenditures by segment for 1998 and
1997 and an estimate for 1999:
(in millions) 1999 1998 1997
- -----------------------------------------------------------------------------
Transmission and Storage $237 $204 $245
Distribution 152 152 159
Exploration and Production 104 76 136*
Marketing 20 16 5
Propane, Power Generation and LNG 129 20 10
Corporate 8 11 5
- -----------------------------------------------------------------------------
TOTAL $650 $479 $560
- -----------------------------------------------------------------------------
* Does not reflect approximately $23 million of gathering facilities that
Columbia Transmission sold to Columbia Natural Resources, Inc.
18
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
For 1998, capital expenditures were $479 million, a decrease of $81 million from
1997. The Alamco acquisition represented approximately $101 million of the 1997
program. The 1998 program included $95 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. In 1998, propane acquisitions accounted for about
$19 million of the program.
For 1999, Columbia's estimated capital expenditure program of $650 million is
$171 million higher than the 1998 program. Included for the transmission and
storage segment is approximately $126 million for new business activities, such
as market expansion initiatives, and another $59 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 230 new wells. The 1999 program also includes small increases
for normal activities in the marketing segment as well as amounts for potential
acquisitions in the propane, power generation and LNG segment.
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, 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 commodity trading activities to help ensure stable cash flow,
favorable prices and margins as well as to help capture any long-term increases
in value. Financial instruments authorized for use by Columbia for commodity
trading include futures, swaps and options. Columbia Energy Services utilizes
financial instruments to help assure adequate margins on the purchase and resale
of natural gas and electric power. Columbia Resources also utilizes financial
instruments to fix prices for a portion of its future production volumes. These
positions of Columbia Resources are hedged in the marketplace through Columbia
Energy Services. Columbia Propane utilizes financial instruments to help protect
the value of inventories. See Note 1(G) in Notes to Consolidated Financial
Statements for a discussion of the accounting treatment for derivatives and Note
5 for Risk Management Activities.
In the third quarter of 1998, Columbia's policy was expanded to allow open
trading positions in electric power for its marketing segment operations to take
advantage of market information or strategic opportunities related to
electricity commodity prices and basis. Also in the third quarter, trading
activity in weather derivatives was authorized. Positions in natural gas,
electric power and weather derivatives are controlled within predetermined
limits as provided by Columbia's senior management. Columbia's policy prohibits
any Columbia subsidiary from entering into trading positions that are not
effectively connected with its business. The risks associated with these trading
activities are managed consistent with policies approved by Columbia's Board of
Directors. Market risks are monitored by an independent risk control group
operating separately from the area that creates or actively manages these risk
exposures to ensure compliance with Columbia's stated risk management policies.
Effective January 1, 1999, Columbia adopted mark-to-market accounting for all of
its gas and power marketing operations and marks all physical and financial
positions to market in accordance with the Financial Accounting Standards Board
Emerging Issues Task Force's recently issued Statement 98-10.
Columbia measures the market risk in its portfolios on a daily basis 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 commodity
market risk sensitive instruments was approximately $1.8 million as of December
31, 1998, whereas at year-end 1997 the value-at-risk was estimated at $175,000.
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, that portion of Columbia's long-term debt is now
subject to fluctuations in interest rates.
19
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Impact of Year 2000 on Computer and Other Systems
The Year 2000 issue is a worldwide concern because many existing computer
programs and certain computer hardware were initially designed without
considering the impact of the change to the year 2000. If not corrected, certain
computer, operating and other systems could fail or create erroneous results.
Columbia is evaluating its IT and non-IT systems to determine if they are year
2000 compliant and, if these systems are not year 2000 compliant, what
corrective action is necessary. IT and non-IT systems that are currently being
identified, tested and, as necessary, corrected or replaced with compliant
systems include: 1) mission critical processes that relate to the safety or
dependability of Columbia's natural gas delivery system and other core business
operations; 2) customer billing, vendor payment, shareholder records and payroll
systems; and 3) other processes relevant to Columbia's continued operations.
Embedded chips and other non-IT hardware that are found to not be year 2000
compliant are being replaced or upgraded as appropriate. To ensure timely
completion of all phases of the year 2000 project, Columbia is utilizing
external consultants with specific year 2000 expertise on certain aspects of the
project.
Columbia's year 2000 program is divided into phases that provide for the timely
assessment, remediation and testing of IT and non-IT systems as appropriate. The
assessment phase, which was completed as of December 31, 1998, covers the
inventory of systems and the determination as to where potential problems may
exist. If a system can not be determined to be either compliant or not date
sensitive, it is deemed non-compliant and scheduled for inclusion in the
remediation/testing phases. The remediation phase is for the correction of any
year 2000 compliance issues through repair or replacement. It is estimated that
this phase is approximately 61% complete for IT systems and 3% complete for
non-IT systems. The testing phase, which is estimated to be approximately 65%
and 7% complete for IT and non-IT systems, respectively, is designed to provide
assurance that the remediation effort has been successful. Critical devices are
tested regardless of whether a manufacturer/vendor has indicated that the device
was year 2000 compliant. Columbia currently has in place general contingency
plans in the event that a computer system, facility or process fails; however,
Columbia is evaluating the need for special contingency plans in the event that
a year 2000 problem should arise in spite of Columbia's efforts to ensure year
2000 compliance. Where appropriate, specific year 2000 contingency plans will be
developed for those systems that are essential to Columbia's ongoing businesses.
Contingency plans involve having alternate suppliers, processes or personnel on
stand-by for essential processes. Columbia's planning for the year 2000
contingency phase for mission critical processes began on January 1, 1999.
For the overall year 2000 project, the assessment phase is complete. The
remediation phase is anticipated to be completed by the end of the first quarter
of 1999, with the testing phase anticipated to be completed by the end of the
second quarter of 1999. Any year 2000 specific contingency plans that may be
necessary are scheduled to be completed by the end of July 1999.
Another area of concern is Columbia's exposure from third parties that may not
be year 2000 compliant. Columbia is in the process of contacting third parties
with which it conducts business to obtain assurance that they will be year 2000
compliant, utilizing letters and, where appropriate, questionnaires. Columbia
has mailed letters to many of its significant vendors and service providers and
has verbally communicated with many strategic customers to determine whether or
not interfaces with such entities are vulnerable to year 2000 problems and
whether the products and services purchased from or by such entities are year
2000 compliant. Columbia has received responses from a large number of these
third parties with many of the companies providing written assurances that they
expect to address all of their significant year 2000 issues on a timely basis. A
follow-up mailing to significant vendors and service providers that did not
initially respond, or whose responses were deemed unsatisfactory by Columbia, is
currently underway.
The total estimated cost of assessing, testing and remediating Columbia's IT and
non-IT systems for year 2000 compliance, along with the cost of developing
contingency plans, is approximately $15.6 million. The bulk of Columbia's year
2000 project budget will be applied to the remediation and testing phases. The
estimated total cost of the year 2000 project represents management's
assessment, based on information currently available, scope of the project, work
already completed and estimated remaining work. The expenditures necessary to
become year 2000 compliant will be satisfied through Columbia's cash flow from
operations.
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 has been incorporated into
Columbia's current contingency plans and the year 2000 project, management
believes that the most reasonably likely worst case year 2000 scenario would
involve minor failures that were not detected and corrected during the
20
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
project. These failures should not be of the type that could result in the
disruption of services and will, in all likelihood, be corrected quickly.
However, the failure of Columbia or a key third party supplier to correct a
material year 2000 problem could result in an interruption in, or a failure of,
certain normal business activities or operations including Columbia's ability to
deliver energy. For such a failure to be material, numerous back-up systems or
processes would also have to fail. For example, an interruption in electric
service along Columbia's pipeline system could impact the operation of one or
more compressor stations or other field facilities and equipment. This impact,
if coupled with the failure of critical back-up systems and processes, could
materially and adversely affect Columbia's operations, liquidity and financial
condition. Due to the general uncertainty inherent in the year 2000 issue, due
in part to the uncertainty of the year 2000 readiness of third party suppliers
and customers, Columbia is unable to determine at this time whether the
consequences of any likely year 2000 failures will have a material impact on
Columbia's operations, liquidity or financial condition.
Common Stock Prices and Dividends*
Market Price
Quarterly
Quarter Ended High Low Close Dividends Paid
- --------------------------------------------------------------------------------------------------------------------------
$ $ $ $
1998
December 31 60 3/4 54 1/4 57 3/4 .20
September 30 60 3/8 47 1/2 58 5/8 .20
June 30 57 11/12 50 1/3 55 5/8 .20
March 31 52 17/24 47 1/3 51 5/6 .17
- --------------------------------------------------------------------------------------------------------------------------
1997
December 31 52 5/12 46 1/3 52 3/8 .17
September 30 48 1/6 43 11/24 46 2/3 .17
June 30 44 11/12 37 1/3 43 1/2 .16
March 31 43 11/12 38 5/12 38 7/12 .10
- --------------------------------------------------------------------------------------------------------------------------
* Amounts have been restated to reflect a three-for-two common stock split, in
the form of a stock dividend, effective June 15, 1998.
21
22
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 Columbia Transmission,
Columbia Gulf Transmission Company (Columbia Gulf) and Columbia Pipeline
Company. Together they operate a 16,658 mile pipeline network extending from
offshore in the Gulf of Mexico to Lake Erie, New York and the eastern seaboard
serving 15 northeastern, midatlantic, 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 midatlantic 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.
Ten 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 have announced that
the proposed in-service date is expected to be November 1, 2000.
The current 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 continued construction of its Market Expansion project
that expands its pipeline and storage system to meet increased customer demands.
The second phase of storage service began in April 1998, and transportation
service began in November 1998. Upon completion in 1999, the expansion will add
approximately 500,000 Mcf per day of firm service to 23 customers.
The New York State Electric & Gas Corporation (NYSEG) filed an appeal with the
U. S. Court of Appeals for the District of Columbia Circuit, primarily to
challenge the FERC's approval of rolled-in pricing for the Market Expansion
project service levels. All briefing is complete with oral arguments being the
next step. NYSEG has not requested a stay of Columbia Transmission's FERC
certificate order. Accordingly, construction is proceeding.
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 system would provide additional capacity to shippers from Grand Isle by
adding approximately 600,000 Mcf per day of incremental firm transportation
capacity. This will 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, would
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 resulting from
the East Lateral expansion and the SunStar Pipeline Project. Columbia Gulf is
currently in the process of evaluating the bids.
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 which 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
22
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
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
Columbia Gulf's Rate Settlement
On April 29, 1998, the FERC approved a settlement of Columbia Gulf's general
rate case that was filed in October 1996. The active parties in the proceeding
unanimously agreed to the terms of the settlement. The approval of the
settlement, which became final May 29, 1998, did not have a material impact on
Columbia's consolidated financial results.
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. Since that time Columbia Gulf has responded to various information
requests from the FERC. In an August 8, 1997 order, the FERC approved a
stipulation and consent agreement 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. On
December 24, 1998, the FERC issued an order rejecting all substantial challenges
and reaffirmed the settlement. On January 25, 1999, a petition for clarification
or rehearing and a separate petition for rehearing of the FERC's December 24,
1998 order were filed in this proceeding. On February 19, 1999, the FERC issued
a tolling order giving itself additional time to act on the January 25, 1999
petitions. In late February 1999, five parties appealed the December 24, 1998
and August 8, 1997 FERC orders to the Court of Appeals for the District of
Columbia.
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 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 open bidding
process held in late 1997 and early 1998. Subject to regulatory approval,
construction relating to the compressor replacements is scheduled to begin in
the first quarter of 1999. The proposed in-service date for the Mainline '99
project is December 1, 1999. At its February 10, 1999, meeting the FERC adopted
an order approving Columbia Gulf's June 5, 1998 filing.
Columbia Transmission's Phase II Rate Proceeding
Columbia Transmission's rate case settlement, approved by the FERC in April
1997, provided for a hearing to address environmental cost recovery that was
excluded from the settlement. The procedural schedule established by the
presiding Administrative Law Judge provided for a hearing to commence in the
fall of 1998. 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 in principle on the overall
components of an environmental settlement. The comprehensive agreement in
principle 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. At this time, the agreement is either supported or not opposed by all
but two parties. Columbia Transmission anticipates filing a stipulation and
agreement with the FERC in the first quarter of 1999.
Challenge to Columbia Transmission's Rate Design
Pursuant to a provision of Columbia Transmission's 1997 rate settlement, the
Public Service Commission of the State of New York (PSCNY) had the right to
initiate a hearing challenging the appropriateness of the Straight Fixed
Variable (SFV) rate design methodology authorized by the FERC for Columbia
Transmission. In a decision rendered in April 1998, the presiding Administrative
Law Judge granted a motion, filed jointly by several interested parties, to
dismiss a challenge made by PSCNY. The Judge found that the PSCNY failed to
demonstrate that continued use of the SFV rate design on Columbia Transmission's
system would be unjust or unreasonable. In May 1998, the PSCNY filed an appeal
of the Administrative Law Judge's decision and on October 6, 1998, the FERC
affirmed the Judge's decision.
23
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
The PSCNY filed a limited request for rehearing of the FERC's decision on
November 5, 1998. In December 1998, the FERC issued an order denying PSCNY's
request for rehearing.
Discussions with FERC
The transmission and storage subsidiaries are in confidential and informal
discussions with the staff of the FERC 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. Because
these discussions are in a very preliminary stage, management is unable to
reasonably estimate the amount that will have to be paid pursuant to
reimbursement or other remedies.
Sale of Gathering Facilities
During 1997, Columbia Transmission sold approximately 4,500 miles of its
gathering lines of which 2,700 miles were sold to Columbia Resources.
Approximately 750 miles of gathering facilities were sold to Columbia Resources
effective January 1999. There are approximately 800 miles of gathering lines
remaining to be sold.
In addition, Columbia Transmission has agreed to sell certain natural gas
pipeline facilities that consist of approximately 341 miles of pipeline,
together with property and associated facilities, located in New York and
Pennsylvania. The sale of these facilities was approved by the FERC in an order
issued on November 4, 1998. Certain parties requested rehearing of the FERC's
decision. At its regularly scheduled meeting on February 10, 1999, the FERC
approved a draft order denying rehearing. The FERC's action on rehearing will
allow the sale to go forward as planned. The facilities are not directly
connected to Columbia Transmission's mainline system and are no longer needed by
Columbia Transmission in connection with providing services to its customers.
The sale of these assets would not have a material impact on Columbia's
consolidated financial results.
Additional Storage Base Gas Sales
As provided in Columbia Transmission's recent rate settlement, 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. Columbia Transmission has agreements to sell
approximately 6.9 Bcf of base gas volumes in the first quarter of 1999 pursuant
to the settlement agreement.
Capital Expenditure Program
The transmission and storage segment's net capital expenditure program was $204
million in 1998 and is projected to be $237 million in 1999. New business
initiatives totaled approximately $95 million in 1998 and are expected to be
$126 million in 1999. 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 15,000 liquid removal
points, approximately 2,800 mercury measurement stations and about 3,700 storage
well locations. As of December 31, 1998, field characterization has been
performed at many of these sites, and site characterization reports and
remediation plans are being prepared for submission to EPA for approval.
Significant remediation has taken place only at mercury measurement stations.
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.
As a result of 1998 activities, Columbia Transmission recorded an additional
liability of $28.8 million. Actual expenditures of approximately $16 million
during 1998 charged to the liability resulted in a remaining liability of $138.2
million. Columbia Transmission's environmental cash expenditures are expected to
be approximately $18
24
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
million in 1999 and up to $20 million annually until the AOC is satisfied. 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 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 local distribution companies 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.
Throughput for the transmission and storage segment totaled 1,197.5 Bcf for
1998, a decrease of 104 Bcf from 1997 that was in turn down 76.6 Bcf from 1996.
The lower throughput in 1998 and 1997 was primarily due to warmer weather in
Columbia Transmission's operating territory that reduced demand for natural gas.
Columbia Transmission's market area transportation declined 84.8 Bcf to 947.8
Bcf during 1998, largely due to 18% warmer weather in its market area.
Transportation volumes for 1997 of 1,032.6 Bcf decreased 69.8 Bcf from 1996
primarily due to warmer weather in early 1997 and reduced requirements from
electric cogeneration facilities during the summer.
Mainline transportation for Columbia Gulf decreased 44.2 Bcf to 563.3 Bcf in
1998, reflecting the impact of warmer weather in Columbia Transmission's
operating territory. During 1997, mainline transportation was 26.2 Bcf lower
than 1996 due to warmer weather. In addition, mainline transportation volumes
were higher in 1996 due to Columbia Gulf's system being heavily used by
customers during the summer of that year to refill depleted gas storage
inventories.
Columbia Gulf's 1998 short-haul transportation of 231.2 Bcf decreased 21.2 Bcf
from the year earlier, largely due to the unusually warm weather. Short-haul
transportation of 252.4 Bcf in 1997 was down 14.1 Bcf from 1996 primarily due to
a decline in market demand in the area south of Rayne, Louisiana.
Variations in throughput have little effect on operating income because, as a
result of FERC Order No. 636, a significant portion of the transmission and
storage segment's fixed costs is being recovered through a monthly demand
charge.
Operating Revenues
Operating revenues of $838.7 million in 1998 were essentially unchanged from the
prior year. After adjusting for the recovery of upstream transportation costs
and certain other revenues that are fully offset in operating expense, 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 due in part to Columbia Transmission's
Market Expansion project. 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 revenues increased $33.6 million to $838.6 million in 1997. After
adjusting for recovery items mentioned above, operating revenues increased $22.6
million over 1996. This increase was primarily due to recording $19.1 million of
revenues in the second quarter of 1997 for the sale of base gas volumes that
were part of Columbia Transmission's 1997 rate case settlement. Increased
transportation and storage services also contributed to the improvement.
Operating Income
Operating income for 1998 for the transmission and storage segment of $326.1
million, increased $67.8 million over 1997 due to a decline in operating
expense. Operation and maintenance expenses for 1998 declined $64.3 million
25
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
compared with 1997, primarily reflecting restructuring costs recorded in 1997
and the beneficial effect of 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 sale of certain
pipeline facilities.
Operating income for 1997 of $258.3 million, increased $52.1 million over the
previous year. This improvement reflected higher operating revenues, mentioned
above, and $18.5 million lower operating expenses due in part to lower
restructuring costs and savings achieved through the implementation of
restructuring initiatives.
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION AND STORAGE OPERATIONS
(UNAUDITED)
Year Ended December 31, (in millions) 1998 1997 1996
- ------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Transportation revenues $ 620.4 $ 622.0 $ 629.0
Storage revenues 186.0 179.8 159.5
Other revenues 32.3 36.8 16.5
- ------------------------------------------------------------------------------------------------------
Total Operating Revenues 838.7 838.6 805.0
- ------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 358.9 423.2 440.1
Depreciation 101.8 104.3 102.6
Other taxes 51.9 52.8 56.1
- ------------------------------------------------------------------------------------------------------
Total Operating Expenses 512.6 580.3 598.8
- ------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 326.1 $ 258.3 $ 206.2
- ------------------------------------------------------------------------------------------------------
TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS
1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 204.0 244.9 142.7 169.1 179.1
- ---------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Transportation
Columbia Transmission
Market area 947.8 1,032.6 1,102.4 1,106.1 1,038.6
Columbia Gulf
Mainline 563.3 607.5 633.7 605.0 590.3
Short-haul 231.2 252.4 266.5 221.4 225.4
Intrasegment eliminations (544.8) (591.0) (624.5) (596.3) (583.2)
- ---------------------------------------------------------------------------------------------------------
Total Transportation 1,197.5 1,301.5 1,378.1 1,336.2 1,271.1
Sales - - - - 0.9
- ---------------------------------------------------------------------------------------------------------
TOTAL THROUGHPUT 1,197.5 1,301.5 1,378.1 1,336.2 1,272.0
- ---------------------------------------------------------------------------------------------------------
26
27
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 approximately 2 million residential, commercial and industrial
customers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland.
Market Conditions
Weather in the market area served by Distribution during 1998 was the warmest on
record. It was 17% warmer than normal and 19% warmer than 1997. As a result,
there was nearly a 50 Bcf decrease in weather-sensitive deliveries compared to
1997. The settlement of a 10-month labor strike at a major customer late in 1997
partially offset the decline in deliveries brought about by the record warm
weather in 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 and
southwestern Pennsylvania where rates are 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.
Distribution continues to be a strong competitor in the energy market for new
homes as a result of a strong customer preference for natural gas. With the
addition of residential and small commercial customer choice programs, natural
gas is now more price-competitive with alternate fuels.
Approximately 40% of Distribution's industrial and commercial throughput, or 140
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. As a result, the estimated throughput
exposure to bypass has been reduced to approximately 48 Bcf, representing about
$12 million in annual net revenue.
Regulatory Matters
Columbia Gas of Virginia, Inc. (Columbia of Virginia) filed a rate case with the
Virginia State Corporation Commission (VSCC) in May 1998, requesting a $13.8
million increase in annual revenue. Of the requested increase, $8.5 million has
been collected through interim rates in effect since October 1997, subject to
refund, as a result of Columbia of Virginia's 1997 rate case filing. In February
1999, the VSCC in the 1997 rate case issued an order authorizing an increase in
annual revenue of $4.6 million. Rates reflecting the requested additional
increase in annual revenue of $5.3 million in the 1998 rate case filing went
into effect, also subject to refund, in October 1998. The higher revenue is
needed to recover costs related to plant additions including those required to
replace aging facilities and to recover normal increases in operating expenses.
Resolution of these proceedings will not have a material impact on Columbia's
consolidated financial results.
In February 1998, the Maryland Public Service Commission (MPSC) approved the
agreement reached by Columbia Gas of Maryland, Inc. (Columbia of Maryland) with
the MPSC staff and the Maryland People's Counsel. The People's Counsel had
sought an annual revenue reduction of $1.6 million, and Columbia of Maryland had
requested an annual revenue increase of $1.2 million. The agreement provided for
an annual revenue increase of $200,000. The new rates went into effect in March
1998.
In July 1998, Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) received
approval from the Kentucky Public Service Commission (KPSC) to extend its pilot
gas cost incentive program for another year until July 31, 1999. The off-system
sales program has been in effect on a pilot basis since August 1, 1996. Columbia
of Kentucky must file a petition with the KPSC by July 1, 1999, to continue the
program beyond August 1, 1999.
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 four of its five 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 capacity costs and other costs incurred by a utility serving as the supplier
of last resort if the marketing company cannot supply the gas. The state
commissions in Distribution's five jurisdictions are at various stages in
addressing these issues and other transition considerations. Distribution is
currently recovering the costs resulting from the
27
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
unbundling of its services and believes that most of such future costs and costs
resulting from being the supplier of last resort will be recovered. In addition
to the supplier of last resort issue, Columbia of Ohio will be at risk for up to
11% of the transition capacity costs.
In June 1998, Columbia of Ohio received approval from the Public Utilities
Commission of Ohio (PUCO) to extend its Customer CHOICE(SM) program to all of
its nearly 1.3 million customers. The PUCO approval to expand and continue the
program was based on Columbia's successful program in three northwestern Ohio
counties. There are now over 357,000 customers participating, including
approximately 320,000 residential customers. Of 44 marketers approved for
participation, 26 are currently active.
Columbia Gas of Pennsylvania, Inc. (Columbia of Pennsylvania) received
permission from the Pennsylvania Public Utility Commission (PPUC) in July 1998
to expand its Customer CHOICE(SM) program into five additional counties.
Customers began shopping for a new supplier in August 1998 for gas deliveries
that started in November 1998. Programs have been in operation in Allegheny and
Washington counties and the approved expansion means that over two-thirds of
Columbia of Pennsylvania's 386,000 customer base would be eligible to
participate in the Customer CHOICE(SM) program. There are now over 58,000
customers and nine marketers participating in the program. Meanwhile, Columbia
of Pennsylvania continues to push for a legislative proposal that would set the
terms for natural gas retail competition statewide.
Columbia of Virginia's two-year pilot transportation program for residential and
small commercial customers began December 1, 1997 and is open to approximately
27,000 customers in the Gainesville market area of Northern Virginia. There are
now over 6,300 customers and six marketers participating in the program.
Columbia of Virginia is supporting legislation that would permit it to offer all
of its 178,000 customers the opportunity to choose their natural gas supplier.
In August 1998, the MPSC approved a two-year continuation of Columbia of
Maryland's Customer CHOICE(SM) program for all of its customers. Introduced in
1996, the program allows more than 30,000 of Columbia of Maryland's customers to
consider a natural gas supplier other than Columbia of Maryland. There are
approximately 3,000 customers and four marketers participating in the program.
Columbia of Kentucky plans to make a filing with the KPSC in the spring of 1999
seeking approval to initiate a residential and small commercial transportation
program. Under the terms of the proposed filing, all of Columbia of Kentucky's
140,000 customers would be eligible to choose a new supplier for gas to be
delivered commencing in November 1999.
Voluntary Severance Plans
In January 1999, Columbia of Pennsylvania announced a Voluntary Severance
Program (VSP) available to all of its nearly 700 employees in the operations
department. The program is an effort to bring staffing levels into balance with
anticipated work assignments. Stagnant market growth, new technologies, a more
modern pipeline system and a more efficient management system for assigning work
is permitting Columbia of Pennsylvania to meet its operations obligations with
fewer employees. When combining the VSP with other workforce reduction measures,
Columbia of Pennsylvania may be able to reduce staffing by approximately 50
employees. These initiatives are anticipated to result in a charge to operating
expense in the first half of 1999.
Capital Expenditure Program
Distribution's 1998 capital expenditures were approximately $151.9 million, a
decrease of $7.6 million from 1997. In addition to maintaining and upgrading
facilities to assure safe, reliable and efficient operation, 1998 expenditures
included $60.9 million for extending service to new areas and $72.1 million for
replacement and betterment projects. The estimated 1999 capital expenditure
program amounts to approximately $152 million, including $59 million for new
business and development, $67 million for replacement and betterment projects
with the remainder primarily for support services.
Gas Supply
Distribution's gas supply portfolio, with its large storage component, has the
reliability and flexibility to accommodate the impact of weather variations on
traditional customer demand, as well as to provide opportunities to increase
revenues through off-system sales and other incentive programs. Off-system sales
are sales or other transactions conducted outside of Distribution's traditional
market. For 1998, Distribution had off-system sales of 62.9 Bcf. This was an
increase of 17.5 Bcf from 1997 due in part to the mild weather throughout the
year that allowed Distribution to market its storage volumes. Columbia of Ohio,
Columbia of Pennsylvania, Columbia of
28
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
Maryland and Columbia of Kentucky have incentive programs in place that have
been approved by their respective regulatory commissions that provide for the
sharing of the proceeds from off-system sales with customers. For 1998, these
programs resulted in pre-tax income for Distribution of $24 million, a decrease
of $2.1 million from 1997. Columbia of Ohio's 1996 rate settlement permitted the
retention of up to $51 million from off-system sales over three years subject to
an earnings limitation.
Proceeds from releasing unused pipeline capacity totaled $31.3 million for 1998,
up $11.8 million from 1997. Distribution can retain a portion of the proceeds
that exceeds established capacity release incentive benchmarks. All other
proceeds are recorded as a reduction to gas costs and the benefit is passed
through to customers. In 1998, Columbia of Ohio and Columbia of Maryland were
able to retain capacity release proceeds totaling $1.1 million. As residential
and small commercial transportation programs develop into widespread practice
and marketers take assignment of the LDC's pipeline capacity contracts, earnings
from these non-traditional services may decline.
Environmental Matters
Distribution's primary environmental issues relate to 15 former manufactured gas
plant sites. Investigations or remedial activities are currently underway at
seven sites and have been completed at one site. 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 action established, the appropriate 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.
Throughput
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 the 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 unusually warm weather in 1998.
In 1997, Distribution's total volumes sold and transported of 572.1 Bcf
increased 7.1 Bcf from 1996, as increased transportation and off-system sales
offset the adverse impact of warmer weather, a reduction in customer usage and
the impact of the strike at the major customer. Transportation volumes were up
by 10.1 Bcf in 1997 compared to 1996, reflecting higher demand for power
generation and competitive natural gas prices.
Net Revenue
In 1998, net revenue was $847 million, down $51.1 million from 1997. This
decrease primarily reflects the record warm weather, which reduced net revenue
approximately $76 million from 1997. The decrease was only partially offset by
the beneficial impact of Columbia of Ohio's 1997 regulatory settlement.
Net revenue for 1997 of $898.1 million was down $8.6 million from 1996, due to
the warmer weather that reduced net revenue by $20 million. This decrease
attributable to the warmer weather was partially offset by an increase in
revenue from Columbia of Ohio's 1997 rate settlement, together with income for
certain gas management activities that Columbia of Ohio retained under the terms
of its 1996 rate settlement.
Operating Income
Operating income for 1998 of $225.8 million increased by $1.6 million from 1997,
as the decline in net revenue was more than offset by a $52.7 million decrease
in operating expenses. Operation and maintenance expense for 1998 decreased
$54.3 million to $386.7 million, primarily reflecting a reduction in
postretirement benefit costs and the ongoing beneficial impact of the
restructuring initiatives implemented in 1997. Other taxes decreased $2.4
million from 1997, primarily due to lower payroll taxes and depreciation expense
increased by $4 million due in part to plant additions.
In 1997, operating income decreased by $1.8 million from 1996 to $224.2 million
as the decrease in net revenue was only partly offset by a $6.8 million decline
in operating expenses. The decrease in operating expenses was primarily due to a
reduced level of restructuring costs recorded in 1997 and the implementation
during 1996 and 1997 of cost conservation measures and operating efficiencies.
29
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $ 1,686.3 $ 2,153.1 $ 2,007.9
Less: Cost of gas sold 1,005.4 1,385.6 1,206.4
- ---------------------------------------------------------------------------------------------------------------
Net Sales Revenues 680.9 767.5 801.5
- ---------------------------------------------------------------------------------------------------------------
Transportation revenues 183.2 143.2 119.8
Less: Associated gas costs 17.1 12.6 14.6
- ---------------------------------------------------------------------------------------------------------------
Net Transportation Revenues 166.1 130.6 105.2
- ---------------------------------------------------------------------------------------------------------------
Net Revenues 847.0 898.1 906.7
- ---------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 386.7 441.0 463.0
Depreciation 82.2 78.2 74.4
Other taxes 152.3 154.7 143.3
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 621.2 673.9 680.7
- ---------------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 225.8 $ 224.2 $ 226.0
- ---------------------------------------------------------------------------------------------------------------
30
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (continued)
DISTRIBUTION OPERATING HIGHLIGHTS
1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 151.9 159.5 148.4 151.8 151.4
- ---------------------------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
Residential 149.1 190.9 209.4 196.6 189.7
Commercial 54.1 72.7 85.7 79.5 80.8
Industrial and Other 4.4 4.2 10.3 7.1 9.7
- ---------------------------------------------------------------------------------------------------------------------------------
Total Sales 207.6 267.8 305.4 283.2 280.2
Transportation 287.7 258.9 248.8 255.9 232.5
- ---------------------------------------------------------------------------------------------------------------------------------
Total Throughput 495.3 526.7 554.2 539.1 512.7
Off-System Sales 62.9 45.4 10.8 7.5 0.3
- ---------------------------------------------------------------------------------------------------------------------------------
Total Sold and Transported 558.2 572.1 565.0 546.6 513.0
- ---------------------------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
Spot market* 223.5 295.0 298.7 210.4 235.3
Producers 17.7 35.7 47.9 70.9 67.5
Storage withdrawals (injections) 12.4 4.0 (20.8) 23.6 (14.0)
Company use and other 16.9 (21.5) (9.6) (14.2) (8.3)
- ---------------------------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 270.5 313.2 316.2 290.7 280.5
Gas received for delivery to customers 287.7 258.9 248.8 255.9 232.5
- ---------------------------------------------------------------------------------------------------------------------------------
Total Sources 558.2 572.1 565.0 546.6 513.0
- ---------------------------------------------------------------------------------------------------------------------------------
CUSTOMERS
Sales
Residential 1,612,124 1,769,647 1,815,269 1,794,800 1,764,968
Commercial 148,529 168,413 173,689 172,114 167,067
Industrial and Other 2,295 2,340 2,285 2,265 2,312
- ---------------------------------------------------------------------------------------------------------------------------------
Total Sales Customers 1,762,948 1,940,400 1,991,243 1,969,179 1,934,347
Transportation 298,107 93,923 12,804 6,789 6,520
- ---------------------------------------------------------------------------------------------------------------------------------
Total Customers 2,061,055 2,034,323 2,004,047 1,975,968 1,940,867
- ---------------------------------------------------------------------------------------------------------------------------------
DEGREE DAYS 4,635 5,736 5,975 5,692 5,530
- ---------------------------------------------------------------------------------------------------------------------------------
* Reflects volumes under purchase contracts of less than one year.
31
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
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 produces over
40 Bcf equivalents (Bcfe) of natural gas and oil annually, owns and operates
7,300 wells, and has net proven reserve holdings of 801.5 Bcfe. Columbia
Resources also owns and operates approximately 4,500 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 1998, Columbia Resources entered into agreements in Ontario
Province, Canada that provide Columbia Resources an expanded undeveloped acreage
base. Columbia Resources' reserve base and production levels have also been
expanded through the successful drilling and completion of 157 gross wells
during 1998. Based on the total of 197 gross wells drilled and completed, the
1998 success rate was 80%. In January 1999, Columbia Resources also completed
its acquisition of gathering pipeline facilities from Columbia Transmission with
the purchase of an additional 750 miles of pipeline in northern West Virginia.
Capital Expenditure Program
Columbia Resources' 1998 capital expenditures of $75.7 million primarily reflect
investment in drilling and acquisitions. The 1999 capital expenditure program is
estimated at $104 million and provides for the drilling of 230 additional wells.
During 1999, Columbia Resources expects to continue efforts to expand and
enlarge the definition of its core Appalachian basin properties, as well as its
eastern Canadian properties, through development drilling, exploration projects
and pipeline projects. Columbia Resources may participate, through joint venture
agreements, in investment opportunities in other basins in the eastern United
States.
Natural Gas Prices
In early 1998, the industry began to experience a deterioration of prices as a
result of last winter being one of the warmest winters in recent history.
Surplus storage levels throughout the year, due in part to the record-breaking
warm temperatures, contributed to the continuation of low gas and oil prices.
Management believes that Columbia Resources is well positioned to take advantage
of opportunities in this low-price environment with per unit operating costs
among the lowest compared to its competitors.
In an effort to help manage the continued uncertainty of gas prices and to
stabilize earnings, Columbia Resources hedged a portion of its 1998 and 1999 gas
production that was subject to price volatility through a gas marketing
affiliate. The gas marketing affiliate in turn, as part of its normal course of
business, hedged these positions in the marketplace. In that manner, Columbia
Resources secured an average gas price of $2.91 per Mcf on 77% of 1998 at-risk
production resulting in a 1998 revenue increase of $11 million. Columbia
Resources has entered into agreements securing an average 1999 price of $2.79 on
28% of 1999 at-risk production. This position for 1999 includes the hedging of
certain risks associated with both the commodity and the Appalachia basis, which
generally represents transportation costs to bring gas from the Southwest to the
Appalachia area.
Production
Gas production of 39.1 Bcf in 1998 increased 4.4 Bcf over 1997, primarily due to
the acquisition of Alamco in mid-1997 and new production brought online in 1998.
From 1996 to 1997, gas production increased by 3% reflecting the Alamco
acquisition together with well shut-ins in 1996 that limited production in that
year.
Oil and liquids production in 1998 increased by 2% from 1997 to 214,000 barrels.
The increase primarily reflects new well completions coming online. In 1997,
production was down 25% from 1996 largely due to the sale of a production field
in December 1996.
Operating Revenues
Operating revenues for 1998 were $127.5 million, an increase of $14.2 million
over 1997, primarily reflecting higher revenues generated from hedging
activities and the gas production increase, both of which were discussed above.
Columbia Resources' average gas sales price for 1998 was $2.91 per Mcf, an
increase of 11% from 1997. The strong natural gas prices reflect the benefit of
hedging a portion of 1998 production in late 1997 when prices were significantly
higher. Operating revenues in 1997 were $113.3 million, an increase of $8.8
million from 1996, primarily due to a reclassification in the recording of
gathering activities.
32
33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Operating Income
In 1998, operating income improved by $6.3 million to $37.2 million, primarily
due to higher operating revenues, which were partially offset by an increase of
$8.9 million in depreciation and depletion expense due to additional investments
in acquisitions and drilling. Operating income of $30.9 million in 1997 improved
by $900,000 from 1996, as the improvement in operating revenues was mostly
offset by higher operation and maintenance expense due primarily to additional
costs associated with the Alamco acquisition.
STATEMENTS OF OPERATING INCOME FROM EXPLORATION AND PRODUCTION OPERATIONS
(UNAUDITED)
Year Ended December 31, (in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
OPERATING REVENUES
Gas revenues $ 113.9 $ 109.5 $ 99.1
Other revenues 13.6 3.8 5.4
- --------------------------------------------------------------------------------
Total Operating Revenues 127.5 113.3 104.5
- --------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 44.6 45.7 37.0
Depreciation and depletion 36.5 27.6 28.8
Other taxes 9.2 9.1 8.7
- --------------------------------------------------------------------------------
Total Operating Expenses 90.3 82.4 74.5
- --------------------------------------------------------------------------------
OPERATING INCOME $ 37.2 $ 30.9 $ 30.0
- --------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS
1998 1997 1996 1995* 1994*
- --------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 75.7 158.7 12.1 86.8 101.6
- --------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf) 790.5 800.5 644.5 599.5 683.8
Oil and Liquids (000 Bbls) 1,835 1,700 774 1,651 12,255
- --------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf) 39.1 34.7 33.6 65.4 66.7
Oil and Liquids (000 Bbls) 214 210 281 2,849 3,611
- --------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf)** 2.91 2.63 2.84 1.96 2.18
Oil and Liquids ($ per barrel) 12.76 17.99 19.07 16.17 15.09
- --------------------------------------------------------------------------------
* 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 1(G) of Notes
to Consolidated Financial Statements.
33
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
MARKETING OPERATIONS
Columbia's wholesale and retail nonregulated natural gas and electric power
marketing operations are conducted by Columbia's wholly-owned subsidiary,
Columbia Energy Services Corporation (Columbia Energy Services). These
operations provide integrated energy-related products and services to wholesale,
industrial and commercial, and residential customers. Columbia Energy Services
can be categorized into three business lines: wholesale energy operations and
services, retail products and services, and online energy services through its
subsidiary, Energy.com Corporation (Energy.com). The wholesale business line
provides products and services to wholesale customers nationwide, including gas
and electricity supply, fuel management and transportation-related services,
management and optimization of energy-related assets, energy commodity sales and
services, risk management products and financial services. The retail business
line provides energy-related products and services to a diverse customer base
(industrial, commercial and residential). These products and services include
gas and electricity supply, energy management, software and other services.
Energy.com focuses on providing an internet commerce channel for energy
companies to sell to all retail customers.
The marketing operations expanded dramatically during 1998; however, this rapid
growth strained Columbia Energy Services' infrastructure and highlighted areas
that need improvement. Columbia Energy Services has been addressing the
administrative requirements related to the significantly increased trading
volumes and continues to implement new accounting systems and procedures that
are necessary to support this growth. As part of this process, certain financial
records have been identified that do not appear to have adequate third party
documentation or represent reconciliation differences between new subsidiary
ledger systems and other financial records. As a result of this analysis, a
$16.3 million pre-tax reserve was recorded in the fourth quarter of 1998.
Management believes that this reserve is adequate based on information currently
available.
In addition, during the fourth quarter of 1998, certain unusual trading
activity, which when combined with all other gas positions, caused a $6.5
million net decrease to gross margin. Management has taken corrective action
designed to prevent similar incidents from recurring. The continuing
effectiveness of such action will be monitored.
Wholesale Energy Activity
Wholesale activity primarily consists of gas trading and marketing, and electric
power trading and marketing, both of which have grown significantly in 1998.
This growth reflects an increased presence in southeast and midwest markets, as
well as an expanded portfolio of storage and transportation assets. Sales growth
has occurred through increased trading, aggressive management of LDC supply,
transportation and storage services, and through Columbia Energy Services'
participation in retail markets. These activities have expanded Columbia Energy
Services' overall wholesale trading capabilities.
During 1998, Columbia Energy Services invested significantly in its wholesale
risk management infrastructure, and related financial products and services.
Consequently, a number of transactions have been added to its overall trading
and marketing portfolio. For example, during 1998, Columbia Energy Services
entered into ten-year natural gas supply contracts with two separate municipal
gas authorities that together total 82 Bcf of natural gas. As part of the
agreements, the municipal gas authorities made advance payments to Columbia
Energy Services in 1998 totaling $137.5 million for future deliveries.
In mid-1998, Columbia Energy Services signed a long-term energy management
contract for a 365-megawatt combined-cycle, natural gas-fired generation
facility in Hopewell, Virginia. Columbia Energy Services began providing the
facility with natural gas in June 1998. This facility has a baseload volume of
approximately 5,000 million British thermal units (MMBtu) daily for steam
generation and a daily peak demand volume of up to 75,000 MMBtu for electric
generation to be sold in Virginia. In addition to supplying natural gas,
Columbia Energy Services is managing the facility's fuel oil reserve tanks.
In addition to natural gas commodity trading and marketing activities,
Columbia Energy Services entered the electricity trading business in December
1997 and has expanded its trading and scheduling operations in northeastern,
midwestern, southwestern, and western United States. Over the past year,
trading levels have increased to 14,364 Gigawatt hours for the year 1998,
providing revenues of $564.4 million. Columbia Energy Services actively trades
in cash and forward markets, as well as electricity futures traded on the four
New York Mercantile Exchanges. Columbia Energy Services is building its
capabilities and related infrastructure to deliver electricity to retail
customers in the Northeast.
34
35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Retail Energy Activity
Retail energy activity can be grouped into two broad strategic business units:
Major Accounts and Mass Markets. These retail business units market to end-use
customers, both for gas and power retail markets. Management believes that
Columbia Energy Services is favorably positioned for gas and electric retail
market unbundling and deregulation. During 1998, the Major Accounts strategic
business unit significantly increased the number of industrial and large
commercial customers served. Geographically, it expanded activity into two new
regions of the country, northeast and southeast, adding eight new states to
Columbia Energy Services' market territory. The Major Accounts group signed
several agreements to provide energy service with prominent national chain
restaurants and retail stores, including its first retail electric customer in
New York.
Columbia Energy Services initiated residential marketing programs in 10 states
in 1998 (Ohio, Pennsylvania, Michigan, Maryland, Indiana, Virginia, Georgia,
Kentucky, West Virginia and New Jersey). During 1998, Columbia Energy Services
increased its Mass Market customer base to over 363,000 or nearly 4 times the
number of customers since the beginning of the year.
During 1998, Columbia Energy Services entered the Georgia retail natural gas
market where it was certified by the Georgia Public Service Commission to sell
natural gas. All 1.2 million retail customers of an LDC located in Atlanta will
either choose a new natural gas supplier or be assigned to a provider. Also,
during 1998, Columbia Energy Services obtained its first residential electric
customers in Pennsylvania.
Columbia Energy Services is also offering diverse products and services related
to the deregulation of retail markets. For example, two energy efficiency
software products, developed by Columbia Energy Services, were launched late in
the third quarter of 1998. These software products are targeted toward helping
residential and commercial customers save money on energy costs.
Gross Margins
Gross margins of $42.7 million for 1998 more than doubled from the $20.6 million
in 1997. Electric power marketing sales, which began in late 1997, together with
increased gas sales represented the majority of the increase. Electric power
traded in 1998 was 14,364 Gigawatt hours while gas sales in 1998 of 1,581 Bcf
represented a 78 percent increase over 1997. Much of the growth in gas sales
came from increased lower-margin wholesale sales that are necessary to expand
Columbia Energy Services' base for future retail growth. Included in the results
for 1998 was the $6.5 million loss mentioned above.
The $20.6 million gross margin for 1997 was $4.1 million higher than for 1996,
reflecting gas sales of 888.4 Bcf that more than tripled the 1996 level due to
the significant growth of Columbia Energy Services' operations. The impact of
higher gas sales volumes was partially offset by a decrease in average margins.
Operating Loss
A 1998 operating loss of $59 million was $45.8 million greater than the $13.2
million loss in 1997, due to 1998 operating expenses that were $67.9 million
higher than the year earlier. The higher expenses related to the implementation
of Columbia Energy Services' strategy to build its systems and infrastructure,
including adding and retaining qualified staff. Included in these higher
expenses was the $16.3 million reserve, discussed above, and higher current
period expenses for costs associated with the development of new products and
services and customer acquisition costs related to adding new Mass Market retail
customers.
35
36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
STATEMENTS OF OPERATING INCOME FROM MARKETING OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
OPERATING REVENUES
Gas revenues $3,507.8 $2,187.0 $ 728.0
Power revenues 564.4 -- --
- --------------------------------------------------------------------------------
Total Operating Revenues 4,072.2 2,187.0 728.0
Less: Products purchased 4,029.5 2,166.4 711.5
- --------------------------------------------------------------------------------
Gross Margin 42.7 20.6 16.5
- --------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 95.7 31.1 11.2
Depreciation 4.1 1.6 0.3
Other taxes 1.9 1.1 0.5
- --------------------------------------------------------------------------------
Total Operating Expenses 101.7 33.8 12.0
- --------------------------------------------------------------------------------
OPERATING INCOME (LOSS) $ (59.0) $ (13.2) $ 4.5
- --------------------------------------------------------------------------------
MARKETING OPERATING HIGHLIGHTS
1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 16.0 5.1 0.8 1.0 0.2
- ------------------------------------------------------------------------------------------
MARKETING SALES
Gas (Bcf) 1,581.0 888.4 259.6 131.6 111.2
Power (Gwh) 14,364 -- -- -- --
- ------------------------------------------------------------------------------------------
36
37
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
PROPANE, POWER GENERATION AND LNG OPERATIONS
During 1998, Columbia Propane Corporation (Columbia Propane) and Columbia
Electric Corporation (Columbia Electric) were involved in several transactions
designed to increase the contribution by Columbia's nonregulated companies to
consolidated results. Columbia Propane purchased the assets of three propane
companies and Columbia Electric announced its participation in two cogeneration
projects.
Propane
During 1998, Columbia Propane purchased the propane assets of three companies
that in total added approximately 12,500 new customers and 6.4 million gallons
of annual propane sales to Columbia Propane.
Power Generation
Columbia Electric's primary focus has been the development, ownership and
operation of natural gas-fueled cogeneration power plants that sell electric
power to local electric utilities under long-term contracts. Columbia Electric
is part owner in three cogeneration projects that have a total capacity of
approximately 250 megawatts and produce both electricity and useful thermal
energy fueled principally by natural gas.
In June 1998, Columbia Electric and LG&E Power Inc., a subsidiary of LG&E Energy
Corporation, announced an agreement for Columbia to participate in the
development of a gas-fired cogeneration project. The facility will have a total
equivalent capacity of approximately 550 megawatts and will provide steam and
electric services to a Reynolds Metals plant in Gregory, Texas. The project,
Gregory Power Partners, will also provide electricity to the Texas energy market
and is expected to begin commercial operation in the Electric Reliability
Council of Texas (ERCOT) region in the summer of 2000. Construction began in
August 1998 and financing for the $257 million project was secured in November
of 1998.
In January 1998, Columbia Electric and Westcoast Energy Inc. signed a joint
ownership agreement to develop three gas-fired electric generation plants by
2001. In total, the three plants would provide approximately 1,000 megawatts of
electricity using approximately 160 MMcf per day of natural gas. In August 1998,
the parties formed a limited liability company, which subsequently purchased a
site in Eddystone, Pennsylvania for the construction of a 500 megawatt, natural
gas-fired electric generation plant. The plant, to be called the Liberty
Electric Power Plant, is expected to cost about $300 million to develop, and
would consume about 80 MMcf per day of natural gas. Each of the sponsors will
own a 50% interest in the project. The exact locations of the other two plants
have yet to be determined.
Capital Expenditure Program
A large portion of the $20.1 million 1998 capital expenditures program was
allocated to propane acquisition activities. The 1999 capital expenditure
program is estimated at $129 million and includes amounts primarily for
acquisitions, as well as for additional investments in Columbia's subsidiary,
Columbia Transmission Telecommunications Corporation, for the development of a
dark fiber optics network, as well as for continued investment in the Cove Point
LNG facility.
Commodity Hedging
Columbia Propane purchases propane and places it in storage for future sale.
Columbia Propane sells commodity futures on a portion of its inventory at the
time of purchase to hedge against the risk of decreasing prices.
Net Revenues
Net revenues of $55.1 million for 1998 decreased $2.1 million from 1997. The
decrease largely reflects 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. This decrease was
partially offset by an increase in propane net revenues of $1.3 million, due to
higher margins achieved in the first quarter of 1998 and additional retail sales
attributable to recent acquisitions. Total propane volumes for 1998 decreased
4.4 million gallons from 1997 due to warmer weather and lower spot sales.
Net revenues for 1997 increased $11.3 million over 1996 to $57.2 million. Net
revenues for Columbia Propane in 1997 increased $1.4 million compared to 1996
due to 11% higher margins, which were partially offset by a 7% decrease in
volumes resulting from the warmer than normal weather experienced in the first
quarter of 1997 and lower spot market sales activity.
37
38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Operating Income
Operating income of $10.7 million for 1998 decreased $5.6 million from 1997,
primarily reflecting the decline in net revenues and a $3.5 million increase in
operating expenses due to the recent propane acquisitions and additional
start-up costs for new services.
Operating income of $16.3 million was recorded in 1997, up $6.7 million over
1996. Operation and maintenance expense for 1997 increased over 1996 as start-up
costs for new services led to higher operating costs.
STATEMENTS OF PROPANE, POWER GENERATION AND LNG OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
NET REVENUES
Propane revenues $ 63.1 $ 70.4 $ 74.1
Less: Products purchased 34.6 43.2 48.3
- --------------------------------------------------------------------------------
Net Propane Revenues 28.5 27.2 25.8
- --------------------------------------------------------------------------------
Power generation 8.3 10.6 7.3
Other revenues 18.3 19.4 12.8
- --------------------------------------------------------------------------------
Net Revenues 55.1 57.2 45.9
- --------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 37.2 35.3 31.6
Depreciation 5.1 3.6 2.8
Other taxes 2.1 2.0 1.9
- --------------------------------------------------------------------------------
Total Operating Expenses 44.4 40.9 36.3
- --------------------------------------------------------------------------------
OPERATING INCOME $ 10.7 $ 16.3 $ 9.6
- --------------------------------------------------------------------------------
PROPANE, POWER GENERATION AND LNG OPERATING HIGHLIGHTS
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 20.1 9.9 5.5 9.0 4.5
- --------------------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions) 66.5 70.9 75.9 68.9 68.5
Customers 113,748 96,954 79,650 74,308 68,218
- --------------------------------------------------------------------------------------------------
38
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
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. In settlement of
its prepetition obligations, Columbia distributed approximately $3.6 billion to
its creditors, which included $2.3 billion in payment of Columbia's prepetition
debt and approximately $1 billion of interest on that debt. 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 is the last remaining producer claim in Columbia Transmission's
bankruptcy proceeding. In the first quarter of 1999, Columbia Transmission
anticipates reversing that portion of its producer settlement reserve that is in
excess of the amount needed to resolve remaining producer-related issues, which
will result in an improvement to income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information required by this item is in Item 7 on page 19.
39
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Index Page
- --------------------------------------------------------------------------------
Report of Independent Public Accountants ................................. 41
Statements of Consolidated Income ....................................... 42
Consolidated Balance Sheets .............................................. 43
Statements of Consolidated Cash Flows .................................... 45
Statements of Consolidated Common Stock Equity ........................... 46
Notes of Consolidated Financial Statements ............................... 47
Schedule II - Valuation and Qualifying Accounts .......................... 70
- --------------------------------------------------------------------------------
40
41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL 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, 1998 and 1997, 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, 1998. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
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
February 11, 1999
41
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA (continued)
STATEMENTS OF CONSOLIDATED INCOME
Columbia Energy Group and Subsidiaries
Year Ended December 31, (in millions, except per share amounts) 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------
NET REVENUES
Energy sales $ 5,731.8 $ 4,325.2 $ 2,713.4
Less: Products purchased 4,654.0 3,125.5 1,466.6
- -----------------------------------------------------------------------------------------------------------
Gross Margin 1,077.8 1,199.7 1,246.8
Transportation 557.5 518.9 476.8
Production gas sales 51.6 30.4 37.7
Other 210.2 166.5 111.6
- -----------------------------------------------------------------------------------------------------------
Total Net Revenues 1,897.1 1,915.5 1,872.9
- -----------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation 810.1 862.1 854.5
Maintenance 91.5 100.2 111.4
Depreciation and depletion 235.2 221.3 215.2
Other taxes 220.3 222.5 213.6
- -----------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,357.1 1,406.1 1,394.7
- -----------------------------------------------------------------------------------------------------------
OPERATING INCOME 540.0 509.4 478.2
- -----------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
Interest income and other, net (Note 14) 13.4 40.4 26.1
Interest expense and related charges (Note 15) (152.4) (157.6) (166.8)
- -----------------------------------------------------------------------------------------------------------
Total Other Income (Deductions) (139.0) (117.2) (140.7)
- -----------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 401.0 392.2 337.5
Income Taxes (Note 7) 131.8 118.9 115.9
- -----------------------------------------------------------------------------------------------------------
NET INCOME $ 269.2 $ 273.3 $ 221.6
- -----------------------------------------------------------------------------------------------------------
EARNINGS PER SHARE OF COMMON STOCK* $ 3.23 $ 3.29 $ 2.75
DILUTED EARNINGS PER SHARE OF COMMON STOCK* $ 3.21 $ 3.27 $ 2.74
- -----------------------------------------------------------------------------------------------------------
DIVIDENDS PAID PER SHARE OF COMMON STOCK* $ 0.77 $ 0.60 $ 0.40
- -----------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (thousands)* 83,382 83,100 80,681
DILUTED AVERAGE COMMON SHARES (thousands)* 83,748 83,594 80,919
- -----------------------------------------------------------------------------------------------------------
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 3 of Notes to Consolidated Financial Statements.
42
43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA (continued)
CONSOLIDATED BALANCE SHEETS
Columbia Energy Group and Subsidiaries
ASSETS as of December 31, (in millions) 1998 1997
- --------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant, at original cost $7,687.8 $7,368.9
Accumulated depreciation (3,592.3) (3,481.5)
- --------------------------------------------------------------------------------
Net Gas Utility and Other Plant 4,095.5 3,887.4
- --------------------------------------------------------------------------------
Gas and oil producing properties, full cost method
United States cost center 714.1 660.2
Canadian cost center 5.0 --
Accumulated depletion (225.4) (196.0)
- --------------------------------------------------------------------------------
Net Gas and Oil Producing Properties 493.7 464.2
- --------------------------------------------------------------------------------
Net Property, Plant and Equipment 4,589.2 4,351.6
- --------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
Accounts receivable - noncurrent 26.2 1.6
Unconsolidated affiliates 81.6 74.1
Other 14.3 9.5
- --------------------------------------------------------------------------------
Total Investments and Other Assets 122.1 85.2
- --------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 26.3 28.7
Accounts receivable
Customer (less allowance for doubtful accounts
of $34.2 and $18.7, respectively) 948.9 815.8
Other 56.0 52.7
Gas inventory 186.0 226.8
Other inventories - at average cost 26.8 35.6
Prepayments 115.9 107.7
Regulatory assets 59.5 64.6
Underrecovered gas costs 24.5 41.4
Deferred property taxes 80.0 80.8
Exchange gas receivable 187.4 189.0
Other 69.2 64.6
- --------------------------------------------------------------------------------
Total Current Assets 1,780.5 1,707.7
- --------------------------------------------------------------------------------
REGULATORY ASSETS 391.4 400.9
DEFERRED CHARGES 85.5 66.9
- --------------------------------------------------------------------------------
TOTAL ASSETS $6,968.7 $6,612.3
- --------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
* The common shares outstanding at December 31, 1997 do not reflect the
three-for-two common stock split, in the form of a stock dividend,
effective June 15, 1998.
43
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA (continued)
CAPITALIZATION AND LIABILITIES as of December 31, (in millions) 1998 1997
- ----------------------------------------------------------------------------------------
COMMON STOCK EQUITY
Common stock, par value $10 per share - issued
83,511,878 and 55,495,460* shares, respectively $ 835.1 $ 554.9
Additional paid in capital 761.8 754.2
Retained earnings 409.5 482.7
Unearned employee compensation (0.9) (1.1)
Accumulated Other Comprehensive Income:
Foreign currency translation adjustment (0.2) --
- ----------------------------------------------------------------------------------------
Total Common Stock Equity 2,005.3 1,790.7
LONG-TERM DEBT (Note 10) 2,003.1 2,003.5
- ----------------------------------------------------------------------------------------
Total Capitalization 4,008.4 3,794.2
- ----------------------------------------------------------------------------------------
CURRENT LIABILITIES
Short-term debt (Note 11) 144.8 328.1
Accounts and drafts payable 710.7 536.7
Accrued taxes 205.9 140.9
Accrued interest 17.3 29.4
Estimated rate refunds 59.2 68.4
Estimated supplier obligations 72.4 73.9
Overrecovered gas costs 34.3 84.6
Transportation and exchange gas payable 134.2 89.2
Other 312.9 367.0
- ----------------------------------------------------------------------------------------
Total Current Liabilities 1,691.7 1,718.2
- ----------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Deferred income taxes - noncurrent 655.3 618.4
Investment tax credits 34.1 35.6
Postretirement benefits other than pensions 103.7 148.8
Regulatory liabilities 44.0 41.3
Deferred revenue 191.4 67.0
Other 240.1 188.8
- ----------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits 1,268.6 1,099.9
- ----------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 13) -- --
- ----------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $6,968.7 $6,612.3
- ----------------------------------------------------------------------------------------
44
45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA (continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
Columbia Energy Group and Subsidiaries
Year Ended December 31, (in millions) 1998 1997 1996
- ----------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 269.2 $ 273.3 $ 221.6
Adjustments for items not requiring (providing) cash:
Depreciation and depletion 235.2 221.3 215.2
Deferred income taxes 31.6 29.3 78.1
Earnings from equity investment, net of distributions (8.5) 2.4 9.2
Other - net 121.4 32.2 (5.7)
- ----------------------------------------------------------------------------------------------
648.9 558.5 518.4
Changes in components of working capital:
Accounts receivable (139.5) (199.2) (64.3)
Income tax refunds -- -- 271.5
Gas inventory 40.8 11.0 (65.6)
Prepayments (8.2) (33.9) (16.3)
Accounts payable 230.7 186.8 160.8
Accrued taxes 46.7 (30.4) (85.5)
Accrued interest (12.1) (1.2) (71.5)
Estimated rate refunds (9.2) (45.6) 17.8
Estimated supplier obligations (1.5) (41.2) (63.2)
Under/Overrecovered gas costs (33.4) 147.9 (146.3)
Exchange gas receivable/payable 47.3 (89.5) 46.9
Other working capital (48.8) 5.0 (25.7)
- ----------------------------------------------------------------------------------------------
Net Cash From Operations 761.7 468.2 477.0
- ----------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
Capital expenditures (462.9) (420.5) (316.4)
Proceeds received on the sale of
Columbia Gas Development Corp. -- -- 187.8
Purchase of Alamco, Inc. -- (99.4) --
Other investments - net (12.5) (9.1) 2.7
- ----------------------------------------------------------------------------------------------
Net Investment Activities (475.4) (529.0) (125.9)
- ----------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Retirement of preferred stock -- -- (400.0)
Dividends paid (63.9) (49.9) (32.1)
Issuance of common stock 10.5 11.7 250.8
Issuance (repayment) of short-term debt (182.4) 77.1 (88.9)
Other financing activities (52.9) 0.8 (39.1)
- ----------------------------------------------------------------------------------------------
Net Financing Activities (288.7) 39.7 (309.3)
- ----------------------------------------------------------------------------------------------
Increase (Decrease) in cash and temporary cash investments (2.4) (21.1) 41.8
Cash and temporary cash investments at beginning of year 28.7 49.8 8.0
- ----------------------------------------------------------------------------------------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 26.3 $ 28.7 $ 49.8
- ----------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest $ 147.0 $ 145.4 $ 150.9
Cash paid for income taxes (net of refunds) $ 38.3 $ 90.7 $ (93.4)
- ----------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
45
46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
Columbia Energy Group and Subsidiaries
Common Stock*
-----------------------------------
Shares Additional Unearned
Outstanding** Par Treasury Paid In Retained Employee
(in millions, except for share amounts) (Thousands) Value Stock Capital Earnings Compensation
- --------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1995 49,204 $ 506.2 $ (57.8) $ 595.8 $ 69.8 $ --
Net income 221.6
Cash dividends:
Common stock (32.1)
Common stock issued:
Public offering 5,750 43.3 57.8 137.5
Long-term incentive plan 310 3.1 9.9 (1.5)
- --------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 55,264 552.6 -- 743.2 259.3 (1.5)
Net income 273.3
Cash dividends:
Common stock (49.9)
Common stock issued:
Long-term incentive plan 232 2.3 11.0 0.4
- --------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 55,496 554.9 -- 754.2 482.7 (1.1)
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 0.2
Three-for-two stock split 27,785 277.9 (278.5)
- --------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1998 83,512 $ 835.1 $ -- $ 761.8 $ 409.5 $ (0.9)
- --------------------------------------------------------------------------------------------------------------------
Accumulated
Other
Comprehensive
(in millions, except for share amounts) Income Total
- ---------------------------------------------------------------------
Balance at December 31, 1995 $ -- $1,114.0
Net income 221.6
Cash dividends:
Common stock (32.1)
Common stock issued:
Public offering 238.6
Long-term incentive plan 11.5
- ----------------------------------------------------------------------
Balance at December 31, 1996 -- 1,553.6
Net income 273.3
Cash dividends:
Common stock (49.9)
Common stock issued:
Long-term incentive plan 13.7
- ----------------------------------------------------------------------
Balance at December 31, 1997 -- 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 10.1
Three-for-two stock split (0.6)
- ----------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1998 $ (0.2) $2,005.3
- ----------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
* 100 million shares authorized at December 31, 1998, 1997, 1996 and 1995 -
$10 par value.
** The common shares outstanding at December 31, 1997, 1996 and 1995 do not
reflect the three-for-two common stock split, in the form of a stock
dividend, effective June 15, 1998.
46
47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
the accounts of the Columbia Energy Group (Columbia) and all subsidiaries. All
intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to the 1997 and 1996 financial statements to
conform to the 1998 presentation.
B. CASH AND CASH EQUIVALENTS. Columbia considers all highly liquid short-term
investments to be cash equivalents.
C. EARNINGS PER SHARE. Financial Accounting Standards Board Statement of
Financial Accounting Standards No. 128, "Earnings Per Share" (SFAS No. 128),
requires dual presentation of Basic and Diluted earnings per share (EPS) by
entities with complex capital structures and also requires restatement of all
prior period EPS data presented. Basic EPS includes no dilution and is computed
by dividing income available to common stockholders by the weighted-average
number of common shares outstanding for the period. Diluted EPS reflects the
potential dilution if certain securities are converted into common stock.
The computation of diluted average common shares follows:
Diluted Average Common Shares Computation 1998 1997 1996
- --------------------------------------------------------------------------------
Net Income ($ in millions) 269.2 273.3 221.6
- --------------------------------------------------------------------------------
Denominator (thousands)
Average common shares outstanding 83,382 83,100 80,681
Dilutive potential common shares - options 366 494 238
- --------------------------------------------------------------------------------
DILUTED AVERAGE COMMON SHARES 83,748 83,594 80,919
- --------------------------------------------------------------------------------
The number of shares reflect a three-for-two common stock split, in the form of
a stock dividend, effective June 15, 1998.
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 reasonable to assume 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.
47
48
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) 1998 1997 1998 1997
- -------------------------------------------------------------------------------------------
ASSETS
Environmental costs 136.7 125.8 6.2 7.4
Postemployment and postretirement benefits costs 60.3 64.6 113.6 121.8
Percent of income plan receivables -- -- 15.3 22.6
Retirement income plan costs 15.2 21.7 16.6 19.2
Regulatory effects of accounting for income taxes -- -- 55.8 50.8
Post in-service carrying charges -- -- 16.9 18.3
Underrecovered gas costs -- -- 24.5 41.4
Other 8.1 7.4 6.2 5.9
- -------------------------------------------------------------------------------------------
TOTAL REGULATORY ASSETS 220.3 219.5 255.1 287.4
- -------------------------------------------------------------------------------------------
LIABILITIES
Rate refunds and reserves 49.1 55.9 10.1 12.5
Overrecovered gas costs -- -- 34.3 84.6
Regulatory effects of accounting for income taxes 17.3 19.5 21.9 24.1
Other 22.7 7.5 6.6 --
- -------------------------------------------------------------------------------------------
TOTAL REGULATORY LIABILITIES 89.1 82.9 72.9 121.2
- -------------------------------------------------------------------------------------------
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
1998 before-tax rates for AFUDC and IDC were 7.43% and 6.96%, respectively. The
1997 and 1996 before-tax rates for AFUDC were 7.09% and 6.15%, respectively, and
for IDC were 7.05% and 6.9%, 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 1998 and 2.5% in 1997 and 1996. The average
annual depreciation rate for the distribution subsidiaries' property was 3.1% in
1998 and 3.2% in 1997 and 1996.
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. 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 as well as to help capture any long-term increases in value.
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 and participation in any long-term increases
in value. In no event does Columbia enter into trading positions that are not
effectively connected with its business.
48
49
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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 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 sheet until they are exercised or expire. Margin
requirements for natural gas and propane futures are also recorded as current
assets. Unrealized gains and losses on all futures contracts, designated as
hedges, are deferred on the consolidated balance sheet 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 futures contracts are
included in products purchased. The cash flows from commodity hedging are
included in operating activities in the consolidated statement of cash flows.
Columbia's gas and power marketing operations utilize futures contracts and
basis swaps to help assure adequate margins on the purchase and resale of
natural gas and electric power. During the fourth quarter of 1998, certain
unusual trading activity in Columbia's gas marketing operations resulted in a
loss. Consistent with generally accepted accounting principles, Columbia applied
mark-to-market accounting for its physical and financial natural gas positions.
The market value of the open physical and financial positions at December 31,
1998, reflected a loss of approximately $6.5 million, which was recorded by
Columbia. Effective January 1, 1999, Columbia will utilize mark-to-market
accounting for all of its gas and power marketing operations and will mark all
physical and financial positions to market in accordance with recently issued
EITF Statement 98-10.
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.
H. GAS INVENTORY. The distribution subsidiaries' gas inventory is carried at
cost on a last-in, first-out (LIFO) basis. The replacement cost of gas inventory
at December 31, 1998, was less than the carrying value by approximately $5
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.
I. 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.
J. 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.
K. 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.
49
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
L. REVENUE RECOGNITION. Columbia's gas distribution subsidiaries bill customers
on a monthly cycle billing basis. Revenues are recorded on the accrual basis
including an estimate for gas delivered but unbilled at the end of each
accounting period.
M. 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 expected through the regulatory process.
N. 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.
O. 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 sheet 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
A. In April 1997, the Federal Energy Regulatory Commission (FERC) approved a
settlement of Columbia Gas Transmission Corporation's (Columbia Transmission)
rate case which provides for an increase in revenues to recover the higher costs
incurred since 1991. The settlement also provides an opportunity for the
recovery of Columbia Transmission's net investment in gathering and certain gas
processing facilities and the continued use of system-wide rates, commonly known
as postage-stamp rates, in lieu of zone rates. Under the settlement, Columbia
Transmission will not place a new rate case into effect prior to February 1,
2000. The settlement allows Columbia Transmission to retain the gain from the
1996 sale of base gas from one of its storage fields, as well as certain future
base gas sales. The settlement rates became effective June 1, 1997 and an
after-tax improvement of $12.4 million was recorded in the second quarter of
1997 to reflect the terms of the settlement, including the base gas sale.
Excluded from the settlement is the environmental cost issue which was to be
addressed in the second phase of the proceeding scheduled for hearings during
the fall of 1998. However, as a result of settlement discussions, the active
parties reached an agreement in principle on the overall components of an
environmental settlement. The comprehensive agreement in principle 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. At this
time, the agreement is either supported or not opposed by all but two parties.
Columbia Transmission anticipates filing a stipulation and agreement with the
FERC in the first quarter of 1999.
B. In its September 1993 order on Columbia Transmission's and Columbia Gulf
Transmission Company's (Columbia Gulf) FERC Order No. 636 (Order 636) compliance
filings, the FERC initiated a proceeding concerning Columbia Gulf's
transportation service to Columbia Transmission. It directed Columbia Gulf to
show cause as to why it had not filed for FERC's abandonment authorization to
reduce capacity on its mainline facilities. In a
50
51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
response to the FERC in late 1993, Columbia Gulf asserted that no abandonment
authorization was required. The FERC issued an order on August 8, 1997,
approving a Stipulation and Consent Agreement that required Columbia Gulf to
conduct a 30-day open season on additional firm mainline capacity up to its
certificated design capacity. The open season concluded on December 15, 1997 and
resulted in requested capacity that exceeded Columbia Gulf's certificated level.
On December 24, 1998, the FERC issued an order rejecting all substantial
challenges and reaffirmed the settlement. On January 25, 1999, a petition for
clarification or rehearing and a separate petition for rehearing of the FERC's
December 24, 1998 order were filed. On February 19, 1999, the FERC issued a
tolling order giving itself additional time to act on the January 25, 1999
petitions. In late February 1999, five parties appealed the December 24, 1998
and August 8, 1997 FERC orders to the Court of Appeals for the District of
Columbia.
C. On January 7, 1998, the Public Utility Commission of Ohio (PUCO) approved an
amendment to the 1994 rate case settlement. The amendment establishes a
five-year funding mechanism that enabled Columbia Gas of Ohio, Inc. (Columbia of
Ohio) to expand its Customer CHOICE(SM) transportation program for residential
and small commercial customers statewide in 1998. The funding mechanism
authorizes Columbia of Ohio to use off-system sales, capacity release revenues
and fees collected from marketers to offset the cost of transition capacity that
may be generated by expansion of the Customer CHOICE(SM) program, while
simultaneously providing Columbia of Ohio with an opportunity to retain some of
the capacity release and off-system sales revenue. The amendment also extends by
one year, to January 1, 2000, Columbia of Ohio's commitment not to implement any
increase in base rates. The amendment gives Columbia of Ohio the responsibility
to manage the transition pipeline capacity costs that will arise as residential
and small commercial customers elect to acquire the commodity directly from
marketers participating in the Customer CHOICE(SM) program, and revenue streams
from a number of sources including off-system sales and capacity releases with
which to manage this responsibility. Columbia of Ohio has accepted the risk for
up to 11% of the transition capacity costs to the extent these costs exceed the
revenue streams available to offset them. However, if after the conclusion of
the five-year program the revenues from these sources more than offset the
transition capacity costs, then customers and Columbia of Ohio will share the
credit balance, 75% to the customers and 25% to Columbia of Ohio. In June 1998,
Columbia of Ohio received approval from the PUCO to extend its Customer
CHOICE(SM) program to all of its nearly 1.3 million customers.
3. STOCK SPLIT EFFECTED IN THE FORM OF A STOCK DIVIDEND
On May 20, 1998, Columbia's board of directors 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.
4. RESTRUCTURING ACTIVITIES
In 1996, Columbia's subsidiaries completed a top-down review of their management
structure and operations in an effort to streamline their organizations and
improve customer service. The studies examined all aspects of Columbia's
operations including the configuration and location of its management.
The transmission subsidiaries' restructuring project focused on all processes
within the companies' operations. These efforts resulted in streamlined business
functions, improved organizational structures and reduced staff levels.
The distribution segment initiated a restructuring of its headquarters'
operations as part of its ongoing efforts to provide enhanced customer service
and to achieve greater operating efficiencies. These initiatives, which are
designed to streamline and enhance customer service, are continuing. Additional
studies are underway in all of the distribution segment's service territories
that may affect the field organizations in functions other than customer service
and may result in additional positions being eliminated, with additional expense
being recorded.
In the third quarter of 1996, Columbia Energy Group Service Corporation,
Columbia LNG Corporation and Columbia Electric Corporation (Columbia Electric),
formerly TriStar Ventures Corporation, implemented restructuring programs and
moved their corporate headquarters from Wilmington, Delaware to Northern
Virginia.
As a result of these restructuring programs, it is estimated that 1,412
management, professional, administrative and technical positions will ultimately
be eliminated. In 1996, Columbia recorded a pre-tax charge of $60.9 million in
51
52
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
operating expense representing severance and related benefit costs, relocation
costs, the establishment of the new corporate center and costs related to the
sale of the former headquarters building. This charge included $52.7 million of
estimated termination benefits. Partially offsetting these charges was a $6
million pre-tax gain on the sale of the former headquarters building. During
1997, Columbia recorded pre-tax charges of $31.1 million in operating expense
representing additional severance and related benefits costs, and additional
relocation costs. This charge included $18.9 million of estimated termination
benefits. As of December 31, 1998, approximately 1,330 employees have been
terminated as a result of these programs and the consolidated balance sheet
reflects an accrual of $4.6 million associated with these restructuring
programs.
5. RISK MANAGEMENT ACTIVITIES
Columbia's gas and power marketing operations utilize futures contracts and
basis swaps to help assure adequate margins on the purchase and resale of
natural gas and electric power. During the fourth quarter of 1998, certain
unusual trading activity in Columbia's gas marketing operations resulted in a
loss. Consistent with generally accepted accounting principles, Columbia applied
mark-to-market accounting for its physical and financial natural gas positions.
The market value of the open physical and financial positions at December 31,
1998, reflected a loss of approximately $6.5 million, which was recorded by
Columbia.
The fair market value of gas trading assets and liabilities were $176.8 million
and $183.3 million, respectively, at December 31, 1998. The average fair market
value of trading assets and liabilities were $117.9 million and $111.9 million,
respectively, for the quarter ended December 31, 1998. Columbia measures the
market risk in its portfolios on a daily basis and employs multiple risk control
mechanisms including value-at-risk measures. Based on a 95% confidence interval
and a one-day time horizon, the value-at-risk for gas trading financial
instruments was approximately $1.8 million as of December 31, 1998.
During the first three quarters of 1998, $15.1 million of losses were recognized
in operating income on the settlement of natural gas option and swap contracts
qualifying for hedge accounting, by the gas marketing subsidiary. These losses
were offset by amounts realized from the sale of the underlying products.
At December 31, 1998, there were 481 net future equivalent contracts to sell
electric power maturing from January 1999 to September 1999 representing a
notional quantity amounting to 354 Gigawatt hours. A total of $0.8 million of
unrealized losses have been deferred on the consolidated balance sheet with
respect to these open contracts. These unrealized losses are largely offset by
gains, which will be realized when the electricity is sold. Based on a 95%
confidence interval and a one-day time horizon, the value-at-risk for the
electric power instruments was approximately $0.4 million as of December 31,
1998. During the year ended December 31, 1998, $0.3 million of losses were
recognized in operating income on the settlement of electric power futures.
Columbia's exploration and production subsidiary hedged a portion of its gas
production that was subject to price volatility through a gas marketing
affiliate. The gas marketing affiliate, in turn, as part of its normal course of
business, hedged these positions in the marketplace. 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 have been deferred on the consolidated
balance sheet with respect to these open contracts. During the year ended
December 31, 1998, $ 11.0 million of gains were realized on contracts settled.
At December 31, 1997, there were 5,443 open contracts representing a notional
quantity amounting to 24.7 Bcf of commodity contracts and 23.0 Bcf of basis
contracts for natural gas production through November 1998 at a combined average
price of $3.02 per Mcf. A total of $8.1 million of unrealized gains have been
deferred on the consolidated balance sheet with respect to these open contracts.
During the year ended December 31, 1997, $4.8 million of losses 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, 1998, there were
620 open contracts through March 1999 representing a notional quantity amounting
to 26.0 million gallons of propane. A total of $0.4 million of unrealized losses
have been deferred on the consolidated balance sheet with respect to these open
contracts. During the year ended December 31, 1998, $1.0 million of losses were
realized on contracts settled. At December 31, 1997, there were 200 open
contracts through February 1998 representing a notional quantity amounting to
8.4 million gallons of propane. No unrealized gains or losses were deferred on
the consolidated balance sheet with respect to these open contracts. During the
year ended December 31, 1997, $0.4 million of gains were realized on contracts
settled.
52
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
6. NEW ACCOUNTING STANDARDS
A. In February 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 132, "Employees' Disclosures about
Pensions and Other Postretirement Benefits" (SFAS No. 132). This statement
revises disclosures about pension and other postretirement benefit plans. It
does not change the measurement or recognition of the costs of those plans. The
disclosures required by this statement are reflected in the December 31, 1998
financial statements. As required by SFAS No. 132, prior periods presented are
restated for comparative purposes (See Note 8).
B. 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 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. This statement is effective
January 1, 2000. Columbia does not anticipate that the adoption of this
statement will have a significant impact on the consolidated financial
statements.
C. In November 1998, the Financial Accounting Standards Board Emerging Issues
Task Force reached a consensus in Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 98-10). This
issue provides guidance regarding the accounting for energy trading contracts.
This consensus should be applied to financial statements issued for fiscal years
beginning after December 15, 1998. The application of EITF 98-10 will not have a
significant impact on the consolidated financial statements as the gas marketing
affiliate commenced marking its physical and financial gas transactions to
market during the fourth quarter of 1998.
53
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
7. INCOME TAXES
The components of income tax expense are as follows:
Year Ended December 31, ($ in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
INCOME TAXES
Current
Federal 98.4 82.4 30.4
State 1.8 7.2 7.5
- --------------------------------------------------------------------------------
Total Current 100.2 89.6 37.9
- --------------------------------------------------------------------------------
Deferred
Federal 46.3 50.4 64.6
State (13.2) (19.6) 14.9
- --------------------------------------------------------------------------------
Total Deferred 33.1 30.8 79.5
- --------------------------------------------------------------------------------
Deferred Investment Credits (1.5) (1.5) (1.5)
- --------------------------------------------------------------------------------
TOTAL INCOME TAXES 131.8 118.9 115.9
- --------------------------------------------------------------------------------
Total income taxes 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) 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
Book income before income taxes 401.0 392.2 337.5
Tax expense at statutory Federal income tax rate 140.4 35.0% 137.3 35.0% 118.1 35.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal income tax benefit (7.4) (1.8) (8.1) (2.1) 16.7 4.9
Estimated non-deductible expenses 1.6 0.4 0.7 0.2 0.9 0.3
Effect of change in deferred taxes previously provided 1.5 0.4 (1.9) (0.5) (4.0) (1.2)
Adjustment to prior year's tax provision
due to pending settlement 0.7 0.2 (3.2) (0.8) (11.3) (3.4)
Other (5.0) (1.3) (5.9) (1.5) (4.5) (1.3)
- -----------------------------------------------------------------------------------------------------------------------------
INCOME TAXES 131.8 32.9% 118.9 30.3% 115.9 34.3%
- -----------------------------------------------------------------------------------------------------------------------------
54
55
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) 1998 1997
- --------------------------------------------------------------------------------
Deferred tax liabilities
Property basis differences 688.1 655.3
Gas purchase costs 55.0 52.4
Partnership deferrals 27.8 27.5
Other 33.1 39.5
- --------------------------------------------------------------------------------
Gross Deferred Tax Liabilities 804.0 774.7
- --------------------------------------------------------------------------------
Deferred tax assets
Estimated supplier obligations (28.2) (28.8)
Estimated rate refunds (21.8) (16.8)
Capitalized inventory overheads (22.1) (26.7)
Unbilled utility revenue (20.9) (23.2)
Benefit plan accruals (16.2) (37.7)
Environmental liabilities (10.5) (8.1)
Tax loss carryforwards (43.9) (48.7)
Deferred revenue (18.4) (17.5)
Other (43.3) (32.7)
- --------------------------------------------------------------------------------
Gross Deferred Tax Assets (225.3) (240.2)
- --------------------------------------------------------------------------------
Deferred Tax Asset Valuation Allowance 31.3 34.4
- --------------------------------------------------------------------------------
NET DEFERRED TAX LIABILITY* 610.0 568.9
- --------------------------------------------------------------------------------
* Includes net current deferred tax assets of $45.3 million and $49.5
million reflected in Current Assets for 1998 and 1997, respectively.
As reflected by the valuation allowance in the table above, Columbia had
potential tax benefits of $31.3 million and $34.4 million at December 31, 1998
and 1997, respectively, which were not recognized in the statements of
consolidated income when generated. These benefits resulted from state income
tax operating loss carryforwards which are available to reduce future tax
liabilities. Management believes there is a risk that certain of these
carryforwards may expire unused and therefore, an asset has not been recorded
for such future benefits. The expiration of the tax loss carryforward benefits,
net of federal taxes, in 1999 is $1.9 million, in 2000 is $1.2 million, in 2001
is $0.4 million, in 2002 is $0.1 million, in 2003 is $0.2 million and beyond is
$40.1 million
8. PENSION AND OTHER POSTRETIREMENT BENEFITS
Columbia has a noncontributory, qualified defined benefit pension plan covering
essentially all employees. Benefits are based primarily on years of credited
service and employees' highest three-year average annual compensation in the
final five years of service. Columbia's funding policy complies with Federal law
and tax regulations. In addition, Columbia has a nonqualified pension plan that
provides benefits to some employees in excess of the qualified plan's Federal
tax limits. Columbia also provides medical coverage and life insurance to
retirees. Essentially all active employees are eligible for these benefits upon
retirement after completing ten consecutive years of service after age 45.
Normally, spouses and dependents of retirees are also eligible for medical
benefits. Columbia is reflecting the information presented below as of September
30, rather than December 31. The effect of utilizing September 30, rather than
December 31, is not significant.
55
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following tables provides a reconciliation of the plans' funded status and
amounts reflected in Columbia's balance sheet at December 31:
PENSION BENEFITS OTHER BENEFITS
--------------------- ---------------------
($ in millions) 1998 1997 1998 1997
- ------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year 888.9 869.9 309.8 287.2
Service cost 31.3 28.7 13.0 11.2
Interest cost 64.7 67.6 23.4 23.1
Plan participants' contributions -- -- 2.7 --
Plan amendments -- -- (2.2) --
Actuarial gain 56.0 35.4 6.2 7.5
Settlements -- -- (130.3) --
Actual expense paid (5.2) (6.1) -- --
Benefits paid (88.9) (106.6) (23.7) (19.2)
- ------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 946.8 888.9 198.9 309.8
- ------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year 1,164.6 1,033.9 242.9 179.6
Actual return on plan assets 20.8 243.1 11.2 48.3
Columbia contributions -- -- 32.4 34.2
Plan participants' contributions -- -- 2.8 --
Settlements -- -- (146.9) --
Actual expense paid (5.2) (6.1) (1.7) --
Benefits paid (88.7) (106.3) (23.7) (19.2)
- ------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 1,091.5 1,164.6 117.0 242.9
- ------------------------------------------------------------------------------------------------------
Funded status of plan at end of year 144.7 275.7 (81.9) (66.9)
Unrecognized actuarial net gain (237.8) (390.2) (41.5) (129.9)
Unrecognized prior service cost 45.1 48.9 (2.2) --
Unrecognized transition obligation 4.6 5.8 -- --
Fourth quarter contributions -- -- 4.5 7.4
- ------------------------------------------------------------------------------------------------------
ACCRUED BENEFIT COST (43.4) (59.8) (121.1) (189.4)
- ------------------------------------------------------------------------------------------------------
PENSION BENEFITS OTHER BENEFITS
--------------------- ---------------------
1998 1997 1998 1997
- ------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF
SEPTEMBER 30,
Discount rate assumption 6.75% 7.50% 6.75% 7.50%
Compensation growth rate assumption 4.40% 4.30% 4.40% 4.30%
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%
56
57
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) 1998 1997 1996 1998 1997 1996
- -------------------------------------------------------------------------------------------------------
NET PERIODIC COST
Service cost 31.3 28.7 35.0 13.0 11.2 13.8
Interest cost 64.7 67.6 70.7 23.5 23.1 22.4
Expected return on assets (99.7) (88.2) (90.3) (18.3) (13.1) (12.0)
Amortization of transition obligation 1.2 1.2 1.2 -- -- --
Recognized gain (17.5) (11.3) (2.0) (10.3) (9.6) (5.9)
Prior service cost amortization 3.7 3.7 4.1 -- -- --
Settlement gain -- -- -- (46.6) -- --
- -------------------------------------------------------------------------------------------------------
NET PERIODIC BENEFITS COST (BENEFIT) (16.3) 1.7 18.7 (38.7) 11.6 18.3
- -------------------------------------------------------------------------------------------------------
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 $ 2.8 $ (2.6)
Effect on accumulated postretirement benefit obligation $ 14.9 $ (14.5)
- -------------------------------------------------------------------------------------
In March 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. This resulted in a pre-tax gain in the
amount of $46.6 million. This gain is reflected in the financial statements as a
$25.4 million reduction to benefits expense, and a $21.2 million liability of
certain rate-regulated companies.
9. LONG-TERM INCENTIVE PLAN
On April 26, 1996, shareholders approved a new Long-Term Incentive Plan (New
LTIP). The New 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 New LTIP also provides for the
granting of nonqualified stock options to outside directors. A total of
3,000,000 shares of Columbia's authorized common stock is available under the
New LTIP's provisions.
On April 26, 1996, shareholders also approved 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 Long-Term Incentive Plan (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 initially reserved for issuance under the 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 LTIP generally
have a maximum term of ten years and vest over two to four years.
57
58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Transactions for the three years ended December 31, 1998, are as follows:
Options
-----------------------------
Without Stock With Stock Options
Appreciation Appreciation Price
Rights Rights Range
- --------------------------------------------------------------------------------------------------
Outstanding at December 31, 1995 524,320 150,050 $28.99-$46.68
Granted 100,000 -- $48.6875
Exercised (209,625) (66,860) $28.99-$46.68
Forfeited (9,020) (7,260) $34.30-$46.68
- --------------------------------------------------------------------------------------------------
Outstanding at December 31, 1996 405,675 75,930 $28.99-$48.6875
Granted 1,133,350 -- $58.375-$71.0938
Exercised (183,138) (48,790) $28.99-$63.6875
Forfeited (41,962) (3,240) $34.30-$63.6875
- --------------------------------------------------------------------------------------------------
Outstanding at December 31, 1997 1,313,925 23,900 $28.99-$71.0938
Granted 853,300 -- $76.15625-$77.5625
Exercised (92,821) -- $28.99-$63.6875
Forfeited (9,000) -- $58.375-$76.15625
Adjustment for three-for-two stock split 1,032,700 11,950 $19.33-$51.7083*
Granted 20,800 -- $52.875-$58.375
Exercised (114,579) (26,190) $19.33-$42.4583
Forfeited (19,050) -- $ 50.77083
- --------------------------------------------------------------------------------------------------
OUTSTANDING AT DECEMBER 31, 1998 2,985,275 9,660 $19.33-$58.375
- --------------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 1998 1,193,300 9,660 $19.33-$51.7083
- --------------------------------------------------------------------------------------------------
* Reflects repricing of outstanding stock options for the effect of the
three-for-two common stock split.
Regarding the stock options granted in 1998 and 1997, such options vest ratably
over three years. Regarding the stock options granted in 1996, 50% of such
options vested in 1996 and the other 50% vested in 1997.
The following table shows the weighted-average option exercise price information
for the three years ended December 31:
1998 1997 1996
- --------------------------------------------------------------------------------
Outstanding at January 1 $ 59.37 $ 42.88 $ 41.31
Granted during the year 75.69 63.40 48.69
Exercised during the year 43.97 44.31 41.07
Forfeited during the year 55.49 62.01 44.15
OUTSTANDING AT DECEMBER 31 44.79 59.37 42.88
EXERCISABLE AT DECEMBER 31 39.56 54.70 42.21
- --------------------------------------------------------------------------------
In 1996, contingent stock awards totaling 1,500 shares were granted and issued
to one key executive. There were no contingent stock awards granted in 1997 or
1998. Restricted stock awards totaling 29,785 shares were granted to one key
executive in 1996 of which 5,957 shares vested during 1997 and 5,957 shares
vested during 1998.
During 1998, 1997 and 1996, $2.4 million, $3.2 million and $2.1 million were
expensed for the long-term incentive plans, respectively.
Had compensation cost been determined consistent with the provisions of the SFAS
No. 123 fair value method (See Note 1), Columbia's net income would have been
$258.4 million (earnings per share of $3.10 and diluted earnings per share of
$3.09) in 1998 and $266.8 million (earnings per share of $3.21 and diluted
earnings per share of $3.19) in 1997. The effect on Columbia's net come and
earnings per share for 1996 would have been immaterial. The fair value of each
option grant is estimated on the date of grant using the Black-Scholes
option-pricing model with the following assumptions used for grants in 1998,
1997 and 1996: dividend yield of zero percent for 1998, 1997 and 1996 to reflect
dividend equivalents applicable to awards granted; expected volatility ranging
from 14.97% to 17.40% for 1998, 18.41% to 19.29% for 1997 and 20.12% for 1996;
risk-free interest rates ranging from 4.90% to 5.77% for 1998, 5.86% to 6.89%
for 1997 and 6.58% for 1996; and expected lives of seven years. The
weighted-average fair market value of options granted were $17.79, $24.85 and
$19.80 for 1998, 1997 and 1996, respectively.
58
59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
10. LONG-TERM DEBT
The long-term debt (exclusive of current maturities) of Columbia and its
subsidiaries is as follows:
At December 31, ($ in millions) 1998 1997
- --------------------------------------------------------------------------------
Columbia Energy Group Debentures
6.39% Series A due November 28, 2000 311.0 311.0
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 281.5 281.5
- --------------------------------------------------------------------------------
Total Debentures 2,000.0 2,000.0
Subsidiary Debt:
Capitalized lease obligations 3.1 2.7
Other -- 0.8
- --------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 2,003.1 2,003.5
- --------------------------------------------------------------------------------
During 1998, Columbia entered into interest rate swap agreements to modify the
interest characteristics of its outstanding long-term debt. At December 31,
1998, 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 $100
million notional amount of its 6.80% Series C Debentures due November 28, 2005.
Under the terms of the agreements, Columbia pays interest based on a floating
rate index and receives interest based on a fixed rate. The effect of these
agreements is to modify the interest rate characterization of a portion of
Columbia's long-term debt from fixed to variable. The effect of these interest
rate swaps on interest expense at December 31, 1998, was immaterial.
The aggregate maturities of long-term debt and capitalized lease obligations
during the next five years are as follows:
($ in millions)
- --------------------------------------------------------------------------------
1999 0.3
2000 311.2
2001 0.2
2002 281.8
2003 0.3
- --------------------------------------------------------------------------------
11. SHORT-TERM DEBT AND CREDIT FACILITIES
In March 1998, Columbia established two new unsecured bank revolving credit
facilities that total $1.35 billion (New Credit Facilities) to replace the $1
billion five-year revolving credit agreement entered into by Columbia in
November 1995. The New 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 New Credit Facilities are based upon the London Interbank
Offered Rate or Citibank's publicly announced "base rate." Facility fee payments
are based upon 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 New 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, 1998, Columbia had no borrowings outstanding under the New
Credit Facilities. The maximum indebtedness outstanding during the year occurred
on January 1, 1998, in the amount of $120 million at an average interest rate of
6.17%.
59
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
As of December 31, 1998, Columbia had $44.4 million of letters of credit
outstanding under the New 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 a $75
million letter of credit outstanding at December 31, 1998 and December 31, 1997,
as a guarantee of certain transactions of its wholly owned marketing affiliate.
Fees for the letter of credit issued were at a rate of 0.35%.
Columbia has an $850 million commercial paper program authorized and rated by
the rating agencies. The commercial paper program is supported by the New Credit
Facilities. 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%.
The maximum commercial paper indebtedness outstanding during the year occurred
on February 6, 1998, in the amount $237.1 million at an average interest rate of
5.72%. At December 31, 1997, Columbia had commercial paper outstanding of $208.1
million (net of discount) at a weighted-average interest rate of 6.42%
In November 1995, Columbia entered into an unsecured $1 billion five-year
revolving credit agreement (Credit Facility). The Credit Facility was used to
support outstanding commercial paper and to meet other short-term requirements.
Interest rates on borrowings were based upon the London Interbank Offered Rate,
Certificate of Deposit rates or other short-term interest rates including a
facility fee on the commitment amount at a rate based on Columbia's public debt
rating. The facility fee rate as of December 31, 1997 was 0.11%.
At December 31, 1997, Columbia had outstanding $120 million under the Credit
Facility at an average interest rate of 6.17%. Columbia had $42.7 million of
letters of credit outstanding at December 31, 1997 under the Credit Facility.
Fees for letters of credit issued under the Credit Facility were calculated at
rates based on Columbia's public debt rating plus a commission of 0.125% to the
issuing bank.
At December 31, 1998, approximately $7.6 million of investments were pledged as
collateral on outstanding letters of credit related to Columbia's wholly owned
insurance company.
12. 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 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 11) 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 ($3.3 million for 1998 and $3.7
million for 1997) 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 ($11.8 million for 1998 and $7.5 million
for 1997), 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 $15.1 million and $11.2 million,
and estimated fair values of $14.7 million and $10.8 million at December 31,
1998 and 1997, respectively. There are no long-term investments for which it is
not practicable to estimate fair value at December 31, 1998 and 1997.
LONG-TERM DEBT
The estimated fair value of Columbia's debentures, including accrued interest,
is based on estimates provided by brokers. Long-term debt of $2,012.9 million
and $2,012.9 million at December 31, 1998 and 1997, have estimated fair values
of $2,088.1 million and $2,051.6 million, respectively.
60
61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
13. OTHER COMMITMENTS AND CONTINGENCIES
A. EMERGENCE FROM CHAPTER 11 OF THE BANKRUPTCY CODE. On November 28, 1995,
Columbia and its wholly owned subsidiary, Columbia Transmission emerged from
Chapter 11 protection of the Federal 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. In settlement of its prepetition obligations,
Columbia distributed approximately $3.6 billion to its creditors, which included
$2.3 billion in payment of Columbia's prepetition debt and approximately $1
billion of interest on that debt. Certain residual unresolved bankruptcy-related
matters are still within the jurisdiction of the Bankruptcy Court. The final
resolution of these issues is not expected to have a significant impact on
Columbia's consolidated financial results.
B. CAPITAL EXPENDITURES. Capital expenditures for 1999 are currently estimated
at $650 million. Of this amount, $237 million is for transmission and storage
operations, $152 million for distribution operations, $104 million for
exploration and production operations, $20 million for marketing operations,
$129 million for propane, power generation and LNG operations and $8 million for
corporate.
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:
Pedricktown Cogeneration Limited Partnership and Vineland Cogeneration Limited
Partnership (the "Partnerships") own and operate project-financed non-utility
power generation facilities in New Jersey. The assets of the Partnerships,
including plant facilities and contract rights, have been pledged as collateral
for loans to a bank syndicate in the case of Pedricktown, or to an indenture
trustee for the benefit of certain bondholders in the case of Vineland.
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, 1998,
amounted to $18.6 million.
E. 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.
F. OPERATING LEASES. Payments made in connection with operating leases are
primarily charged to operation and maintenance expense as incurred. Such amounts
were $63.8 million in 1998, $62.9 million in 1997 and $60.9 million in 1996.
Future minimum rental payments required under operating leases that have initial
or remaining noncancellable lease terms in excess of one year are:
($ in millions)
- --------------------------------------------------------------------------------
1999 35.5
2000 31.9
2001 28.1
2002 27.0
2003 26.6
After 187.4
- --------------------------------------------------------------------------------
61
62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
G. 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, 1998, were:
($ in millions)
- --------------------------------------------------------------------------------
1999 60.0
2000 55.7
2001 42.5
2002 39.8
2003 34.7
After 138.3
- --------------------------------------------------------------------------------
Costs incurred under these contracts are recovered under Columbia's regulatory
cost recovery mechanisms.
H. 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 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 15,000 liquid removal
points, approximately 2,800 mercury measurement stations, and about 3,700
storage wells. As of December 31, 1998, field characterization has been
performed at many of these sites, and site characterization reports and
remediation plans are being prepared for submission to EPA for approval.
Significant remediation has taken place only at mercury measurement stations.
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.
As a result of 1998 activities, Columbia Transmission recorded an additional
liability of $28.8 million. Actual expenditures of approximately $16 million
during 1998 charged to the liability resulted in a remaining liability of $138.2
million. Columbia Transmission's environmental cash expenditures are expected to
be approximately $18 million in 1999 and up to $20 million annually until the
AOC is satisfied. 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 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 15 former manufactured gas
plant sites. Investigations or remedial activities are currently underway at
seven sites and have been completed at one site. 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 action established, the appropriate 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.
62
63
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
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 $140.9 million
for Columbia at December 31, 1998. As new issues are identified, additional
liabilities will be recorded.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve mutually
acceptable compliance plans. However, there can be no assurance that fines and
penalties will not be incurred. Management expects most environmental assessment
and remediation costs to be recoverable through rates.
I. DISCUSSIONS WITH FERC. The transmission and storage subsidiaries are in
confidential and informal discussions with the staff of the FERC concerning the
scope of authorizations for certain past transactions under the relevant filed
tariffs. The transmission and storage subsidiaries have initiated these
discussions with the FERC. Because these discussions are in a very preliminary
stage, management is unable to reasonably estimate the amount that will have to
be paid pursuant to reimbursement or other remedies.
14. INTEREST INCOME AND OTHER, NET
Year Ended December 3l, ($ in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
Interest income 13.6 21.0 13.4
Miscellaneous (0.2) 19.4 12.7
- --------------------------------------------------------------------------------
TOTAL INTEREST INCOME AND OTHER, NET 13.4 40.4 26.1
- --------------------------------------------------------------------------------
15. INTEREST EXPENSE AND RELATED CHARGES
Year Ended December 31, ($ in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
Interest on debentures 140.4 140.4 140.4
Interest on short-term debt 10.9 8.1 11.7
Discount on prepayment transactions 7.8 0.1 --
Interest on rate refunds 2.3 3.4 3.9
Interest on prior years' taxes (6.3) 9.1 8.3
Allowance for borrowed funds used
and interest during construction (2.7) (3.5) 2.5
- --------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE AND RELATED CHARGES 152.4 157.6 166.8
- --------------------------------------------------------------------------------
63
64
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
16. 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 18 direct subsidiaries. Effective
June 30, 1998, in accordance with generally accepted accounting principles,
Columbia revised the presentation of its business segments. 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, midatlantic, 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 marketing segment provides gas and electricity supply,
fuel management and transportation-related services to a diverse customer base
including cogenerators, local distribution companies, industrial plants,
commercial businesses, joint marketing partners and residential customers. The
propane, power generation and LNG segment includes the sale of propane at
wholesale and retail to customers in eight states, participation in natural gas
fueled electric generation projects and peaking services.
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 on the basis
of prevailing market or regulated prices. Operating income is derived from
revenues and expenses directly associated with each segment.
($ in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
REVENUES
Transmission and Storage
Unaffiliated 523.0 505.7 450.4
Intersegment 315.7 332.9 354.6
- --------------------------------------------------------------------------------
TOTAL 838.7 838.6 805.0
- --------------------------------------------------------------------------------
Distribution
Unaffiliated 1,843.3 2,283.6 2,120.4
Intersegment 26.2 12.7 7.3
- --------------------------------------------------------------------------------
TOTAL 1,869.5 2,296.3 2,127.7
- --------------------------------------------------------------------------------
Exploration and Production
Unaffiliated 65.2 44.3 45.5
Intersegment 62.3 69.0 59.0
- --------------------------------------------------------------------------------
TOTAL 127.5 113.3 104.5
- --------------------------------------------------------------------------------
Marketing
Unaffiliated 4,047.5 2,121.9 645.6
Intersegment 24.7 65.1 82.4
- --------------------------------------------------------------------------------
TOTAL 4,072.2 2,187.0 728.0
- --------------------------------------------------------------------------------
Propane, Power Generation and LNG
Unaffiliated 89.2 98.3 91.7
Intersegment 0.5 2.1 2.5
- --------------------------------------------------------------------------------
TOTAL 89.7 100.4 94.2
- --------------------------------------------------------------------------------
Adjustments and eliminations
Unaffiliated -- (0.2) 0.4
Intersegment (429.4) (481.8) (505.8)
- --------------------------------------------------------------------------------
TOTAL (429.4) (482.0) (505.4)
- --------------------------------------------------------------------------------
CONSOLIDATED 6,568.2 5,053.6 3,354.0
- --------------------------------------------------------------------------------
64
65
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
($ in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
OPERATING INCOME (LOSS)
Transmission and Storage 326.1 258.3 206.2
Distribution 225.8 224.2 226.0
Exploration and Production 37.2 30.9 30.0
Marketing (59.0) (13.2) 4.5
Propane, Power Generation
and LNG 10.7 16.3 9.6
Corporate (0.8) (7.1) 1.9
- --------------------------------------------------------------------------------
CONSOLIDATED 540.0 509.4 478.2
- --------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
Transmission and Storage 101.8 104.3 102.6
Distribution 82.2 78.2 74.4
Exploration and Production 36.5 27.6 28.8
Marketing 4.1 1.6 0.3
Propane, Power Generation
and LNG 5.1 3.6 2.8
Corporate 5.0 5.5 5.7
Adjustments and eliminations 0.5 0.5 0.6
- --------------------------------------------------------------------------------
CONSOLIDATED 235.2 221.3 215.2
- --------------------------------------------------------------------------------
ASSETS
Transmission and Storage 2,837.6 2,775.4 2,774.3
Distribution 2,629.9 2,753.2 2,648.1
Exploration and Production 590.9 564.6 511.9
Marketing 778.7 509.4 205.7
Propane, Power Generation
and LNG 193.0 155.7 133.5
Corporate 4,298.0 4,221.4 3,924.6
Adjustments and eliminations (4,359.4) (4,367.4) (4,193.5)
- --------------------------------------------------------------------------------
CONSOLIDATED 6,968.7 6,612.3 6,004.6
- --------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Transmission and Storage 204.0 244.9 142.7
Distribution 151.9 159.5 148.4
Exploration and Production 75.7 158.7 12.1
Marketing 16.0 5.1 0.8
Propane, Power Generation
and LNG 20.1 9.9 5.5
Corporate 11.0 5.3 5.3
Adjustments and eliminations -- (23.1) --
- --------------------------------------------------------------------------------
CONSOLIDATED 478.7 560.3 314.8
- --------------------------------------------------------------------------------
65
66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
17. 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
- ------------------------------------------------------------------------------------------------
1998
Net Revenues 622.5 385.6 350.2 538.8
Operating Income 254.2 70.9 54.1 160.8
Net Income 147.5(a) 22.8 11.2 87.7(b)
Per Share Amounts
Earnings Per Share of Common Stock 1.77 0.27 0.13 1.05
Diluted Earnings Per Share of
Common Stock 1.77 0.27 0.13 1.05
- ------------------------------------------------------------------------------------------------
1997
Net Revenues 628.1 407.1 331.3 549.0
Operating Income 256.6 84.3 29.7 138.8
Net Income 162.7(c) 34.9(d) 0.1 75.6(e)
Per Share Amounts
Earnings Per Share of Common Stock 1.96 0.42 -- 0.91
Diluted Earnings Per Share of
Common Stock 1.96 0.42 -- 0.90
(a) Includes $8.7 million from the sale of base gas, $16.5 million gain on
settlement of postretirement benefit costs and a $10 million benefit from
state tax planning initiatives.
(b) Includes $10.6 million reduction on the marketing segment for a provision
for amounts that presently do not have adequate third party documentation.
(c) Includes $12.8 million reduction in state income tax expense and $5.5
million gain on deactivation of a storage field.
(d) Includes $12.4 million from the sale of base gas.
(e) Includes the net income effect of $6.0 million for the sale of coal
assets.
18. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
During the first quarter of 1998, Columbia Energy Resources, Inc. (Columbia
Resources) purchased wells and undeveloped property in Ontario, Canada. In June
1998, Columbia Resources further broadened its Canadian operations by entering
into a joint venture with CanEnerco, Ltd. Under the terms of the agreement,
Columbia Resources and CanEnerco, Ltd. will jointly develop drilling properties
in southwestern Ontario, Canada.
On August 7, 1997, Columbia Resources acquired Alamco, Inc. (Alamco), a gas and
oil production company operating in the Appalachian Basin. On April 30, 1996,
Columbia sold Columbia Gas Development Corporation, its wholly owned southwest
exploration and production subsidiary, effective December 31, 1995. 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, 1995 599.5 1,651 -- --
Revisions of previous estimate 78.9 (169) -- --
Extensions, discoveries
and other additions 5.5 161 -- --
Production (33.6) (281) -- --
Sale of reserves-in-place (5.8) (588) -- --
- -------------------------------------------------------------------------------------------
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) (13.0)
Purchase of reserves-in-place -- -- 1.1 77.0
Sale of reserves-in-place (9.6) -- -- --
- -------------------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1998 789.5 1,771 1.0 64.0
- -------------------------------------------------------------------------------------------
Proved developed reserves as of
December 31,
1996 518.3 730 -- --
1997 653.2 1,330 -- --
1998 586.2 1,436 1.0 64.0
- -------------------------------------------------------------------------------------------
(a) Includes the purchase of Alamco.
CAPITALIZED COSTS United States Canada Total
- -----------------------------------------------------------------------------------------------------------------------------
($ in millions) 1998 1997 1996 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
CAPITALIZED COSTS AT YEAR END
Proved properties 673.2 628.4 475.4 1.4 -- -- 674.6 628.4 475.4
Unproved properties (a) 40.8 31.8 27.4 3.7 -- -- 44.5 31.8 27.4
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 714.0 660.2 502.8 5.1 -- -- 719.1 660.2 502.8
Accumulated depletion (225.2) (196.0) (146.4) (0.2) -- -- (225.4) (196.0) (146.4)
- -----------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS 488.8 464.2 356.4 4.9 -- -- 493.7 464.2 356.4
- -----------------------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR (b)
Acquisition properties
Proved -- -- -- 0.7 -- -- 0.7 -- --
Unproved 0.6 0.1 0.7 3.0 -- -- 3.6 0.1 0.7
Exploration 2.3 1.0 2.7 -- -- -- 2.3 1.0 2.7
Development 62.1 132.4 8.7 1.4 -- -- 63.5 132.4 8.7
- -----------------------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED 65.0 133.5 12.1 5.1 -- -- 70.1 133.5 12.1
- -----------------------------------------------------------------------------------------------------------------------------
(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
$3.3 million in 1998, $1.4 million in 1997 and $0.9 million in 1996.
67
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
OTHER EXPLORATION AND PRODUCTION DATA United States Canada
- ---------------------------------------------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
Average sales price per Mcf of gas ($)(a) 2.91 2.63 2.84 2.61 -- --
Average sales price per barrel
of oil and other liquids ($) 12.53 17.99 19.07 16.42 -- --
Production (lifting) cost per
dollar of gross revenue ($) 0.21 0.24 0.22 0.32 -- --
Depletion rate per dollar
of gross revenue ($) 0.29 0.28 0.29 0.27 -- --
- ---------------------------------------------------------------------------------------------------------
(a) Includes the effect of hedging activities.
HISTORICAL RESULTS OF OPERATIONS
United States Canada Total
- ---------------------------------------------------------------------------------------------------------------
($ in millions) 1998 1997 1996 1998 1997 1996 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------
Gross revenues
Unaffiliated 53.7 27.4 43.1 0.6 -- -- 54.3 27.4 43.1
Affiliated 62.3 69.0 58.8 -- -- -- 62.3 69.0 58.8
Production costs 24.2 23.3 21.7 0.2 -- -- 24.4 23.3 21.7
Depletion 33.5 26.6 28.8 0.2 -- -- 33.7 26.6 28.8
Income tax expense 20.7 14.3 15.1 0.1 -- -- 20.8 14.3 15.1
- ---------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 37.6 32.2 36.3 0.1 -- -- 37.7 32.2 36.3
- ---------------------------------------------------------------------------------------------------------------
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) 1998 1997 1996 1998 1997 1996 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------
Future cash inflows 2,094.4 2,503.0 2,389.1 3.4 -- -- 2,097.8 2,503.0 2,389.1
Future production costs (585.5) (719.9) (715.5) (1.5) -- -- (587.0) (719.9) (715.5)
Future development costs (200.4) (182.7) (165.8) (0.1) -- -- (200.5) (182.7) (165.8)
Future income tax expense (487.8) (557.5) (499.7) (0.7) -- -- (488.5) (557.5) (499.7)
- ----------------------------------------------------------------------------------------------------------------------------
Future net cash flows 820.7 1,042.9 1,008.1 1.1 -- -- 821.8 1,042.9 1,008.1
Less: 10% discount 440.1 582.2 574.4 0.3 -- -- 440.4 582.2 574.4
- ----------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF
DISCOUNTED FUTURE
NET CASH FLOW 380.6 460.7 433.7 0.8 -- -- 381.4 460.7 433.7
- ----------------------------------------------------------------------------------------------------------------------------
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) 1998 1997 1996 1998 1997 1996 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------
Beginning of year 460.7 433.7 316.0 -- -- -- 460.7 433.7 316.0
- ---------------------------------------------------------------------------------------------------------------------------
Gas and oil sales,
net of production costs (91.9) (73.1) (80.2) (0.4) -- -- (92.3) (73.1) (80.2)
Net changes in prices
and production costs (108.5) (107.8) 170.4 -- -- -- (108.5) (107.8) 170.4
Change in future
development costs (10.0) (16.9) 0.5 -- -- -- (10.0) (16.9) 0.5
Extensions, discoveries
and other additions,
net of related costs 77.5 51.9 9.4 -- -- -- 77.5 51.9 9.4
Revisions of previous
estimates, net of
related costs (18.0) 64.0 90.1 -- -- -- (18.0) 64.0 90.1
Sales of reserves-in-place (12.0) (4.1) (18.4) -- -- -- (12.0) (4.1) (18.4)
Purchases of reserves-in-place -- 67.0 -- 1.7 -- -- 1.7 67.0 --
Accretion of discount 70.1 64.3 46.0 -- -- -- 70.1 64.3 46.0
Net change in income taxes 21.1 (30.5) (65.3) (0.5) -- -- 20.6 (30.5) (65.3)
Timing of production
and other changes (8.4) 12.2 (34.8) -- -- -- (8.4) 12.2 (34.8)
- ---------------------------------------------------------------------------------------------------------------------------
END OF YEAR 380.6 460.7 433.7 0.8 -- -- 381.4 460.7 433.7
- ---------------------------------------------------------------------------------------------------------------------------
69
70
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
1998 18.7 43.1 6.6 34.2 34.2
1997 16.2 29.8 19.8 47.1 18.7
1996 12.3 25.6 17.7 39.4 16.2
- --------------------------------------------------------------------------------------------------------
(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.
70
71
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
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 1999 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, 46, 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, 52, 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, 54, 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, 48, 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, 52, Senior Vice President for Strategy and Communications
for Columbia since May 1998. Vice President of the Natural Gas Supply
Association from 1983 through 1996. Manager, Energy Liason 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 1999 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 1999 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 1999 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
71
72
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Exhibits
Reference is made to pages 74 through 76 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
A report on Form 8-K was filed on October 13, 1998, containing a Press Release
issued that day announcing earnings for the three and nine months ended
September 30, 1998.
Financial
Item Statements
Reported Included Date of Event Date Filed
-------- ---------- ---------------- ----------------
5 Yes October 13, 1998 October 13, 1998
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. 33-03869 (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.
72
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 26, 1999
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 26, 1999 /s/ Oliver G. Richard III March 26, 1999 /s/ J. Bennett Johnston
---------------------------- ----------------------------
Director (Principal J. Bennett Johnston
Executive Officer) Director
March 26, 1999 /s/ Richard F. Albosta March 26, 1999 /s/ Malcolm Jozoff
---------------------------- ----------------------------
Richard F. Albosta Malcolm Jozoff
Director Director
March 26, 1999 /s/ Robert H. Beeby March 26, 1999 /s/ William E. Lavery
---------------------------- ----------------------------
Robert H. Beeby William E. Lavery
Director Director
March 26, 1999 /s/ Wilson K. Cadman March 26, 1999 /s/ Gerald E. Mayo
---------------------------- ----------------------------
Wilson K. Cadman Gerald E. Mayo
Director Director
March 26, 1999 /s/ Jeffrey W. Grossman March 26, 1999 /s/ Michael W. O'Donnell
---------------------------- ----------------------------
Jeffrey W. Grossman Michael W. O'Donnell
Vice President & Controller Senior Vice President
(Principal Accounting Officer) (Chief Financial Officer)
March 26, 1999 /s/ James P. Heffernan March 26, 1999 /s/ Douglas E. Olesen
---------------------------- ----------------------------
James P. Heffernan Douglas E. Olesen
Director Director
March 26, 1999 /s/ Karen L. Hendricks March 26, 1999 /s/ William R. Wilson
---------------------------- ----------------------------
Karen L. Hendricks William R. Wilson
Director Director
March 26, 1999 /s/ Malcolm T. Hopkins
----------------------------
Malcolm T. Hopkins
Director
73
74
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
3-A - Restated Certificate of Incorporation of The Columbia 1-1098 3-A
Gas System, Inc., 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.
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
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 System, Inc., 1-1098 10-P
amended October 9, 1991.
10-Q(a) - Thrift Restoration Plan of The Columbia Gas System, Inc. 1-1098 10-Q
dated January 1, 1989.
10-T - Agreement and Bridge Agreement dated December 1, 1993, 1-1098 10-T
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.
74
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., dated 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 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, between 1-1098 10-BV
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 Agreement dated, 1-1098 10-BY
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, among The 1-1098 10-CB
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
Company, L.P. dated May 31, 1998.
10-CH * - Contribution Agreement Between Columbia Gas Transmission
Corporation and Millennium Pipeline Company, L.P. dated July 31, 1998
10-CI * - Regulations of Millennium Pipeline Management Company, L.L.C.
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.
* Filed herewith.
75
76
EXHIBIT INDEX (continued)
Reference
----------------------------
File No. Exhibit
10-CK * - Amended and Restated 364-Day Credit Agreement among Columbia
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 Corporation 1-1098 10-CM
as filed with the United States Bankruptcy Court for the District
of Delaware on January 18, 1994.
12 * - Statements of Ratio of Earnings to Fixed Charges
21 * - Subsidiaries of Columbia Energy Group
23-A * - Letter report, dated January 22, 1999, and the written consent to
the filing and use of information contained in such letter report,
Reports and Registration Statements filed during 1998, 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 1998 Annual Report on Form 10-K of Columbia
Energy Group and their report included in Columbia Energy Group's
1998 Annual Report to Shareholders in the registration statements
on Form S-8 (File No. 33-03869), and Form S-8 (File No. 33-42776).
23-C * - Letter report, dated February 2, 1999, and the written consent to the filing
and use of information contained in such letter report, Reports and
Registration Statements filed during 1998, of Sproule Associates Limited,
independent petroleum and natural gas consultants.
27 * - Financial Data Schedule for the period ended December 31, 1998.
* Filed herewith.
76