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1
Commission File No. 1-1098
As filed with the United States Securities and Exchange Commission on February
23, 1996.
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
/ X / OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended DECEMBER 31, 1995
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
/ / OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____ to _____
T H E C O L U M B I A G A S S Y S T E M, I N C.
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(Exact name of registrant as specified in its charter)
Delaware 13-1594808
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(State or other Jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
20 Montchanin Road, Wilmington, Delaware 19807-0020
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (302) 429-5000
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Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common Stock, $10 Par Value . . . . . . . . . . . . . . . . . . . . . . . . . . New York Stock Exchange
7.89% Redeemable Preferred Stock, Series A
5.22% Convertible Preferred Stock, Series B
Debentures
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6.39% Series A due November 28, 2000
6.61% Series B due November 28, 2002
6.80% Series C due November 28, 2005
7.05% Series D due November 28, 2007
7.32% Series E due November 28, 2010
7.42% Series F due November 28, 2015
7.62% Series G due November 28, 2025
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the proceeding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days: Yes X or No .
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. / /
The aggregate market value of the outstanding common shares of the Registrant
held by nonaffiliates as of January 31, 1996, was $2,132,925,000. For purposes
of the foregoing calculation, all directors and/or officers have been deemed to
be affiliates, but the registrant disclaims that any of such directors and/or
officers is an affiliate.
The number of shares outstanding of each class of common stock as of January
31, 1996, was : Common Stock $10 Par Value: 49,208,385 shares outstanding.
Documents Incorporated by Reference
-----------------------------------
Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the 1996 Annual Meeting of Stockholders and the Quarterly
Form 10-Q for the period ended September 30, 1995.
2
CONTENTS
Page
Part I No.
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Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . 14
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 14
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . 15
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations . . . . . . . . . . . . . . . . . . . . . 17
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . 42
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . 77
Part III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . 77
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . 78
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . 78
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . 78
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . 78
Undertaking made in Connection with 1933 Act Compliance on Form S-8 . . . . . 79
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
3
PART I
ITEM 1. BUSINESS
General
The Columbia Gas System, Inc. (Columbia) 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
oil and natural gas. Columbia is also engaged in related energy businesses
including the marketing of natural gas, the generation of electricity,
primarily fueled by natural gas; and the distribution of propane. Columbia was
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 its 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 System.
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 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 Operations
Columbia's two interstate pipeline subsidiaries, Columbia Transmission and
Columbia Gulf Transmission Company (Columbia Gulf), operate a 23,200-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.
The transmission subsidiaries serve directly or indirectly eight million
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.
Since November 1, 1993, following a fundamental restructuring of the gas
industry that was brought about by new federal regulations, Columbia
Transmission has eliminated its merchant function. It now provides 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.
Distribution Operations
Columbia's five distribution subsidiaries provide natural gas service to nearly
2 million residential, commercial and industrial customers in Ohio,
Pennsylvania, Virginia, Kentucky and Maryland. The distribution subsidiaries
purchase gas for and sell gas to high priority (mostly residential) customers
and transport gas for certain industrial and commercial customers who purchase
gas from other sources. More than 30,600 miles of distribution pipelines serve
these major markets.
Oil and Gas Operations
Columbia's oil and gas exploration and production subsidiaries, Commonwealth
Natural Resources, Inc. (CNR) and Columbia Gas Development Corporation
(Columbia Development), explore for, develop and produce oil and natural gas in
the United States. In an effort to strategically focus its resources, Columbia
recently announced its intent to sell Columbia Development, its Southwest oil
and gas subsidiary. Columbia believes that the strategic value to the System
of drilling for oil and gas in the Southwest has diminished. Columbia
Development accounts for approximately 196 Bcf equivalent of proved oil and
natural gas reserves.
Columbia plans to retain its larger and more strategically placed Appalachian
oil and gas subsidiary, CNR, which is closer to Columbia's customer base and
pipeline service territory. As of December 31, 1995, CNR held interest in more
than 2.2 million net acres of gas and oil leases and had proved gas and oil
reserves in excess of 609 Bcf equivalent.
3
4
ITEM 1. BUSINESS (Continued)
Other Energy Operations
Columbia Energy Services Corporation (CES), Columbia's nonregulated natural gas
marketing company, provides an array of 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. CES
opened the Columbia Energy Market Center in 1994 to provide one-stop shopping
for natural gas supply and transportation services to help customers better
manage their energy costs and in 1995 added electronic trading to its list of
services, making real-time trading of natural gas supplies and pipeline
capacity easier and more efficient.
TriStar Ventures is involved in four cogeneration projects that produce both
electricity and useful thermal energy. These projects are fueled principally by
natural gas. TriStar Ventures holds various interests in these facilities that
have a total capacity of nearly 300 megawatts.
Columbia Propane Corporation and Commonwealth Propane, Inc., sell propane at
wholesale and retail to approximately 74,300 customers in eight states.
Columbia Coal Gasification has in excess of 500 million tons of coal reserves
in the Appalachian area, much of which contains less than 1% sulfur.
Approximately 50% of these reserves are leased to other companies for
development.
Columbia LNG Corporation is a partner with Potomac Electric Power Company in
the Cove Point LNG Limited Partnership which recently began commercial
operation of one of the largest natural gas peaking and storage facilities in
the United States located at Cove Point, Maryland. The facility enables
liquefied natural gas to be stored until needed for the winter peak-day
requirements of utilities and other large gas users. The facility has the
capacity to liquefy natural gas at a rate of 15,000 mcf of natural gas per day.
Columbia Gas System Service Corporation provides centralized, cost-efficient
data processing, financial, accounting, legal and other services to the System.
For additional discussion of the System's business segments, including
financial information for the last three fiscal years, see Item 7, pages 17
through 42 and Note 16 on pages 68 through 70 of Item 8.
Recent Management Changes
Oliver G. Richard III joined Columbia April 28, 1995 as Chairman, Chief
Executive Officer and President. Prior to joining Columbia, Mr. Richard served
as Chairman, Chief Executive Officer and President of New Jersey Resources
Corporation (NJR). He joined NJR in 1991 after three years as President and
Chief Executive Officer of Northern Natural Gas Company, the major pipeline
subsidiary of Enron Corporation. Prior to that, Mr. Richard also served as
Senior Vice President and, subsequently, Executive Vice President of Enron Gas
Pipeline Group and Vice President and General Counsel of Tenngasco, an
unregulated gas trading subsidiary of Tenneco, Inc. From 1982 to 1985 Mr.
Richard served as a Commissioner of the Federal Energy Regulatory Commission
(FERC) where he was instrumental in promulgating initiatives aimed at
increasing competition and efficiencies among federally regulated energy
providers. From 1978 to 1981 he served as a legislative assistant for energy
issues to the Honorable Bennett Johnston, U.S. Senator from Louisiana.
In September 1995, Peter M. Schwolsky was appointed Senior Vice President and
Chief Legal Officer of Columbia. He had previously been Executive Vice
President for Law and Corporate Development for NJR. Other recent appointments
include the election of Robert C. Skaggs, Jr., as President and Chief Executive
Officer of Columbia Gas of Ohio, Inc. and Columbia Gas of Kentucky, Inc., and
Catherine Good Abbott as Chief Executive Officer of Columbia Transmission and
Columbia Gulf. Mr. Skaggs was previously Executive Vice President and Chief
Financial Officer of Columbia's distribution subsidiaries. Ms. Abbott was a
Principal at Gem Energy Consulting, Inc., (Gem) and prior to that was a vice
president at various business units within Enron Corporation. Also from Gem,
Stephen J. Harvey was recently appointed as the Vice President of Strategic
Planning for Columbia Gas System Service Corporation, and Terrance L. McGill
was elected President of Columbia Gulf. Prior to Gem, Mr. Harvey was
President of NJR Energy and Mr. McGill held an executive position with various
Enron pipelines. W. Henry Harmon, the former Treasurer and Controller of
Columbia Natural Resources, one of the two exploration and production
subsidiaries, was selected as the new President of Columbia Natural Resources
and Columbia Coal Gasification. Dr. Michael J. Gluckman, formerly President of
Paradigm Power, a subsidiary of NJR, was selected as the new Chief Executive
Officer of TriStar Ventures.
4
5
ITEM 1. BUSINESS (Continued)
Competition and Business Strategies
The natural gas and energy markets are undergoing tremendous change. Over the
past ten years open access over interstate pipelines to natural gas supplies
has developed and the commodity price of gas has been deregulated. During this
period, distribution companies, larger industrial and commercial 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
allows customers to select the services they want independent from the purchase
of the commodity. Many believe that this "unbundling" of services and
deregulation of the commodity price will occur at the distribution company
level as well, and that the distribution companies will face competition in the
sale of gas, or largely confine their activities to the transportation of the
commodity and related services. 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 is under investigation by the
FERC and, if introduced, could result in increased competition in the market
for electricity. The energy market of the future may be characterized by open
competition not only in the market for supply of a particular commodity but
also open competition between interchangeable fuels. This change in the energy
markets will not happen overnight and perhaps not within the next five to ten
years, if at all.
In order to capitalize on the opportunities presented by this increasingly
competitive environment, Columbia's management is intent on developing a more
agile, customer-focused organization which will utilize Columbia's core asset
strengths, its expansive customer base and its knowledge and experience in the
energy markets to remake Columbia into a "total energy company" - a leading
provider of energy and energy services. To achieve this goal, Columbia has
developed the following strategic initiatives:
Capitalize on Core Asset Strengths. Management intends to capitalize
on its core asset strengths in order to compete more effectively in an
increasingly competitive energy marketplace. Columbia will focus on and expand
its core businesses, allocating approximately 90% of planned 1996 capital
investment to the transmission and distribution segments. Consistent with this
focus Columbia has announced a $400 million expansion of Columbia
Transmission's storage and transportation systems which is expected to be
substantially completed in the period from 1997 to 1999. The recent
announcement of Columbia's intention to sell Columbia Development is consistent
with this new strategy, following the determination that the strategic value to
Columbia of drilling for gas in the Southwest had diminished. In contrast, the
reserves held by Columbia's Appalachian oil and gas subsidiary, CNR, have
greater strategic value due to their location.
Exploit Synergies. Unlike the structure of many of its peers,
Columbia's distribution, storage and Appalachian oil and gas production
operations form a grid connected from within by Columbia Transmission. Columbia
intends to embark on a system-wide marketing strategy that will provide
customers with a variety of unbundled gas supply services - gathering,
processing, transportation, storage, distribution and other energy delivery
services. Columbia is also seeking to capitalize on the efficiencies of its
integrated system through initiatives with regulators designed to promote rate
structures that will reward Columbia's transmission and distribution
subsidiaries for enhanced productivity and efficiency.
Develop Non-Regulated Energy Business. Columbia's extensive presence
in the northeast, mid-atlantic and midwestern regions of the country provides
significant opportunities to offer customers a wide variety of non-regulated
energy-related products and services. Currently CES, Columbia's non-regulated
marketing subsidiary, actively markets natural gas and a broad range of natural
gas-related products and services. In order to expand the scope of energy
services and products offered by CES, or another subsidiary, Columbia has filed
an application under the 1935 Act seeking authority to offer a wide array of
products and services to energy consumers. These non-regulated energy-related
products and services would be offered to all energy consumers within its
wholesale and retail market area. In addition, Columbia has filed an
application with the U.S. Securities and Exchange Commission (SEC) under the
1935 Act for authority to market all forms of energy. Columbia's gas marketing
subsidiary already operates an electronic system for the trading of natural gas
supplies and transportation-related services, The Fast Lane(TM), that could be
expanded to allow instantaneous trading of any energy commodity. Columbia
expects that the SEC will approve the concept of electricity marketing by
natural gas registered holding company systems in the near future and that an
appropriate order will be issued for Columbia on a timely basis. Columbia
anticipates the expansion of energy-related and power marketing services over
time so that ultimately Columbia will be able to provide its customers with
one- stop shopping for all their energy needs.
5
6
ITEM 1. BUSINESS (Continued)
Streamline Organizational Structure. In February 1996, Columbia's
transmission and distribution subsidiaries commenced a top-down review of their
management structure and operations in an effort to streamline their
organizational structure and improve customer service. The studies will
examine all aspects of Columbia's operations including the configuration and
location of its management. No decisions have been made as yet and it is
premature to estimate the potential costs and/or savings, if any, which might
result from implementation of any recommendations resulting from the studies.
This review parallels a similar effort involving the Columbia Gas System
Service Corporation which was previously initiated. Columbia anticipates that
changes in organizational structure and operation will occur over a period of
time. For example, the recently announced management changes for the
distribution subsidiaries, which provide for the president and chief executive
officers to report directly to Mr. Richard, are the beginning of an effort to
flatten Columbia's organizational structure. Columbia also recently
implemented various operational and maintenance cost reductions in its
Appalachian exploration and production subsidiary and believes that similar
cost reductions are likely in other business segments.
Implement CVA. Underpinning Columbia's financial strategy is the
recent application of a value added approach (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. The CVA process was initiated to encourage
Columbia's employees to think in terms of value enhancement. All material,
discretionary capital expenditures will be subject to the CVA process.
Columbia believes the effects of CVA are beginning to materialize, reflecting
net planned investment reductions in a number of Columbia's business segments.
This new management tool aided Columbia in its decisions to allocate capital to
Columbia Transmission's planned expansion and to divest Columbia Development.
CVA is also being employed in Columbia's strategic planning process and in the
setting of management compensation levels.
Maintain Financial Flexibility. As a result of its bankruptcy
recapitalization, Columbia achieved one of the lowest average costs of debt in
the natural gas industry (7.03%) with an average maturity of 14 years and, as
of year- end 1995, had a 57% ratio of long-term debt to total capital.
Columbia's debentures are currently rated Baa3/BBB/BBB by Moody's/S&P/Fitch,
respectively. One of management's objectives is to improve the credit quality
and debt ratings of Columbia over time, to better position Columbia to take
advantage of business opportunities as they arise. However, there can be no
assurance that Columbia will be successful at improving or maintaining its
credit quality or debt ratios.
The foregoing discussion includes 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. Although Columbia believes that its
expectations are based on reasonable assumptions, it can give no assurance that
its goals or strategies will be achieved. Important factors that could cause
actual results to differ materially from those in the forward looking
statements or projections included herein include regulatory actions, the pace
of deregulation of domestic retail natural gas and electricity markets, the
timing and extent of change in commodity prices for all forms of energy and the
timing and extent of Columbia's efforts to implement changes planned by
management.
Other Relevant Business Information
The System's customer base is broadly diversified, with no single customer
accounting for a significant portion of revenues.
Certain subsidiaries file reports with various federal agencies containing
estimates of company-owned oil and gas reserves. These estimates are generally
consistent, but not always comparable, to those reported in the 1995 Annual
Report to Shareholders.
As of January 31, 1996, the System had 9,981 full-time employees of which 2,073
are subject to collective bargaining agreements.
Information relating to environmental matters is detailed in Item 7 pages 24
through 25, page 31 and page 37 and in Item 8, Note 13G on pages 66 through 68.
For a listing of the subsidiaries of Columbia and their lines of business refer
to Exhibit 21.
6
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ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed below
and on page 8 and pages 72 through 75 of Item 8 under Note 18. The System also
owns coal interests in the Appalachian area. Assets under lien and other
guarantees are described on page 65 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 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.
OIL AND GAS DATA
Acreage - At December 31, 1995
Developed Acreage Undeveloped Acreage
---------------------------- -------------------------------
Gross Net Gross Net
--------- ----------- ---------- -----------
Appalachian . . . . . . . . . . . 1,642,183 1,551,157 812,414 671,788
Southwest - Onshore . . . . . . . 70,567 34,459 155,560 80,917
Southwest - Offshore . . . . . . 162,951 53,858 80,555 54,415
Rocky Mountain . . . . . . . . . 22,111 10,885 181,621 106,634
Other Areas . . . . . . . . . . . 114 57 - -
----------- ---------- ----------- -----------
Total . . . . . . . . . . . 1,897,926 1,650,416 1,230,150 913,754
=========== ========== =========== ===========
Net Wells Completed - 12 Months Ended December 31
Exploratory Development Total
-------------------- -------------------- --------------------
Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- -----
1995 . . . . 4 4 64 21 68(a) 25
1994 . . . . 3 9 78 14 81(a) 23
1993 . . . . 2 10 91 18 93(a) 28
Productive and Drilling Wells - At December 31, 1995
Production Wells
------------------------------------
Gross(b) Net Wells Drilling
-------------- ------------------ ---------------
Gas Oil Gas Oil Gross Net
------ ----- ------ ------ ------ ---
6,419 693 5,765 375 34 22
(a) Includes 18 net horizontal wells in 1995, 17 net horizontal wells in 1994
and 17 net horizontal wells in 1993.
(b) Includes 791 multiple completion gas wells and 14 multiple completion oil
wells, all of which are included as single wells in the table. Also
includes 52 gross productive horizontal wells.
7
8
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1995
Miles of Pipeline Compressor Stations
Underground ------------------------- -------------------
Storage Gathering Installed
--------------- and Trans- Distri- Capacity
Subsidiaries State Acreage Wells Storage mission bution Number (hp)
- --------------------------------------- ----- ------- ----- ------- ------- ------- ------ ---------
Columbia Gas of Kentucky, Inc. . . . . . KY - - - - 2,272 - -
Columbia Gas of Maryland, Inc. . . . . . MD - - - - 589 - -
Columbia Gas of Ohio, Inc. . . . . . . . OH - - - - 17,374 - -
Columbia Gas of Pennsylvania, Inc. . . . PA 3,364 8 4 - 6,758 1 825
Commonwealth Gas Services, Inc.. . . . . VA - - - - 3,610 - -
Columbia Gas Transmission Corporation. . DE - - - 3 - - -
KY - - 947 770 - 9 19,420
MD 945 - 23 182 - 1 12,000
NJ - - - 78 - - -
NY 26,083 143 67 496 - 4 6,280
NC - - - 1 - 1 1,356
OH 485,164 2,463 2,753 4,112 - 28 101,685
PA 63,848 270 627 2,064 - 29 67,884
VA - - 128 1,117 - 11 56,720
WV 289,621 816 3,030 2,571 - 51 304,837
Columbia Gulf Transmission Company . . . AR - - - 8 - - -
KY - - - 716 - 2 70,290
LA - - - 2,055 - 6 201,200
MS - - - 659 - 3 118,800
TN - - - 556 - 2 83,000
TX - - - 202 - - -
WY - - - 10 - - -
Columbia Natural Resources, Inc. . . . . KY - - 432 - - - -
MI - - 6 - - - -
NY - - 2 - - - -
OH - - 99 - - - -
PA - - 8 - - - -
VA - - 25 - - - -
WV - - 171 - - - -
------- ----- ------- ------ ------- ------- ---------
Total . . . . . . . . . . . . . . . . . 869,025 3,700 8,322 15,600 30,603 148 1,044,297
======= ===== ======= ====== ======= ======= =========
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 knows 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
ITEM 3. LEGAL PROCEEDINGS
I. Shareholder Class Actions and Derivative Suits
After the June 19, 1991 announcement of Columbia's proposed charge to
second quarter earnings and suspension of its dividend, seventeen complaints
including suits purporting to be class actions, or alleging claims common to
the purported class actions, were filed in the U.S. District Court for the
District of Delaware. These actions were consolidated under the style In re
Columbia Gas Securities Litigation, Consol. C.A. No. 91-357. The complaints
named as defendants Columbia, members of Columbia's Board of Directors as of
June 1991, certain officers, Columbia's independent public accountants and
Columbia's underwriters for its 1990 common stock offering (the Defendants). A
class was certified and a negotiated settlement was approved as fair and
reasonable by the District Court of Delaware, following notice to the class and
a hearing. The order approving the settlement became final and non-appealable
on December 6, 1995. While a small number of potential class members, holding
less than 15,000 shares timely completed the appropriate forms in order to
elect to "opt out" of the class, as of the date hereof no such opt-outs have
commenced an action. In addition, persons holding approximately 450 shares
elected to assert their opt-out claims directly against Columbia in the
bankruptcy proceedings, with the Bankruptcy Court retaining post-confirmation
jurisdiction to address such claims. Columbia is in the process of determining
the most efficient procedure to resolve such claims. As part of the settlement
and related agreements among the defendants in this action, Columbia agreed to
indemnify the officers and directors and the underwriter defendants with
respect to any claims that may be asserted against them by the opt-out holders.
Also in 1991, three derivative actions were filed in the Court of
Chancery in and for New Castle County (Delaware) alleging that Columbia's
directors breached their fiduciary duties at that time. Consistent with the
recommendation of the Special Litigation Committee of Columbia's Board of
Directors, the derivative action, In re Columbia Gas Derivative Litigation,
Consol. C.A. 12159 (Del. Chan. Ct.), was dismissed with prejudice pursuant to
Columbia's Plan of Reorganization.
II. Purchase and Production Matters
A. Matters that have been resolved.
1. CNG Producing Co. v. Columbia Gas Transmission Corporation, C.A.
No. 95-491 (U.S. Dist. Ct. of Del. 1995). On August 11, 1995 CNG Producing Co.
filed an appeal of the Bankruptcy Court's order approving the Producer
Settlement. CNG settled its claims with Columbia Transmission and withdrew its
appeal by stipulation of dismissal entered on November 7, 1995.
2. The following matters were resolved upon confirmation of Columbia
Transmission's Plan of Reorganization or by a settlement with Producers which
was approved by the Bankruptcy Court on June 16, 1995 and became effective upon
confirmation of Columbia Transmission's Plan of Reorganization:
a. Phillips Production Co. v. Columbia Gas Transmission Corp.,
C.A. No. 89-0269, (U.S. Dist. Ct., W.D. Pa. filed February 7, 1989).
b. Wagner & Brown v. Columbia Gas Transmission Corp., C.A. No.
83-15091 (Orleans Parish (La.) C.V. Dist. Ct. filed September 6, 1983).
c. Koch Industries Inc. v. Columbia Gas Transmission Corp.,
C.A. No. 89-2156 (U.S. Dist. Ct., E.D. La., filed May 12, 1989); Columbia Gas
Transmission Corp. v. Koch Industries, Inc., C.A. No. 91-0174, (U.S. Dist. Ct.,
E.D. La. 1991); Koch Industries, Inc. v. Columbia Gas Transmission Corp., C.A.
No. 91-0177 (U.S. Dist. Ct. E.D. La. 1991).
d. Energy Development Corp. v. Columbia Gas Transmission Corp.,
C.A. No. CV91-0960 (U.S. Dist. Ct., W. D., La., division Lafayette/Opelousas,
filed May 13, 1991).
e. Columbia Gas Transmission Corp. v. Alamco, Inc., C.A. No.
88-C-38-2 (Harrison (W.Va) Cir. Ct. filed January 15, 1988).
9
10
ITEM 3. LEGAL PROCEEDINGS (Continued)
f. Vescorp Industrial 81V and Clinton Development 81-A and
Clinton Oil Co. v. Columbia Gas Transmission Corp., C.A. No. CV 0791 (N.D.
Ohio).
g. Certain Royalty Owners Litigation:
Moore-Sams Field:
A. Tidewater Land Co. Ltd. v. Amoco Production Co., No.
88-594, (U.S. Dist. Ct., N.D. La. 1988).
B. Fulmer v. Amoco Production Co., No. 88-23304, (U.S. Dist.
Ct., E.D. La. 1988).
C. Hurst v. Amoco Production Co., No. 88-23305, (U.S. Dist.
Ct., E.D. La. 1988).
These suits involved prepetition claims by royalty owners of
gas production from the Moore-Sams Field in Louisiana seeking
damages for alleged underpayment of royalties by producers
with whom Columbia Transmission may have had an
indemnification obligation regarding underpayment of
royalties. These claims have been resolved in Columbia
Transmission's Plan of Reorganization.
B. Pending Producer Matters
1. Estimation Proceedings. Claims by certain producers for
damages resulting from the rejection of gas purchase contracts remain unresolved
as discussed in the Management's Discussion and Analysis of Financial Condition
and Results of Operations.
2. Daniel Garshman v. Columbia Gas Transmission Corporation,
No. ATL-L-000172-88, (Sup. Ct. of N.J. 1993). On February 17, 1993,
plaintiffs, who are investors in an Appalachian producer and claim to be third
party beneficiaries of the contracts between Columbia Transmission and the
producer, filed a motion seeking to have their status as third party
beneficiaries recognized and seeking to have their claims against Columbia
Transmission liquidated separately from the estimation procedure established by
the Bankruptcy Court to deal with producer claims. By order dated April 5,
1993, the Bankruptcy Court lifted the stay in order to allow the New Jersey
State Court to determine whether plaintiffs enjoyed third party beneficiary
status in the pending State Court action. On November 9, 1994, the New Jersey
State Court denied cross-motions for summary judgment on the question of third
party liability. However, the Bankruptcy Court held that movants' claims, to
the extent liability of Columbia Transmission to such investors might be
established, would be quantified pursuant to the estimation procedure. A
plenary non-jury trial was held in early 1995 and at the conclusion of
plaintiffs' case, the Court granted Columbia Transmission's motion for directed
verdict and dismissed the complaint with prejudice. The Court found that
plaintiffs were not third party beneficiaries under the contracts between
Columbia Transmission and the Appalachian producers with which the plaintiffs
had invested. On March 23, 1995, Plaintiffs filed a notice of appeal in the
New Jersey Superior Court, Appellate Division (No. A-3714-94T3). On April 6,
1995, Columbia Transmission filed a notice of cross appeal based on the State
Court's failure to grant its motion for summary judgment. Briefing has been
complete since October 25, 1995.
3. New Ulm and Fox v. Mobil Oil Corporation, Columbia Gas
Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655 (155th
Judicial Dist. Ct. of Austin County, TX). New Ulm alleged Columbia Transmission
incorrectly paid for gas on the basis of Columbia Transmission's market-out
price rather than the higher price New Ulm claimed was available to it under
the contracts.
After the Bankruptcy Court entered an order modifying the
automatic stay provisions of the Bankruptcy Code, jury trial began on June 22,
1992, and concluded with a verdict against Columbia Transmission on July 2,
1992, in the amount of approximately $5.6 million, including interest. On July
30, 1992, the Court denied Columbia Transmission's motion for summary judgment
notwithstanding the jury's verdict and entered judgment against Columbia
Transmission in such amount for actual damages, prejudgment interest and
attorneys' fees. On July 28, 1994, the Court of Appeals for the First District
of Texas found that evidence proferred by Columbia Transmission was improperly
excluded from trial. Consequently, the Court reversed the trial court's
judgment and remanded the matter to the trial
10
11
ITEM 3. LEGAL PROCEEDINGS (Continued)
court for proceedings not inconsistent with the Court of Appeals opinion.
Motion for rehearing by Columbia Transmission and New Ulm were denied in
October, 1994. On December 5, 1994, both parties filed applications for writ
of error with the Supreme Court of Texas. On January 11, 1996, the Supreme
Court of Texas granted Columbia Transmission's application for writ of error on
three of its four points of error and granted New Ulm's application for writ of
error with a "because" notation indicating it was granted because of the
court's action on Columbia Transmission's application.
4. New Bremen Corp. v. Columbia Gas Transmission Corp. and Columbia
Gulf Transmission Co., No. 88V-631 (Dist. Ct. Austin County, TX). On November
16, 1988, New Bremen filed a complaint alleging it is entitled to a higher
price under the contract than the market-out price Columbia Transmission paid
for past periods. On January 10, 1989 Columbia Transmission removed the case
to United States District Court for the Southern District of Texas (No.
H-89-0072).
While the parties' motions for partial summary judgments were
pending with the court, Columbia Transmission filed a petition in Bankruptcy
Court automatically staying any action thereon. By order entered December 7,
1992, the Bankruptcy Court modified the automatic stay to allow the Texas Court
to decide the pending motions for summary judgment. 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 the Texas Court's August
11, 1995 order granting Columbia Transmission's motion for partial summary
judgment because of bankruptcy stay, 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 granting partial
summary judgment in favor of Columbia Transmission was a violation of the
automatic stay provision of the U.S. Bankruptcy Code.
III. Regulatory Matters
A. The following matters were resolved by the Customer Settlement
which was approved by FERC on June 15, 1995 and became effective and was
implemented on November 28, 1995 as a result of final Bankruptcy Court approval
of Columbia Transmission's plan of reorganization.
1. Columbia Gas Transmission Corp., FERC Docket Nos. RP91-41.
2. Columbia Gas Transmission Corp., FERC Docket No. GP94-2.
3. Tennessee Gas Pipeline Co., Docket Nos. RP94-113.
4. Columbia Gas Transmission Corp., Docket Nos. RP94-157 and
RP95-196. (Except as to the issue discussed in item (D)(1)
below.)
5. Columbia Gas Transmission Corp., FERC Docket Nos. TA91-1-21,
and RP94-158.
6. Columbia Gulf Transmission Co., Docket Nos. RS92-5.
B. Tennessee Gas Pipeline Take-or-Pay Transition Cost Recovery
Filing, Docket No. RP96-61. On November 30, 1995, Tennessee Gas Pipeline
Company (Tennessee) made a filing to direct bill Columbia Transmission for
$115,303 of costs it incurred as defined under FERC Order No. 528. Columbia
Transmission is protesting the direct bill on the bases that a FERC-approved
settlement Tennessee reached with its current and former customers allows for
collection of such costs based on current (at the time of filing) firm
entitlements only and that the FERC-approved settlement between Columbia
Transmission and Tennessee provided for the payment of an exit fee in
consideration for Tennessee's termination of its transportation contracts with
Columbia Transmission. As a result of these settlements, Columbia Transmission
had no current firm entitlements on Tennessee at the time of the filing and
therefore believes that it no longer has an obligation with respect to such
costs.
11
12
ITEM 3. LEGAL PROCEEDINGS (Continued)
On December 29, 1995, FERC issued an order accepting the filing,
subject to refund, but ordered Columbia Transmission and parties which support
Columbia Transmission to submit briefs by January 29, 1996 on the issues raised
by Columbia Transmission.
Considering Tennessee's method of calculating the direct bill,
Columbia Transmission's total exposure could be as high as $5 million.
Columbia Transmission's management believes that the likelihood of Columbia
Transmission incurring a liability is remote.
C. Direct Billing of Past Period Production and
Production-Related Costs
1. Columbia Gas Transmission Corp. v. FERC, C.A. No. 94-1727
(U.S. Ct. of App., D.C. Circuit). On February 9, 1990, the Court issued its
opinion finding that the FERC's orders authorizing five of Columbia
Transmission's upstream pipeline suppliers to directly bill past period
production related costs (Order Nos. 94 and 473) to customers allocated based
upon past period purchases violates the filed rate doctrine and the rule
against retroactive ratemaking. Therefore, the Court struck the orders
authorizing direct billing and remanded the issue to the FERC for further
proceedings. On October 9, 1990, the U.S. Supreme Court denied certiorari.
Columbia Transmission agreed to settlements with four of its
pipeline suppliers, which were initially approved by FERC orders issued
February 11, 1993. However, by orders issued January 12, 1994, the FERC
granted requests for rehearing by Columbia Transmission's customers and
rejected the settlements because they provided for rate recovery of the
settlement payments to its pipeline suppliers. The FERC held that such rate
recovery was barred by Columbia Transmission's 1985 PGA Settlement. The same
orders directed the pipeline suppliers to refund all principal Order Nos.
94/473 direct billed amounts collected from Columbia Transmission, but provided
that no interest would be required on such refunds. FERC issued a similar
ruling with regard to the fifth pipeline supplier on February 13, 1995.
Columbia Transmission and its pipeline suppliers filed petitions
for review of the FERC's orders with the United States Court of Appeals for the
District of Columbia Circuit. A briefing schedule has been established leading
to oral argument on March 19, 1996.
On November 21, 1995, Columbia Transmission and Texas Eastern
reached an agreement to resolve the issues in Docket No. RP85-170 and related
appeals. The agreement provided for Texas Eastern to refund to Columbia
Transmission a principal amount of $11,948,555.73, interest in the amount of
$1,440,000 for the period prior to October 1, 1994, and additional interest on
the principal amount for the period October 1, 1994, to the date of the refund.
A refund report was filed with FERC by Texas Eastern, which was approved on
February 2, 1996. An order dismissing the related appeals was issued on
December 7, 1995.
On December 21, 1995, Columbia Transmission entered into an
agreement with Texas Gas to resolve the issues in Docket No. RP85-181. Under
the settlement, Texas Gas refunded a principal amount of $9,582,552.50,
post-February 11, 1994 interest of $1,468,424.44 and additional pre-February
11, 1994 interest of $850,000. A refund report was filed with FERC by Texas
Gas asking for an order accepting the refund report and terminating
proceedings. An order dismissing the related appeals was issued on January 22,
1996.
D. Transportation Costs Recovery Adjustment (TCRA)
1. Columbia Gas Transmission Corp., Docket No. RP95-196 and UGI
Utilities, Inc. v. Columbia Gulf Transmission Co. and Columbia Gas Transmission
Corp., Docket No. RP95-392. On March 1, 1995, Columbia Transmission filed its
semi-annual TCRA filing in Docket No. RP95-196 to recover operational and
stranded Account No. 858 costs (including exit fees) paid to upstream
pipelines. Numerous protests to the filing were made, particularly with regard
to Columbia Transmission's recovery of certain costs paid to Columbia Gulf.
On March 30, 1995, FERC accepted the annual filing, subject to
refund and conditions. Columbia Transmission was required to further document
and support why it is appropriate to recover an additional $39 million of costs
paid to Columbia Gulf.
12
13
ITEM 3. LEGAL PROCEEDINGS (Continued)
The April 17, 1995 settlement approved by FERC on June 15, 1995,
in Docket No. GP94-2, resolved all issues in this docket except Columbia
Transmission's recovery of cost paid to Columbia Gulf under the T-1 Rate
schedule.
On August 2, 1995, the FERC issued an order in Docket Nos.
RP94-157 and RP95-196 (1) requiring Staff to convene a Technical Conference and
to file a report with the FERC within 120 days, at which Columbia Transmission
must support the payments to Columbia Gulf, and (2) creating Docket No.
RP95-392 for the complaint filed by UGI and making Columbia Gulf a party to the
proceeding. On September 27, 1995, the Technical Conference was held.
Columbia Transmission's and Columbia Gulf's initial comments on the technical
conference were filed on October 19, 1995. Initial comments were filed by
other parties on November 2, 1995, and reply comments by all parties were filed
on November 16, 1995. This matter is pending FERC action.
IV. Insurance Coverage Litigation
A. Columbia Gas Transmission Corp. v. Aetna Casualty & Surety
Co., C.A. No. 94-C-454 (Kanawha (W.Va.) Cir. Ct. filed March 14, 1994).
Columbia Transmission filed a complaint in West Virginia State Court seeking
coverage from various insurers and under various insurance policies for
environmental cleanup costs. All insurers have responded to the complaint.
The case is currently stayed until March 1, 1996 under an agreed scheduling
order entered by the 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 also
entered by the Court.
B. Columbia Gulf Transmission Co. v. Aetna Casualty & Surety
Co., C.A. No. 95-C-177 (Kanawha (W.Va.) Cir. Ct. filed January 19, 1995).
Columbia Gulf filed a complaint in West Virginia State Court seeking coverage
from various insurers and under various insurance policies for environmental
cleanup costs. The case is currently stayed until March 1, 1996 under an
agreed scheduling order entered by the 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 also entered by the Court.
V. Other
A. In re Marcor Environmental, Inc. v. Columbia Gas Transmission
Corp. On September 30, 1994, EPA Region III issued a complaint and notice of
opportunity for hearing against Marcor Environmental, Inc. (Marcor) and
Columbia Transmission for alleged violations of the Clean Air Act Amendments of
1990 arising from Marcor's removal of asbestos at Lanham Compressor Station at
Lanham, West Virginia in 1993. The complaint which seeks a penalty of $162,500
alleges failure by Marcor and Columbia Transmission, as owner of the facility,
to adequately wet the asbestos material and to ensure it remained wet pending
disposal. On November 4, 1994, Columbia Transmission filed an answer and a
motion to dismiss. A settlement conference among EPA Region III, Marcor and
Columbia Transmission was held on January 12, 1995. Marcor has subsequently
agreed to indemnify Columbia Transmission for all liabilities arising from the
complaint.
B. On January 9, 1996, Columbia Transmission and Columbia Gulf
each entered into a one year tolling agreement with Monsanto Company. The
possible claims by the Columbia Companies against Monsanto Company covered by
the tolling agreement relate to polychlorinated biphenyls (PCBs) manufactured
by Monsanto that have contaminated Columbia Transmission's and Columbia Gulf's
pipeline system, including pipelines, associated buildings and equipment,
on-site and off-site soils, groundwater, surface water, or other media. The
tolling agreement permits Columbia Transmission and Columbia Gulf more time to
assess the applicable issues with Monsanto while still preserving the right as
plaintiffs to file suit in the jurisdiction of its choice.
C. 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 plaintiff asserts, 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 plaintiff seeks, among other
remedies, the return of the defendants'
13
14
ITEM 3. LEGAL PROCEEDINGS (Continued)
interests in the Kotaneelee field to the plaintiff, a declaration that such
interests are held in trust for the plaintiff, 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 plaintiff's 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. effective December 31,
1991, and the company name was subsequently changed to Anderson Oil & Gas, Inc.
During the week of October 2, 1995, the Court of Queen's Bench
denied Columbia's motion for summary judgment which was premised on the absence
of an obligation on the part of Columbia Gas of Canada to market gas.
A trial is scheduled to commence in September 1996 by the Court
of Queens Bench.
Note: Pursuant to an Indemnification Agreement re Kotaneelee
Litigation, Columbia agreed to indemnify and hold Anderson harmless from losses
due to this litigation due to actions occurring prior to December 31, 1991. An
escrow account now funded by a letter of credit in the amount of approximately
$67,000,000 (Cdn) provides security for the indemnification obligation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information required by this item is contained in Columbia's quarterly report
on Form 10-Q for the quarter ended September 30, 1995, filed on November 9,
1995.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of Columbia is traded on the New York Stock Exchange under the
ticker symbol CG and abbreviated as either ColumGas or ColGs in trading
reports. The number of shareholders of record on January 31,1996, was
approximately 55,000 and the stock closed at $43.375. On June 19, 1991,
Columbia suspended the dividend on its common stock. On February 21, 1996,
Columbia declared a quarterly dividend of $0.15 per share for the first quarter
of 1996, payable on or about March 15, 1996, to holders of record on March 1,
1996.
See Item 7 on page 21 for additional information regarding Columbia's common
stock prices and dividends.
14
15
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
($ in millions except per share amounts) 1995* 1994* 1993* 1992* 1991* 1990
- --------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total operating revenues 2,635.2 2,747.1 3,313.8 2,859.2 2,463.7 2,346.7
Products purchased 820.6 984.2 1,577.7 1,236.9 1,056.5 846.8
Earnings (Loss) on common stock before
extraordinary item and accounting changes (432.3) 246.2 152.2 90.9 (794.8) 104.7
Earnings (Loss) on common stock (360.7) 240.6 152.2 51.2 (694.4) 104.7
- --------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Earnings (Loss) per common share ($):
Before extraordinary item and
accounting changes (8.57) 4.87 3.01 1.79 (15.72) 2.21
Earnings (Loss) on common stock (7.15) 4.76 3.01 1.01 (13.74) 2.21
Dividends:
Per share ($) - - - - 1.16 2.20
Payout ratio (%) N/A N/A N/A N/A N/A 99.5
Average common shares outstanding (000) 50,468 50,560 50,559 50,559 50,537 47,316
- --------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 1,114.0 1,468.0 1,227.3 1,075.1 1,006.9 1,757.8
Preferred stock 399.9 - - - - -
Long-term debt 2,004.5 4.3 4.8 5.4 6.1 1,428.7
Short-term debt N/A - - - 136.0 735.5
Current maturities of long-term debt .5 1.2 1.3 1.4 2.9 35.2
Debt subject to Chapter 11 - 2,317.1 2,317.1 2,317.1 2,317.1 -
Total 3,518.9 3,790.6 3,550.5 3,399.0 3,469.0 3,957.2
Total assets 6,057.0 7,164.9 6,957.9 6,505.9 6,332.2 6,196.3
- --------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including short-term
debt and current maturities**):
Common stock equity 31.7 38.7 34.6 31.6 29.0 44.4
Preferred stock 11.4 - - - - -
Debt 56.9 61.3 65.4 68.4 71.0 55.6
Capital expenditures ($) 421.8 447.2 361.3 299.7 381.9 629.6
Net cash from operations ($) (807.4) 572.8 850.4 765.4 531.6 420.1
Book value per common share ($) 22.07 29.03 24.27 21.26 19.92 34.83
Return on average common equity before extra-
ordinary item and accounting changes (%) (33.5) 18.3 13.2 8.7 N/A 6.2
- --------------------------------------------------------------------------------------------------------------------------
N/A - Not applicable
*Reference is made to Note 2 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 $982.9 million including write-off
of unamortized discounts on debentures, was recorded in 1995.
**Prior to its Chapter 11 filing, Columbia made extensive use of variable rate
debt since the associated cost was normally less than senior long-term debt.
Inclusion of the short-term debt in years prior to 1991 makes those historical
ratios more meaningful.
15
16
ITEM 6. SELECTED FINANCIAL DATA (Continued)
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
($ in millions except per share amounts) 1989 1988 1987 1986 1985
- -------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total operating revenues 3,189.3 3,157.5 2,855.7 3,407.7 4,097.6
Products purchased 1,669.0 1,822.3 1,534.2 2,002.9 2,733.5
Earnings (Loss) on common stock before
extraordinary item and accounting changes 145.8 119.0 111.3 99.4 (93.8)
Earnings (Loss) on common stock 145.8 111.1 100.5 75.3 (107.0)
- -------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Earnings (Loss) per common share ($):
Before extraordinary item and
accounting changes 3.21 2.46 2.30 2.12 (2.67)
Earnings (Loss) on common stock 3.21 2.46 2.30 1.82 (2.67)
Dividends:
Per share ($) 2.00 2.29 3.18 3.18 3.18
Payout ratio (%) 62.3 93.3 138.3 174.7 N/A
Average common shares outstanding (000) 45,494 45,190 43,763 41,436 40,134
- ------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 1,620.3 1,552.6 1,523.7 1,448.7 1,422.7
Preferred stock - - 110.0 115.0 120.0
Long-term debt 1.196.0 1,038.4 1,438.0 1,378.5 1,659.6
Short-term debt 634.2 697.1 327.5 393.4 418.0
Current maturities of long-term debt 47.2 52.7 69.6 432.5 336.1
Debt subject to Chapter 11 - - - - -
Total 3,497.7 3,340.8 3,468.8 3,768.1 3,956.4
Total assets 5,878.4 5,641.0 5,440.9 5,590.2 5,835.2
- ------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including short-term
debt and current maturities**):
Common stock equity 46.3 46.5 43.9 38.4 36.0
Preferred stock - - 3.2 3.1 3.0
Debt 53.7 53.5 52.9 58.5 61.0
Capital expenditures ($) 473.5 307.9 298.8 232.3 220.0
Net cash from operations ($) 400.5 429.4 702.0 550.5 81.7
Book value per common share ($) 35.50 34.18 34.08 34.06 35.10
Return on average common equity before extra-
ordinary item and accounting changes (%) 9.2 7.7 7.5 6.9 (6.1)
- -------------------------------------------------------------------------------------------------------------------------------
N/A - Not meaningful
*Reference is made to Note 2 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 1995.
**Prior to its Chapter 11 filing, 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.
16
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Index Page
- -------------------------------------------------------------------------------------------------------------------------------
Consolidated Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Transmission Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Distribution Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Oil and Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Other Energy Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Bankruptcy Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
- -------------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED REVIEW
Net Income (Loss)
After adjusting for items related to emergence from bankruptcy in November 1995
and other bankruptcy-related and unusual items, as listed below, Columbia had
net income for 1995 of $153.3 million, a decrease of $11.6 million from the
prior year. This decrease was largely due to higher operating costs for
Columbia Gas Transmission Corporation (Columbia Transmission) that are not
being recovered in current rates, higher interest expense, lower prices
received for natural gas produced and reduced oil and gas production volumes.
These factors more than offset the beneficial effect of higher rates and
increased transportation deliveries for the distribution subsidiaries. For
1995 on an unadjusted basis, Columbia reported a net loss of $360.7 million, or
$7.15 per share, versus net income of $240.6 million, or $4.76 per share in the
prior year. The decrease was primarily caused by the $676 million after-tax
effect of bankruptcy- related charges.
Bankruptcy-related and Unusual Items
After-tax effect on Net Income
------------------------------
(in millions)
Twelve Months
Ended December 31
-------------------
1995 1994
-------- --------
Reported Net Income (Loss) $(360.7) $240.6
Less:
Bankruptcy related items
- Interest and customer settlements (649.4) (22.8)
- Estimated interest costs not recorded on prepetition debt
prior to emergence 158.0 149.2
- Professional fees and related expenses (26.8) (30.1)
- Producer claim adjustment - (35.4)
Reapplication of SFAS No. 71 for transmission subsidiaries 71.6 -
Estimated loss on the proposed sale of Southwest oil and gas subsidiary (54.8) -
Transmission regulatory items - 28.0
IRS settlement - 10.3
Miscellaneous unusual items (12.6) (23.5)
-------- ------
Total adjustments (514.0) 75.7
--------- ------
Net Income after adjusting for bankruptcy and unusual items $ 153.3 $164.9
========== =======
Revenues
For 1995, operating revenues of $2,635.2 million were down $111.9 million from
the prior year due to lower natural gas prices that reduced that portion of the
sales rate that recovers the cost of gas for the distribution segment and
decreased the price received for gas produced by the oil and gas segment.
Mitigating these decreases were higher operating revenues related to additional
retail sales volumes and higher rates in effect for the non-gas portion of the
sales
17
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
rate for the distribution segment resulting from recent regulatory settlements
which provided $56.3 million higher revenues in 1995. Also improving the
current period was $12.2 million of exit fee payments received by Columbia Gulf
Transmission Company (Columbia Gulf) and $10.3 million of surcharges that were
offset in expense and had no effect on operating income. Revenues in 1994 were
reduced $35 million for a customer settlement reserve addition partially offset
by $22.1 million of revenues Columbia Transmission recorded because its average
cost of gas from an earlier period met certain competitive tests as well as
higher revenues in 1994 for the recovery of certain transportation costs.
Operating revenues for 1994 decreased $566.7 million, to $2,747.1 million from
1993 primarily due to the elimination of Columbia Transmission's merchant
function in November 1993 under Federal Energy Regulatory Commission (FERC)
Order No. 636 (Order 636). The reduced revenues also reflected pipeline exit
fees of $130 million recorded in 1993 that were offset in products purchased
expense and had no effect on income. Also contributing to lower revenues in
1994 was the customer settlement reserve addition mentioned above, warmer
weather for the distribution segment and the effect of lower prices and reduced
gas production. Improving revenues was the $22.1 million increase for
Columbia Transmission's recovery of prior period gas costs, discussed
previously.
Expenses
Operating expenses of $2,245 million for 1995 decreased $118 million from the
prior year. Product purchases were down $163.6 million due to lower gas prices
that reduced the cost of gas purchased for resale offset by additional
purchases necessary to meet increased sales requirements. Operation and
maintenance expense increased $35.2 million in 1995. Partially offsetting
this increase was the effect of a $19.1 million environmental reserve addition
in 1994. Increasing current period expenses was $8.3 million higher
depreciation and depletion expense primarily reflecting additional plant in
service. Depletion expense for 1995 was essentially unchanged from 1994 as the
impact on depletion expense from lower depletable revenues, caused by lower
natural gas prices and reduced production, was offset by a higher depletion
rate. Also included in operating expense was $10.3 million of expense that was
offset by revenue surcharges and had no effect on operating income, as
mentioned above.
In 1994, operating expenses of $2,363 million were $577.8 million lower than
1993 primarily reflecting a $593.5 million reduction for products purchased due
to the elimination of Columbia Transmission's merchant function and the 1993
expense associated with pipeline exit fees, mentioned above. The total expense
for 1994 was also lower by comparison due to the effect of certain 1993 items;
namely a $57.5 million writedown for Columbia's investment in Columbia LNG
Corporation (Columbia LNG) and environmental accruals of $66.8 million. The
effect of these items was more than offset by a $140 million increase in
operating and maintenance expense, depreciation expense and other taxes in
1994.
Other Income (Deductions)
Twelve Months Ended December 31,
---------------------------------------
(in millions) 1995 1994 1993
---------- ----------- -----------
Interest income and other, net $ (58.2) $ 35.2 $ 7.7
Interest expense and related charges (988.4) (14.8) (101.5)
Reorganization items, net 13.4 (12.3) 8.9
---------- ---------- ---------
Total Other Income (Deductions) $(1,033.2) $ 8.1 $ (84.9)
========== =========== ==========
Other Income (Deductions) reduced income $1,033.2 million in 1995, whereas in
1994 income was improved $8.1 million. Interest expense and related charges
for 1995 was $973.6 million higher than the prior year due primarily to
recording at emergence approximately $982 million of bankruptcy-related
interest costs on prepetition debt obligations. In 1994, a reserve reduction
in interest charges of $15.8 million was recorded for an IRS settlement,
largely offset by $14.7 million of interest expense based on an initial
interpretation of the claims mediator's report on producer claims against
Columbia Transmission (see Note 2 of Notes to Consolidated Financial Statements
for additional information). The remaining decrease in interest expense
primarily reflects other emergence adjustments partially offset by higher
interest costs on contingent taxes and rate refunds. Included in the $93.4
million decrease for Interest income and other, net was $77.8 million in 1995
for the estimated loss on the proposed sale of Columbia's Southwest oil and gas
subsidiary, Columbia Gas Development Corporation (Columbia Development), and an
income improvement in 1994 for a $21 million reserve reversal for carrying
charges on exchange gas. Reorganization items, net increased $25.7 million
over 1994 due to $40 million recorded in 1994 for the principal portion of the
producer claim reserve, mentioned previously, and $30.1 million higher interest
earned in 1995 on cash accumulated during the Chapter 11 proceedings.
18
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Tempering these improvements were $44 million for bankruptcy-related emergence
adjustments and additional expense for professional fees and related charges.
Other Income (Deductions) increased income in 1994 by $8.1 million compared to
a decrease to income of $84.9 million in 1993. The $86.7 million change in
Interest expense and related charges primarily reflected $74.5 million of
interest expense recorded in 1993 for the IRS settlement and the subsequent
$15.8 million reduction in this reserve in 1994. The $14.7 million of interest
expense associated with the producer claims also contributed to the change.
Interest income and other, net increased $27.5 million between 1994 and 1993
primarily for the $21 million reserve adjustment recorded in 1994 for carrying
charges, mentioned previously, as well as a $5.4 million reduction to income in
1993 for a pipeline partnership reserve. The 1994 reserve for producer claims
of $40 million and higher professional fees and related charges led to the
$21.2 million higher expense for Reorganization items, net that was only
partially offset by increased interest earned on accumulated cash.
Income Taxes
Income tax expense in 1995 decreased $356.7 million when compared to the prior
year and increased $10.1 million when comparing 1994 to the year earlier.
These changes were caused principally by changes in pre-tax book income.
Extraordinary Items
Columbia recorded an extraordinary after-tax gain of $71.6 million for the
cumulative adjustment for the reapplication of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71) for Columbia Transmission and Columbia Gulf. The
impact of the reapplication results in the recognition of regulatory assets for
certain costs previously expensed which are expected to be recovered in rates,
mainly environmental and postemployment benefit costs, and recording revenues
and expenses in a manner to reflect the ratemaking process. Management
believes that cost of service rate concepts will continue to be applicable to
Columbia's FERC-regulated transmission subsidiaries for the foreseeable future.
LIQUIDITY AND CAPITAL RESOURCES
Cash From Operations
Cash paid to producers and creditors on emergence from bankruptcy resulted in a
deficit of $807.4 million in net cash from operations for 1995. Included in
cash from operations, was approximately $1.45 billion of cash paid on emergence
to satisfy claims against Columbia and Columbia Transmission (see Note 2 in
Notes to Consolidated Financial Statements for additional information). After
adjusting for emergence payments, net cash from operations was $73.1 million
higher than 1994 primarily reflecting a 1994 payment for Order 500/528 (Order
500) refunds to nonaffiliated customers of $84.6 million, higher rates in
effect for the distribution segment and increased throughput. Overrecovery of
gas costs in 1994 for the distribution segment and lower prices received for
oil and gas production in 1995 partially offset this improvement as well as the
effect in both periods of supplier refunds and payments made by Columbia
Transmission.
In 1994 net cash from operations of $572.8 million decreased $277.6 million
from the year earlier. The decrease was largely due to the 1994 Order 500
refunds made by Columbia Transmission, mentioned above, exit fee payments made
in 1994, lower oil and gas prices and gas production, and warmer weather in
late 1994. Cash from operations was higher in 1993 due to refunds received
from certain pipelines and the sale of Columbia Transmission's gas in
underground storage, resulting from the elimination of the merchant function.
A significant portion of Columbia's operations are subject to seasonal
fluctuations in cash flow. During the heating season, which is essentially
from November through March, cash receipts from sales and transportation
services typically exceed cash requirements. Conversely during the remainder
of the year this excess cash, together with external financing as needed, is
typically used to purchase gas to place in storage for heating season
deliveries, make capital improvements in plant, perform necessary maintenance
of the facilities and expand service into new areas.
19
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Financing Activities
Prior to the emergence date, Columbia and its subsidiaries satisfied their
liquidity requirements through internally generated funds, since payments were
not made on Columbia's outstanding indebtedness. Columbia and Columbia
Transmission each maintained a debtor-in-possession facility of up to $25
million strictly for the issuance of letters of credit. Upon emergence from
bankruptcy, Columbia issued $2 billion of debentures and approximately $200
million each of 5.22% Convertible Preferred Stock, Series B (Series B - DECS)
and 7.89% Redeemable Preferred Stock, Series A (Series A - Preferred Stock) to
holders of Columbia's pre-bankruptcy debt securities. The $2.4 billion
distribution of securities, bank borrowings under a new $1 billion credit
facility (Credit Facility) as discussed below, and cash on hand were used to
settle claims in accordance with approved plans of reorganization. Maturities
of the new debentures range from 5 to 30 years with an average cost of
approximately 7.03%. In early February 1996, Columbia issued a notice of
redemption to redeem the Series B - DECS and Series A - Preferred Stock on
February 26, 1996, (See Note 9 in Notes to Consolidated Financial Statements
for additional information). Temporary funding for the redemption will be
provided by borrowings under the Credit Facility. It is anticipated that
permanent funding will be provided with funds generated from the planned sale
of Columbia Development and from the issuance of new common stock under the
shelf registration statement, as more fully described below. In addition,
Columbia will receive an income tax refund of about $270 million expected to be
received in the second quarter of 1996.
Columbia maintains a five-year unsecured bank revolving Credit Facility
totaling $1 billion. Scheduled quarterly reductions of $25 million of the
committed amount start December 31, 1997 and will reduce the Credit Facility to
$700 million by September 30, 2000. The Credit Facility provides for the
issuance of up to $100 million of letters of credit. As of December 31, 1995,
Columbia had $339 million of borrowings and $59 million of letters of credit
outstanding under the Credit Facility. It is expected that borrowings under
the Credit Facility will temporarily increase to approximately $600 million in
order to effect the above-mentioned redemption of the Series B - DECS and
Series A - Preferred Stock.
On November 22, 1995, Columbia filed a shelf registration with the U.S.
Securities and Exchange Commission requesting authorization to issue up to $1
billion in aggregate of debentures, common stock or preferred stock in one or
more series. In February 1996, Columbia announced its intention to use a
combination of treasury stock and the issuance of new common stock, totaling
approximately 5 million shares or $214 million, to reduce the borrowings
incurred under the Credit Facility for the redemption of Series B - DECS and
Series A - Preferred Stock. Columbia believes that future ongoing cash
requirements will be met with internally generated funds, amounts available
under the Credit Facility and additional potential drawdowns under the shelf
registration, although only the common stock sale discussed above is currently
planned.
Capital Expenditures
The table below reflects actual capital expenditures by segment for 1994 and
1995 and an estimate for 1996.
(in millions) 1996 1995 1994
- ----------------------------------------------------------------------------------
Transmission $133 $169 $179
Distribution 160 152 151
Oil and Gas 21 87 102
Other Energy 13 14 15
- ----------------------------------------------------------------------------------
Total $327 $422 $447
- ----------------------------------------------------------------------------------
For 1995 Columbia's capital expenditures were $422 million, a decrease of $25
million from 1994. The largest portion of the transmission subsidiaries'
investments was made to assure the safety and reliability of the pipelines.
Distribution subsidiaries' program included investments to extend service to
new areas and develop future markets, as well as expenditures required to
ensure safe and reliable service and improved service where warranted. The
capital expenditures for the oil and gas segment decreased $15 million from the
1994 level reflecting curtailments due in large part to depressed energy
prices.
20
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Capital expenditures for 1996 are expected to decrease $95 million to $327
million. This reflects $66 million of lower expenditures for the oil and gas
segment as a result of the proposed sale in 1996 of Columbia Development and
reduced exploration in the Appalachian area. Ongoing replacement and upgrading
of the distribution and pipeline facilities of approximately $175 million will
represent the largest portion of the 1996 program. Columbia Transmission also
anticipates expenditures of approximately $9 million in 1996 for its expansion
project, as discussed in the Transmission Segment.
COMMON STOCK PRICES AND DIVIDENDS
Market Price
--------------------------------------------
Quarterly
Quarter Ended High Low Close Dividends Paid
- -------------------------------------------------------------------------------------------------------------
$ $ $ c
1995
December 31 44 1/8 36 43 7/8 -
September 30 39 3/4 31 3/8 38 5/8 -
June 30 32 7/8 28 3/4 31 3/4 -
March 31 29 3/4 23 1/8 29 5/8 -
- ---------------------------------------------------------------------------------------------------------------
1994
December 31 29 22 1/4 23 1/2 -
September 30 28 7/8 26 26 7/8 -
June 30 30 3/4 24 7/8 27 -
March 31 29 7/8 21 1/2 26 1/8 -
- ---------------------------------------------------------------------------------------------------------------
21
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATIONS
Marketing Initiatives
Early in 1995, Columbia Transmission announced plans to expand its pipeline and
storage capacity to serve the increasing needs of customers in its eastern
market area. Columbia Transmission has signed 15-year agreements with 23
customers for approximately 500,000 Mcf per day (Mcf/d) of additional firm
service to be phased in over a three-year period commencing November 1, 1997.
Approximately 82% of the increased firm agreements are for storage service and
related transportation from storage to customers during the winter periods.
The company will make a filing with the FERC in February 1996 seeking
authorization for this project. This additional capacity, once fully phased
in, is projected to increase total firm service for the transmission segment by
approximately 7.5%. The cost to construct the facilities is estimated at
approximately $400 million. Other significant marketing developments during
1995 include:
- Columbia Gulf began transporting approximately 10,000 Mcf/d to a natural
gas distribution company near Nashville, Tennessee in November 1995.
- Columbia Transmission filed for FERC authorization to provide
approximately 23,000 Mcf/d of firm transportation service to a
cogeneration facility in Brandywine, Maryland. Approval is expected in
March 1996 and service is anticipated to commence in the fall of 1996.
- In November 1995, Columbia Transmission initiated 3,100 Mcf/d of firm
transportation service to a plant in Covington, Virginia, and
approximately 500 Mcf/d to a facility in Alderson, West Virginia.
- Columbia Transmission constructed additional facilities at its
Chesapeake, Virginia, LNG facility to provide an additional 33,650 Mcf/d
of peak deliveries commencing November 1, 1995.
Capital Expenditure Program
The transmission segment's 1995 capital expenditure program of approximately
$169 million and anticipated 1996 capital expenditures of $133 million, which
includes $9 million for the major expansion project mentioned above, reflect
the segment's continued commitment to maintaining its competitive position by
modernizing and upgrading facilities. The commitment will contribute to a
safe, reliable and efficient pipeline system, which conforms to all pipeline
safety regulations. Total expenditures in this area are expected to
approximate $125 million a year.
Regulatory Matters
Customer Settlement
Incorporated in the approved plan of reorganization (Plan) for Columbia
Transmission was a settlement by Columbia Transmission and Columbia Gulf with
firm customers, state regulatory agencies and consumer groups (Customer
Settlement) that resolved virtually all outstanding Order 636 transition costs
and rate and bankruptcy related matters that were pending before the FERC. The
FERC approved the settlement on June 15, 1995 and it was implemented upon
Columbia Transmission's emergence from bankruptcy. Generally, the settlement
defined Columbia Transmission's and Columbia Gulf's refund obligations to their
customers in certain pending regulatory proceedings and established Columbia
Transmission's ability to recover certain costs associated with the
restructuring of its services under Order 636. The Customer Settlement
provided for payment to Columbia Transmission's customers of an estimated $170
million in refunds and recovery of $250 million in costs from Columbia
Transmission's customers. The refunds paid under the Customer Settlement
resolved all issues relating to the flowthrough of customer refunds involved in
the bankruptcy reorganization, Columbia Transmission's collection of gas
purchase costs, its own FERC Order 500 costs and gas inventory charges,
Columbia Transmission's ability to flowthrough upstream Order 500 amounts,
including a settlement regarding the Baltimore Gas & Electric vs. FERC
litigation, implementation of a previous rate case settlement of Columbia
Transmission and Columbia Gulf, and Columbia Transmission's collection of
payments made to terminate contracts with certain upstream pipelines.
Upstream Pipeline Contracts
In early 1995, Columbia Transmission made its annual filing with the FERC to
recover costs it continues to incur under transportation contracts with
upstream pipelines. The filing provided for recovery of costs that Columbia
Transmission projected it would incur under contracts it continues to utilize
in system operations, costs associated with contracts for which exit fees had
not yet been implemented, and continued amortization of exit fees paid to an
upstream pipeline. In addition, the filing proposed to implement a surcharge
to recover an undercollection of transportation costs incurred during 1994.
This underrecovery related, in part, to $39 million paid by Columbia
Transmission to Columbia Gulf under the provisions of the cost-of-service
contract between the two companies for the period through October 31, 1994, the
date on which the agreement was terminated. Various parties protested Columbia
Transmission's filing and challenged,
22
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
among other things, Columbia Transmission's ability to recover the costs
attributable to Columbia Gulf. A technical conference among the parties was
held at the FERC in December 1995, and Columbia Transmission, Columbia Gulf and
intervenors filed comments and reply comments with the FERC in support of their
positions.
Columbia Transmission's General Rate Filing
On August 1, 1995, Columbia Transmission filed with the FERC its first general
rate case since 1991, requesting an increase in annual revenues of
approximately $147 million. In addition to seeking a reasonable return on
additional plant investment and recovering general increases in expenses, the
filing also requested:
- - recovery over a five-year period of Columbia Transmission's net
investment in gathering facilities and substantially all of its net
investment in gas processing facilities (approximately $60 million)
that were "stranded" as a result of the implementation of Order 636
(see discussion of Gathering Facilities on page 34 for more
information);
- - an increase in certain depreciation rates;
- - recovery of environmental expenses that are anticipated to be incurred
as a result of recent settlements with the U.S. Environmental
Protection Agency (EPA) and certain state environmental regulatory
agencies; and
- - certain tariff changes relating to operational and service issues.
Numerous customers and other interested parties protested the filing, and
certain parties proposed that Columbia Transmission should be required to adopt
zone rates or mileage-based rates. On August 30, 1995, the FERC accepted the
filing subject to refund, directed that certain operational and tariff changes
be considered at a technical conference, suspended implementation of the
increased rates until February 1, 1996, and directed that certain revisions be
made to Columbia Transmission's requested rates. In an effort to reach a
timely resolution of the issues, Columbia Transmission agreed that it would not
implement 25% of the rate increase for a three month period beginning February
1996, because settlement negotiations currently underway were continuing at a
satisfactory pace at year-end 1995. On January 11, 1996, a procedural schedule
was approved which established a hearing date of November 12, 1996.
Environmental issues were removed from the normal procedural schedule and will
be pursued separately from the other rate case issues.
Columbia Gulf's Rate Filing
In 1994, Columbia Gulf filed a general rate case with the FERC that was placed
into effect, subject to refund, on November 1, 1994. The rate case reflected
the termination of Columbia Gulf's long-standing transportation contract with
Columbia Transmission and sought the recovery of increased costs since its last
rate case. A unanimous settlement providing for $8.4 million of additional
annual revenues was reached and approved by the FERC on July 18, 1995.
Columbia Gulf Show Cause Proceeding
In its September 1993 order on Columbia Transmission's and Columbia Gulf's
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 the FERC's
abandonment authorization to reduce capacity on its mainline facilities. In a
response to the FERC in late 1993, Columbia Gulf asserted that no abandonment
filing was required. During 1994 and early 1995, Columbia Transmission and
Columbia Gulf responded to information requests from the FERC's staff.
Management continues to believe that an abandonment filing was not necessary;
however, the ultimate outcome of this issue is uncertain at this time.
Restructuring Proceedings
Numerous parties filed with the United States Court of Appeals for the District
of Columbia (Circuit Court) for review of Columbia Transmission's and Columbia
Gulf's restructuring proceedings under Order 636. Under the terms of the
Customer Settlement, the transmission subsidiaries will have no refund
obligations in the event the appeals of the FERC order approving the
restructuring are successful. As discussed above, the Customer Settlement
became effective as a result of the United States Bankruptcy Court for the
District of Delaware (Bankruptcy Court) approving Columbia Transmission's Plan.
On December 18, 1995, Columbia Transmission filed a motion with the Circuit
Court to dismiss certain of the petitions for review and to sever certain
issues as moot in accordance with the terms of the Customer Settlement.
Appeals of Order 636
Numerous parties have filed petitions for review of Order 636 with the Circuit
Court. Upon review, Order 636 may be modified or reversed in whole or in part;
however, at this time it is impossible to predict the outcome. On June 12,
1995, the FERC filed its brief in support of Order 636 with the Court. Oral
argument is currently scheduled for February 1996.
23
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Under the terms of the FERC-approved Customer Settlement, Columbia Transmission
and Columbia Gulf will have no refund obligation in the event the appeals are
successful. Further, the Customer Settlement states that the transmission
subsidiaries can adjust rates prospectively to take into account any change or
modifications as a result of a court remand of Order 636.
Environmental Matters
Columbia's transmission subsidiaries continue their reviews of compliance with
existing environmental standards, including reviews of past operational
activities, identification of potential problems through site reviews and the
formulation of remediation programs where necessary. The progress of Columbia
Transmission's efforts in the last year was limited by a 1995 EPA
Administrative Order by Consent (AOC) that requires Columbia Transmission to
obtain prior EPA approval of its investigation, characterization and
remediation efforts. Progress was further limited because of the more than
19,000 miles of pipeline that Columbia Transmission operates, the exceptionally
large number of sites at which it conducts or has conducted operations, and the
long time period over which operations have been conducted.
Management had previously estimated, based on studies conducted since 1990 by
independent consultants, that site investigation, characterization and
remediation costs might range between $135 million and $280 million. The
primary focus of these prior studies was to analyze discrete issues to assist
management in its on-going environmental evaluations. In 1994, in anticipation
of implementation of the AOC, Columbia Transmission commissioned a new study
(1995 Study) to reflect costs that might arise from the EPA's recommendations
with respect to site assessment and remediation under the AOC and to reflect
information gathered since the previous studies. The 1995 Study was structured
to be a comprehensive review of all environmental issues currently known to
management. The 1995 Study estimated that the cost of Columbia Transmission's
environmental program under the AOC may range between $204 million and $319
million over the life of the program. This estimate was based on a limited
amount of actual data available and utilized a variety of assumptions,
including: the number of sites to be investigated, characterized and
remediated; the location, nature and levels of wastes that will be treated at
or disposed of from each site; the amount of time and nature of equipment
required for such activities; the appropriate remediation levels and the
technology to be utilized; and the frequency with which groundwater
contamination might be discovered at sites requiring remediation. The 1995
Study did not include previously identified costs, aggregating approximately
$50 million, for which Columbia Transmission already had reasonable estimates.
Following an extensive review of bases utilized and assumptions contained in
the 1995 Study, management has concluded that 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). This
conclusion was based upon the fact that the actual characterization and
remediation experience of Columbia Transmission was extremely limited and
information on environmental conditions at many of the sites or former sites of
operations is not yet available. The nature and condition of such sites varies
greatly, and any change in any of the numerous assumptions used in the 1995
Study may materially alter the estimated range of costs, with no assurance that
actual costs will not exceed amounts specified in the range. Columbia
Transmission is unable, at this time, to accurately estimate the timeframe and
potential costs of all site screening, characterization and remediation. As
Columbia Transmission continues its program pursuant to the AOC, additional
costs will become probable and reasonably estimable and will be recorded.
Moreover, in time, management expects that, as additional work is performed and
more facts become available, it will then 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 and SFAS No. 5.
Based upon its current review, Columbia Transmission estimates the future costs
of investigating, characterizing, and remediating sites upon which it has
adequate information will be approximately $136.6 million. This resulted in
the recognition of an additional liability of approximately $21 million in the
fourth quarter of 1995. As contemplated by the AOC, Columbia Transmission's
environmental expenditures are expected to approximate $20 million in 1996 and
to continue at that level for the foreseeable future. These expenditures will
be charged against Columbia's previously recorded liability. Management does
not believe that Columbia Transmission's environmental expenditures will have a
material adverse effect on Columbia's operations, liquidity or financial
position, based on known facts and existing laws and regulations and the long
period over which expenditures will be made. In addition, as a result of
reapplying SFAS No. 71, Columbia Transmission has recorded a regulatory asset
to the extent environmental expenditures are expected
24
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
to be recovered through rates, and therefore, environmental expenditures will
have less potential impact upon Columbia's financial results.
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. Columbia Transmission is unable at this time to determine if it will
become liable for any characterization or remediation costs at such sites.
Clean Air Act Amendments of 1990
In 1995, Columbia Transmission completed the majority of the equipment
installations required by Title I of the Clean Air Act Amendments of 1990
(CAA-90). Until regulations are finalized, the capital expenditures necessary
to comply fully with CAA-90 cannot be estimated. Management anticipates that
capital expenditures made in compliance with CAA-90 will be recoverable through
the rate-making process.
Adoption of SFAS No. 71
As a result of emergence from bankruptcy and significant industry changes
culminating with Order 636, the operating experience gained since
implementation of Order 636, a new Columbia Transmission rate case that was
filed on August 1, 1995, and the resolution of gas contract difficulties and
various customer issues, Columbia Transmission and Columbia Gulf reapplied SFAS
No. 71 upon Columbia Transmission's emergence from bankruptcy. Management
believes that cost of service rate concepts will continue to be applicable to
Columbia's FERC-regulated transmission subsidiaries for the foreseeable future.
The reapplication of SFAS No. 71 results in the recognition of regulatory
assets for certain costs previously expensed, which are expected to be
recovered in rates, mainly environmental and postemployment benefit costs, and
recording revenues and expenses in a manner to reflect the ratemaking process.
As a result of reapplying SFAS No.71, an extraordinary gain of $71.6 million
was recorded in 1995.
Volumes
Throughput for Columbia Transmission consists of transportation for local
distribution companies and other customers in its market area and for storage
services. Columbia Gulf's mainline transportation service extends from
Louisiana to West Virginia. Short-haul transportation service is primarily
from the Gulf of Mexico to Rayne, Louisiana. Total 1995 throughput for the
transmission subsidiaries of 1,336.2 Bcf, increased 64.2 Bcf over the prior
year, due largely to increased demand stemming from the colder weather during
the last quarter of 1995 and increased summer-related requirements from
cogeneration facilities. Total throughput for 1994 was 1,272 Bcf, a decrease
of 83.9 Bcf from 1993. This decrease reflected a timing change for the
recognition of transportation for storage activity and reduced short-haul
transportation needed by customers for spot purchases.
In 1995, market area transportation increased 67.5 Bcf over 1994 largely due to
colder weather and increased deliveries to cogeneration facilities attributable
to unseasonably warm weather during the summer. Market area transportation
increased 142.7 Bcf in 1994 over 1993 due to customers switching from sales to
transportation services as a result of the implementation of Order 636,
partially offset by a timing change in the recognition of market area
transportation for storage activity.
Mainline transportation service of 605 Bcf, up 14.7 Bcf over 1994, reflected
the impact of colder weather in 1995 causing customers to increase their
utilization of Columbia Gulf 's transportation services. Columbia Gulf's
mainline transportation service increased in 1994 by 10.4 Bcf over 1993
primarily reflecting additional transportation service for customers to move
gas to Columbia Transmission's storage fields and to meet their supply
requirements.
Short-haul transportation of 221.4 Bcf in 1995 was essentially unchanged from
1994 as the impact of customers using facilities other than Columbia Gulf's to
transport their gas requirements was offset by colder weather together with
additional natural gas supplies available for transportation and increased
marketing efforts. In 1994, short-haul transportation decreased from 1993 by
32.7 Bcf due to reduced customer requirements.
Under Order 636, a significant portion of the transmission segment's fixed
costs are being recovered through a monthly demand charge. As a result,
variations in throughput have little effect on income.
25
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Operating Revenues
The transmission segment's 1995 operating revenues of $756.7 million were
relatively unchanged from 1994. After adjusting for unusual items, operating
revenues increased $3.1 million reflecting higher demand revenues attributable
to additional short-term transportation agreements and the impact of higher
throughput. The unusual items include Columbia Gulf in 1995 recording exit fee
revenues of $12.2 million, most of which were associated with its pipeline
partnerships. Revenues in 1994 were higher for the recovery of certain
transportation and other costs, and $22.1 million of additional revenues were
recorded by Columbia Transmission because its sales rate from an earlier period
met certain competitive tests. Reducing revenues in 1994 was a customer
settlement reserve addition of $35 million.
Operating revenues in 1994 of $758.7 million were $940 million lower than 1993
due largely to eliminating the merchant function. This decrease also included
the effect of a $35 million reserve established in 1994 for various customer
and regulatory settlements and a lower cost-of-service recovery level for
Columbia Transmission reflecting its restructuring under Order 636.
Operating Income
Operating income for 1995 of $214.1 million, increased $4.4 million, primarily
reflecting $6.4 million in lower operating expenses. Included in operating
expense in 1994 were environmental accruals of approximately $19.1 million for
Columbia Gulf and $8 million of severance and relocation expense. Partially
offsetting 1994's higher expenses is the impact of rising operating costs in
1995 that exceed recovery through current rates. In August 1995, Columbia
Transmission made its first rate filing since 1991 to recover, among other
things, these increasing costs.
Operating income for 1994 of $209.7 million increased $32.8 million over 1993.
The $940 million decrease in revenues was offset by a $972.8 million decrease
in operating expenses. A significant portion of this decrease was attributable
to reduced gas purchases due to the elimination of Columbia Transmission's
merchant function in 1994. Also contributing to this decrease was a $57.5
million writedown in the investment in the Cove Point LNG facility in 1993
along with a $66.8 million 1993 environmental reserve addition.
26
27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1995 1994 1993
================================================================================================================================
OPERATING REVENUES
Transportation revenues $612.7 $650.7 $549.7
Storage revenues 139.3 141.7 125.3
Other revenues 4.7 (33.7) 1,023.7
- --------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 756.7 758.7 1,698.7
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 388.0 391.1 1,310.3
Depreciation 103.8 103.9 97.8
Other taxes 50.8 54.0 56.2
Writedown of investment in Columbia LNG Corporation - - 57.5
- --------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 542.6 549.0 1,521.8
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME $214.1 $209.7 $ 176.9
TRANSMISSION OPERATING HIGHLIGHTS
1995 1994 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 169.1 179.1 137.2 114.2 152.9
- ----------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Transportation
Columbia Transmission
Market area 1,106.1 1,038.6 895.9 909.0 849.9
Columbia Gulf
Main-line 605.0 590.3 579.9 574.3 535.4
Short-haul 221.4 225.4 258.1 258.3 267.0
Intrasegment eliminations (596.3) (583.2) (561.7) (563.3) (535.4)
- -----------------------------------------------------------------------------------------------------------------
Total Transportation 1,336.2 1,271.1 1,172.2 1,178.3 1,116.9
Sales - 0.9 183.7 196.0 112.6
- -----------------------------------------------------------------------------------------------------------------
Total Throughput 1,336.2 1,272.0 1,355.9 1,374.3 1,229.5
- -----------------------------------------------------------------------------------------------------------------
27
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATIONS
Market Conditions
The continued strong economy in the distribution subsidiaries' (Distribution)
service area and the success of its industrial marketing efforts resulted in a
6 percent increase in industrial throughput during 1995. Increased production
at manufacturing facilities (specifically, steel, paper, oil and chemicals) and
increased demand from power generation facilities all contributed to the
increase. Similar to previous years, Distribution experienced nominal customer
growth and added approximately 34,900 net residential and commercial customers
in 1995, a 1.8 percent increase. Also in 1995, a large industrial customer
in Virginia signed an agreement with Commonwealth Gas Services, Inc.
(Commonwealth Services) to service a new 50 megawatt gas-fired cogeneration
plant. Estimated gas load from the facility is expected to exceed 3 Bcf per
year.
As a result of a continuing market assessment, Distribution concluded that the
future demand for natural gas vehicles (NGVs) will not be as great as
previously thought and therefore reduced its previously announced five-year
commitment to invest $38 million in its NGV program to $10 million.
Distribution has decided to eliminate future capital expenditures, except for
NGV fueling stations currently under construction, and is now focusing its NGV
efforts on opportunities within its own fleet and more fully developing NGV
fueling stations that are currently operational. Distribution participated in
the completion of 28 new NGV fueling stations during 1995.
Growing efforts by the electric industry to make additional inroads into
Distribution's traditional residential and commercial markets are being
countered through aggressive marketing and innovative financing programs that
show the many benefits of choosing natural gas for both new and replacement
appliances.
Beginning in 1995, Columbia Gas of Ohio, Inc. (Columbia of Ohio) initiated a
commercial water heater financing program designed to assist food service
operators in purchasing supplemental gas water heaters. The program supports
Distribution's entry into a market that has predominantly been served by
electricity. Financing is provided by third parties and the program is being
promoted through contractors. This complements the residential water heater
replacement program that was introduced in Ohio in 1994. Both programs are
being expanded to other Distribution affiliates in 1996.
Distribution continues to promote the use of environmentally friendly and
cost-efficient natural gas cooling equipment by commercial and industrial
customers. In 1995, new sales of gas cooling equipment in Distribution's
territory totaled 4,500 refrigerant tons which added 60,000 Mcf of annual gas
load. In addition, Distribution continues its support of the "Triathlon" heat
pump, for residential natural gas heating and cooling. Distribution is one of
the leading gas utilities in the nation in number of installations.
The Clean Air Act Amendments of 1990 (CAA-90), which require many electric
power generating facilities to reduce emissions by installing expensive exhaust
scrubbers or using cleaner burning fuels, also has created new marketing
opportunities for natural gas.
Competition
Industrial customers have been able to buy natural gas on the spot market and
transport it through transmission and distribution facilities for more than a
decade and third party sales to commercial users are becoming common as gas
brokering reaches smaller users. Market and regulatory forces are causing
Distribution to evaluate the extent to which it will unbundle the commodity gas
sales portion of its service from the transportation portion of such service to
all customers. This unbundling would increase competition among gas providers
and offer choices to customers. Distribution's primary role in this evolving
environment will be to transport gas and provide related services while the
regulatory approvals needed to compete with marketers in brokering gas for
profit are yet to be determined. The current bundled sales service margins are
similar to transportation service margins; therefore, discontinuing the current
sales service is not expected to significantly impact earnings.
Approximately 40 percent of Distribution's industrial and commercial
throughput, or 125 Bcf, is susceptible to bypass as these customers are
geographically located close to natural gas pipelines. With the use of
innovative rate and capacity release strategies and the negotiation of unique
customer arrangements, substantial inroads by other natural gas pipelines
28
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
have been avoided to date. As a result of these actions, the current estimated
throughput exposure has been reduced to approximately 40 Bcf, representing $10
to $15 million in annual net revenues.
Distribution competes with 17 investor-owned electric utilities throughout its
five state service area as well as numerous municipal and cooperative electric
utilities. Competition is generally strong in the residential and commercial
markets of Kentucky, southern Ohio and southwest Pennsylvania where electric
rates are driven by low-cost coal-fired generation. Areas such as northern
Ohio and Pittsburgh, Pennsylvania have less competitive electric rates due to
the use of higher-cost nuclear-generated power.
Federal and state regulators are currently moving the electric industry toward
a more competitive environment. Customers may ultimately be able to purchase
electricity from sources other than their local utility, which would be
required to transport the electricity purchased. In response to the forces of
competition, these electric utilities are positioning themselves to be lower
cost suppliers than they have been in the past. Although the timing and
overall financial impact of these initiatives are uncertain at this time, they
will undoubtedly increase price competition for the gas industry.
Regulatory Matters
Rate Case Activity
Rate changes during 1995 and early 1996 resulted in $22.8 million of annual
revenue increases to recover higher operating costs. In all jurisdictions,
Distribution also continued its pursuit of regulatory initiatives in order to
more effectively participate in today's competitive energy market. In each of
its service areas, Distribution has formed a regulatory collaborative process
(Collaborative) that provides for a more cooperative environment among the many
diverse and interested parties in its rate cases, thereby possibly avoiding
lengthy and costly litigation.
In late 1995, Columbia Gas of Pennsylvania, Inc. (Columbia of Pennsylvania)
reached a settlement on a general rate case filed in September 1995. The
settlement includes an annual revenue increase of $12.5 million as well as a
number of changes that allow Columbia of Pennsylvania to provide additional
services to its customers. Columbia of Pennsylvania received regulatory
approval of the settlement on January 12, 1996, with new rates effective the
same day, over five months sooner than originally anticipated.
Columbia Gas of Maryland, Inc. (Columbia of Maryland) filed a rate case in
March 1995. The Maryland Public Service Commission approved an annual revenue
increase of $900,000, effective October 23, 1995.
As provided in its 1994 general rate case settlement, Columbia Gas of Kentucky,
Inc. (Columbia of Kentucky) increased annual revenues $2.25 million, effective
October 1, 1995, through the implementation of the second phase of a three-
step increase. The third step, which is expected to increase revenues by $1.5
million, will go into effect October 1, 1996.
In Virginia, Commonwealth Services filed a general rate case in May 1995, with
new rates effective October 13, 1995. A settlement of the issues in this case
was reached with all parties on January 17, 1996. The settlement includes an
annual revenue increase of approximately $7.1 million and provides for a
separate proceeding to consider gas supply and other incentive proposals. The
settlement was presented to the Hearing Examiner on January 18, 1996, and
Commonwealth Services expects State Corporation Commission approval by
mid-1996.
Columbia of Maryland currently plans to file for an increase in base rates in
November 1996 with new rates effective June 1997. Columbia of Ohio's 1994 rate
case settlement provided for a re-opener, to provide the opportunity to recover
higher operating costs and additional plant investments, with new rates
effective May 1996. Columbia of Ohio has initiated discussions with its Ohio
Collaborative regarding an increase.
Regulatory Initiatives
Distribution continues to pursue regulatory initiatives designed to bring about
improvements to shareholders and customers. These initiatives focus on
maximizing efficiencies and customer choice and releasing temporarily unused
supply and pipeline capacity by continually monitoring current market demand.
Some of the incentive rate mechanisms Distribution is pursuing include:
- off-system sales where Distribution shares income with its
customers;
29
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
- supply management incentive programs that compensate Distribution
for purchasing gas at a cost that is lower than set prices reported
in major indices; and
- programs that allow Distribution to share income obtained by
releasing temporarily unused pipeline capacity with its customers.
Distribution continues to support pilot transportation programs that provide
small customers, including residential, the opportunity to arrange their own
gas purchases from marketers or producers while using Distribution's facilities
for the transportation. It is also working with legislatures and regulatory
commissions to streamline the related regulatory process.
In Distribution's various service areas, some of these activities have received
regulatory approval and are being implemented. In other jurisdictions
Distribution is still in the process of negotiating the various proposals with
the regulatory commissions and other interested parties.
In Ohio, a 1994 settlement allowed Columbia of Ohio to test a weather
normalization adjustment (WNA) to alleviate the impact of unusual weather on
customers' bills. As a result of some customer concerns with the program,
Columbia of Ohio agreed to several modifications in February 1995. During the
second quarter, Columbia of Ohio met with interested parties to review the
results of the WNA program, and it was jointly determined that the pilot
program should be suspended. Although it was generally agreed that WNA refunds
were not appropriate, certain local governments and consumer groups continue to
press for the refund of WNA revenues collected during the 1994-1995 winter.
Columbia of Ohio did not pursue a WNA for the 1995-1996 winter.
Columbia of Ohio is permitted to include in its plant investment
post-in-service carrying charges on those eligible plant investments which are
placed in service between December 31, 1990, and December 31, 1994. Columbia
of Ohio is currently recovering plant investment post-in-service carrying
charges for 1991, 1992 and 1993 in rates. Subject to regulatory approval, the
carrying charges are also authorized to be included in base rates in subsequent
rate filings. These carrying charges are subject to a net income limitation, as
determined by the regulatory commission, through 1997.
Project Customer Initiatives
Distribution is continuing to implement phases of its comprehensive initiative
termed "Project Customer", which is designed to reshape, streamline, and
enhance processes involved in delivering customer service. Columbia of Ohio
recently announced the establishment of three centralized customer service
centers, eliminating 26 smaller offices. The centers are designed to make
quality service more accessible and reliable for customers. As a result of
this initiative, Columbia of Ohio recorded a liability of $3.8 million in the
fourth quarter, representing salary and related severance benefit costs for 136
employees. A similar reorganization is expected in early 1996 for Columbia of
Pennsylvania and Columbia of Maryland with an estimated liability of $1.6
million, representing salary and related severance benefit costs for 71
employees. Efforts to restructure corporate services and other Project
Customer initiatives, that began in late 1993 and 1994, are continuing to be
implemented.
Capital Expenditures
In addition to maintaining and upgrading facilities to assure safe, reliable
and efficient operation, Distribution's 1995 capital expenditure program of
$152 million, essentially the same as 1994, included expenditures for extending
service to new areas. The 1996 capital expenditure program amounts to
approximately $160 million, including $60 million for new business development
and $79 million for replacement and betterment projects.
Gas Supply
To ensure a reliable supply of gas to its customers, Distribution contracts for
both the purchase of gas and the interstate pipeline and storage capacity
necessary to transport and store the commodity. Since natural gas is readily
available and in ample supply, Distribution enters into primarily short-term
contracts for natural gas requirements. In 1995, Distribution purchased about
80 percent of its supply under contracts with term lengths of one year or less.
Also, Distribution maintains long-term contracts for firm transportation
capacity to serve its core market requirements.
To meet its customers' needs during the heating season, Distribution has
developed a delivery system consisting of storage services, 50 percent; firm
transportation capacity on interstate pipelines, 49 percent; and peaking
service for the
30
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
coldest days, 1 percent. This favorable mix of storage and transportation
permits efficient annual utilization of Distribution's firm transportation
capacity and provides a high level of reliability.
In 1995, Distribution contracted for additional interstate pipeline capacity to
serve growing areas that have become capacity constrained. In addition,
Distribution has added peaking contracts that provide nearly 230,000 Mcf/day of
additional capacity to serve heavy customer demand on the coldest winter days.
Environmental Matters
Distribution's primary environmental issues relate to 14 former manufactured
gas plant sites. Investigations or remedial activities are currently underway
at five sites and 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 allowed or is anticipated.
On October 18, 1995, Columbia of Pennsylvania was served in a Comprehensive
Environmental Response Compensation and Liability Act cost recovery action
related to the Keystone Sanitation Company Landfill/Superfund site. Columbia
of Pennsylvania may be named as a Potentially Responsible Party (PRP) by virtue
of trash hauling services provided to Columbia of Pennsylvania's service center
by the city of Hanover, Pennsylvania. Columbia of Pennsylvania believes, based
on a preliminary investigation of the facts, that involvement at this site, if
any, will not have a material impact on Columbia.
Volumes
Distribution's 1995 throughput of 546.6 Bcf reflects an increase of 33.6 Bcf
over 1994. Higher transportation deliveries, off-system sales, continued
customer growth and colder weather contributed to the increase. Transportation
deliveries were 23.4 Bcf higher due to strong economic conditions in
Distribution's service area while the 7.2 Bcf increase in off- system sales
reflects recent changes in natural gas industry regulations which have
generated opportunities to buy and sell gas in the open market. Under current
regulatory treatment traditional customers are given the benefit of most of the
income derived from off-system sales.
Distribution's 1994 throughput of 513 Bcf reflected a 3.2 Bcf increase over
1993. Transportation deliveries of 232.5 Bcf were 15 Bcf higher largely due to
increased industrial demand in Ohio, Virginia and Kentucky as well as
industrial customers shifting from tariff sales to transportation services in
order to reduce their overall energy costs. The transportation improvement was
largely offset by an 11.8 Bcf sales decline due to nearly 3% warmer weather.
Net Revenues
Net revenues for 1995 of $821.5 million were up $86.7 million due to higher
rates that generated additional revenues of $56.3 million and improved
transportation deliveries that provided $14.3 million. Weather that was 3%
colder than 1994 resulted in a $4 million increase in net revenues. Surcharges
were $10.3 million higher in 1995 but they offset an equivalent expense and
have no impact on income.
Net revenues of $734.8 million in 1994 were up $8.8 million from 1993 primarily
due to higher rates and increased transportation deliveries.
Operating Income
Operating income for 1995 of $163.6 million reflected an increase of $35.3
million over 1994 as the higher net revenues were partially offset by increased
operating expenses of $51.4 million. Included in the higher operating expenses
was an expense equal to the revenue surcharges, discussed above, and previously
capitalized benefit costs that are expensed as they are included in rates.
After eliminating the effect of these issues, operating expenses were up
approximately $34.5 million. This increase reflects generally higher costs
including costs for computer applications, labor and expenses associated with
ongoing marketing and customer service activities as well as ongoing pipeline
maintenance. Increases in plant additions contributed to higher depreciation
expense and higher property taxes.
Operating income for 1994 decreased $18.1 million from 1993 to $128.3 million
as the increase in net revenues was more than offset by a $26.9 million
increase in operating expenses. Operation and maintenance expense increased
$12.5 million due to higher labor and benefits expense as well as the effect of
employee severance accruals associated with
31
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
implementing productivity and customer service initiatives. Other taxes
increased $12.2 million due to higher gross receipts taxes and property taxes
while the $2.2 million increase in depreciation expense primarily reflected
plant additions.
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1995 1994 1993
=============================================================================
NET REVENUES
Sales revenues $1,677.8 $1,741.9 $1,754.0
Less: Cost of gas sold 952.2 1,088.6 1,098.6
- -----------------------------------------------------------------------------
Net Sales Revenues 725.6 653.3 655.4
- -----------------------------------------------------------------------------
Transportation revenues 105.3 88.8 76.7
Less: Associated gas costs 9.4 7.3 6.1
- ----------------------------------------------------------------------------
Net Transportation Revenues 95.9 81.5 70.6
- ----------------------------------------------------------------------------
Net Revenues 821.5 734.8 726.0
- ----------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 443.0 404.0 391.5
Depreciation 70.9 64.5 62.3
Other taxes 144.0 138.0 125.8
- ----------------------------------------------------------------------------
Total Operating Expenses 657.9 606.5 579.6
- ----------------------------------------------------------------------------
OPERATING INCOME $ 163.6 $ 128.3 $ 146.4
- ----------------------------------------------------------------------------
32
33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS*
1995 1994 1993 1992 1991
==============================================================================================================
CAPITAL EXPENDITURES ($ in millions) 151.8 151.4 117.8 99.7 98.0
- --------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
Residential 196.6 189.7 194.7 186.2 178.4
Commercial 79.5 80.8 83.4 81.8 78.3
Industrial and Other 7.1 9.7 14.2 15.0 11.0
- --------------------------------------------------------------------------------------------------------------
Total Sales 283.2 280.2 292.3 283.0 267.7
Transportation 255.9 232.5 217.5 203.7 194.7
- --------------------------------------------------------------------------------------------------------------
Total Throughput 539.1 512.7 509.8 486.7 462.4
Off-System Sales 7.5 0.3 - - -
- --------------------------------------------------------------------------------------------------------------
Total Sold or Transported 546.6 513.0 509.8 486.7 462.4
- --------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
Spot market** 210.4 235.3 142.3 169.9 113.9
Producers 70.9 67.5 56.9 57.1 64.4
Pipelines - - 118.4 84.0 68.2
Storage withdrawals (injections) 23.6 (14.0) (6.7) (10.7) 11.4
Company use and other (14.2) (8.3) (18.6) (17.3) 9.8
- ---------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 290.7 280.5 292.3 283.0 267.7
Gas received for delivery
to customers 255.9 232.5 217.5 203.7 194.7
- ---------------------------------------------------------------------------------------------------------------
Total Sources 546.6 513.0 509.8 486.7 462.4
- ---------------------------------------------------------------------------------------------------------------
CUSTOMERS
Residential 1,794,800 1,764,968 1,737,609 1,711,946 1,686,918
Commercial 172,114 167,067 164,037 161,937 160,378
Industrial and Other 2,265 2,312 2,302 2,382 2,366
- ---------------------------------------------------------------------------------------------------------------
Total 1,969,179 1,934,347 1,903,948 1,876,265 1,849,662
- ---------------------------------------------------------------------------------------------------------------
DEGREE DAYS 5,692 5,530 5,677 5,507 4,998
- ---------------------------------------------------------------------------------------------------------------
* Includes Columbia Gas of New York, Inc. through March 31, 1991.
** Reflects volumes under purchase contracts of less than one year.
33
34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
Proposed Sale of Columbia Development
On October 23, 1995, Columbia announced its intention to sell Columbia
Development, its wholly-owned southwest oil and gas exploration and production
subsidiary, which has approximately 196 billion cubic feet equivalent (Bcfe) of
proved oil and natural gas reserves located in the Gulf of Mexico and on-shore
continental United States. Based on the proposed sale of this subsidiary in
early 1996, an estimated loss of $54.8 million after-tax was recorded in the
fourth quarter of 1995. It is expected that the proposed sale of Columbia
Development may take several months to complete and the financial impact of the
sale may be different once finalized. Management has determined that the
strategic value to Columbia of drilling for oil and gas in the Southwest has
diminished and that Columbia's investment in Columbia Development would be
better devoted to assets focused on meeting customer needs. Columbia is not
exiting the exploration and production business, and will retain its larger and
more strategically placed Appalachian oil and gas subsidiary, Columbia Natural
Resources, Inc. (CNR), which is closer to Columbia's customer base and pipeline
service territory. As of December 31, 1995, CNR held interests in more than
2.2 million net acres of gas and oil leases and had proved oil and gas reserves
in excess of 609 Bcfe.
Market Conditions
Despite a rise in gas prices in late 1995, average prices for the year were
lower than the year earlier and had an adverse impact on results from
operations of the oil and gas segment. Columbia's natural gas prices averaged
$1.96 per Mcf in 1995 compared to $2.18 in 1994. Oil prices improved to $16.17
per barrel for 1995 from a 1994 level of $15.09 per barrel. The decline in gas
prices throughout most of 1995 has been attributed to a number of factors
including warm weather in the first quarter of 1995, increased imports from
Canada, greater pipeline and storage flexibility, and general excess supply
deliverability as a result of federal deregulation. In December 1995, gas
prices rebounded as storage levels fell due to unseasonably colder weather.
Fluctuations in oil and gas prices can cause significant variations in revenues
for the oil and gas segment. To dampen the impact of these price swings and
help stabilize revenues, the oil and gas segment uses futures and option
contracts and price swap agreements to lessen the price risk for a portion of
its production. (See Note 4 - Commodity Hedging in Notes to Consolidated
Financial Statements for additional information.)
Capital Expenditures
In the Appalachian area, CNR participated in the drilling of 96 gross (61 net)
development wells in 1995, with a success rate of 74%. The primary focus of
CNR's 1995 drilling activity was in the Rose Run formation in southeast Ohio
and shale formations in West Virginia. CNR's $21 million capital and
exploration budget for 1996 is anticipated to focus on joint venture prospects
in Ohio, which have higher reserve and deliverability potential.
In the southwest, Columbia Development drilled 67 gross (24 net) wells in 1995,
with an 82 percent success rate. In the Austin Chalk drilling program, 45 out
of 48 Austin Chalk wells drilled in 1995 were successful.
Gathering Facilities
Under Order 636, the natural gas pipeline industry is required to eventually
unbundle gathering services from other transportation services. Columbia
Transmission provides transportation services, including gathering services,
for a significant portion of gas produced from CNR's reserves. In its August
1, 1995 general rate filing, Columbia Transmission requested an increase in its
gathering rate to reflect partial unbundling of this service.
Columbia Transmission is currently preparing the regulatory filings necessary
for abandonment of selected gathering facilities and transfer of those assets
to CNR. Capital expenditures needed to purchase these intercompany assets are
estimated at $22 million, the book value of the facilities, with additional
costs to be incurred for compression and measurement. Operation and
maintenance costs associated with these facilities will be partially offset by
the absence of Columbia Transmission's gathering charges on wells located in
southern West Virginia coupled with additional revenue generated from
transportation of third party gas.
Reserves
Net proved gas reserves at the end of 1995 totaled approximately 737 Bcf,
compared to 684 Bcf at the end of 1994. The determination that an increasing
number of CNR's wells are economical to produce at year-end 1995 gas prices is
34
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
reflected in a 116 Bcf upward revision in recoverable gas reserves in the
Appalachian area. Without this revision, CNR's reserve base declined as
production exceeded newly discovered Appalachian reserves and extensions of 14
Bcf . Drilling activity in the Appalachian area was curtailed during 1995 due
to low natural gas prices. In the Southwest, net proved reserves declined
slightly as production during 1995 and an 8 Bcf downward revision in
recoverable gas reserves exceeded new discoveries and extensions of 39 Bcf by
approximately one Bcf.
Proved reserves for oil, condensate and natural gas liquids decreased from 12.3
million barrels at the end of 1994 to 11.6 million barrels for 1995. While
production of 2.8 million barrels was largely replaced through extensions and
discoveries of 2.7 million barrels during 1995, net reserves were revised
downward by 0.5 million barrels.
Volumes
Gas production decreased 1.9% in 1995 to 65.4 Bcf primarily due to normal
production declines from onshore wells in the Southwest. Gas production
in the Appalachian area was essentially unchanged at 33.3 Bcf as production
from new wells offset normal production declines from older wells combined with
production curtailments resulting from replacement and repair of Columbia
Transmission's gathering lines and compressor facilities. In 1994, gas
production decreased 6.7% to 66.7 Bcf as production declined in both the
Southwest and Appalachian areas. The decline was primarily attributable to the
same factors impacting 1995 production.
Oil and liquids production declined in 1995 by 21.1% to 2.8 million barrels.
The decrease was primarily due to production declines in onshore wells,
especially horizontal wells in the Austin Chalk field, and decreased gas
processing from the West Cameron 485 block at the Blue Water Gas Processing
Plant. In 1994, oil and liquids production was essentially unchanged from 1993
as an increase in Appalachian production offset the decrease in the Southwest
program due to offshore well production problems.
Operating Revenues
In 1995, operating revenues were $180.6 million, a decrease of $24.7 million
from 1994. The decrease is primarily attributable to lower gas prices and
significantly lower oil and liquids production in the southwest. In 1994,
operating revenues declined $16.9 million or 7.6% from 1993 as the impact of
lower oil and gas prices and the decrease in gas production was only partially
offset by the combined effect of recording a reserve of $5.4 million in 1993
for a royalty dispute and the subsequent reversal of most of this reserve in
1994.
Operating Income
Operating income in 1995 declined by $26.9 million to $3.7 million primarily
due to the lower operating revenues. In 1994, operating income declined by $23
million due to lower operating revenues and an increase in depletion expense of
$12.4 million as a result of depressed energy prices.
35
36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
STATEMENTS OF OPERATING INCOME FROM OIL AND GAS OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1995 1994 1993
- ---------------------------------------------------------------------------------------
OPERATING REVENUES
Gas $134.4 $150.7 $ 163.8
Oil and liquids 46.2 54.6 58.4
- ---------------------------------------------------------------------------------------
Total Operating Revenues 180.6 205.3 222.2
- ---------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 79.6 76.9 83.7
Depreciation and depletion 86.9 86.2 73.8
Other taxes 10.4 11.6 11.1
- ---------------------------------------------------------------------------------------
Total Operating Expenses 176.9 174.7 168.6
- ---------------------------------------------------------------------------------------
OPERATING INCOME $ 3.7 $ 30.6 $ 53.6
- ---------------------------------------------------------------------------------------
OIL AND GAS OPERATING HIGHLIGHTS*
1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 86.8 101.6 95.1 70.8 120.8
- --------------------------------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf)(a) 736.5 683.8 697.0 779.5 808.1
Oil and Liquids (000 barrels)(b) 11,552 12,255 12,792 14,650 15,568
- --------------------------------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf) 65.4 66.7 71.5 69.2 76.3
Oil and Liquids (000 barrels) 2,849 3,611 3,603 3,061 3,411
- --------------------------------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf) 1.96 2.18 2.28 2.02 1.81
Oil and Liquids ($ per barrel) 16.17 15.09 16.17 18.20 21.10
- --------------------------------------------------------------------------------------------------------------
* Year 1991 include results from Canadian operations that were sold effective
December 31, 1991.
(a) Includes reserves held for sale of 137.0 Bcf in 1995.
(b) Includes reserves held for sale of 9.9 million barrels in 1995.
36
37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OTHER ENERGY OPERATIONS
Energy Services
Columbia Energy Services Corporation (Columbia Energy Services) oversees
Columbia's nonregulated natural gas marketing efforts and provides an array of
services to distribution companies, independent power producers and other large
end users both on and off Columbia's transmission and distribution pipeline
system. Columbia Energy Services offers one-stop shopping for natural gas
supply, transportation-related services, and fuel management services to help
customers better manage their energy costs. In 1995, electronic trading, The
Fast Lane(TM), was added to its services making real-time trading of natural
gas supplies and pipeline capacity easier and more efficient.
Propane
During 1995, propane sales by Columbia Propane Corporation and Commonwealth
Propane, Inc. (Commonwealth Propane) totaled 68.9 million gallons, a small
increase over 1994. The propane companies serve approximately 74,300 customers
in parts of Kentucky, Maryland, New York, North Carolina, Ohio, Pennsylvania,
Virginia and West Virginia.
Cogeneration
Columbia is part owner in four cogeneration projects through its subsidiary,
TriStar Ventures Corporation (TriStar). These facilities produce both
electricity and useful thermal energy and are fueled principally by natural
gas. TriStar holds various interests in these facilities that have a total
capacity of nearly 300 megawatts. In 1995, TriStar expanded its business to
include facility energy management services. This includes providing
operations, maintenance, and technical advisory services for power generation
projects. TriStar plans to utilize the extensive Columbia presence in the
Mid-Atlantic region to market its services and develop additional opportunities
with customers of Columbia's distribution subsidiaries.
Cove Point Facility
Columbia LNG is a partner with subsidiaries of the Potomac Electric Power
Company in Cove Point LNG Limited Partnership (Cove Point LNG). Cove Point LNG
recently began commercial operations of one of the largest natural gas peaking
and storage facilities in the United States located at Cove Point, Maryland.
The facility has a capacity to liquefy natural gas at a rate of 15,000 Mcf per
day and stores the resulting liquefied natural gas until needed for winter peak
day requirements of utilities and other large gas users.
Commodity Hedging
Columbia Energy Services and Commonwealth Propane use commodity futures from
time to time to hedge prices on commitments for natural gas purchases and sales
and propane inventories. Under internal guidelines, speculative positions are
prohibited.
Columbia Energy Services uses commodity futures contracts to assure acceptable
margins on the purchase and resale of natural gas in future months. When
Columbia Energy Services makes a sale for future delivery without having
natural gas committed to that sale, it purchases commodity futures to reduce
the risk of increasing prices prior to purchasing the natural gas to fulfill
the sales obligation.
Commonwealth Propane purchases propane and places it in inventory for future
sale. Commonwealth Propane sells commodity futures on a portion of its
inventory at the time of purchase to protect it from decreasing prices.
Environmental Matters
Columbia Gas System Service Corporation (Service Corporation) received a
"General Notice of Potential Liability and Section 104(2) Request for
Information" from the EPA concerning a process site to which the Service
Corporation sent certain solvents. Service Corporation joined a group for the
purpose of sharing the costs of the cleanup. Management does not believe this
Superfund matter will have a material adverse effect on future income or
Columbia's financial position.
Net Revenues
Net revenues for gas marketing in 1995 were essentially unchanged at $7.1
million after increasing by $3.8 million in 1994. In the prior year the
demand for gas marketing services surged as a result of the new environment
created by
37
38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Order 636. Net revenues from propane operations in 1995 were also relatively
unchanged at $29.6 million from the prior year. Net revenues increased in
1994 due primarily to cold weather in the first quarter of 1994.
Other revenues increased $10.2 million in 1995, to $86.4 million, due to an
increase in revenues for professional services provided to affiliates, revenues
from Columbia LNG and an increase for cogeneration activities. In 1994, other
revenues increased $1.4 million as the impact of increased cogeneration
activities was mostly offset by a decline in revenues for service provided to
affiliated companies due to restructuring certain processes.
Operating Income
The $4.8 million decrease in operating income in 1995 to $19.3 million reflects
higher costs for services provided to affiliates, higher operating expenses for
propane operations and an operating loss associated with Columbia LNG. The $21
million increase in operating income in 1994 was due to the $12.8 million
decrease in operating expenses reflecting the impact of a reserve recorded in
1993 for employee severance costs and the overall increase of $8.2 million in
net revenues.
38
39
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM OTHER ENERGY OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1995 1994 1993
- ------------------------------------------------------------------------------------------
NET REVENUES
Gas marketing revenues $237.9 $232.1 $176.5
Less: Products purchased 230.8 225.3 173.5
- ------------------------------------------------------------------------------------------
Net Gas Marketing Revenues 7.1 6.8 3.0
- ------------------------------------------------------------------------------------------
Propane revenues 65.1 63.2 56.5
Less: Products purchased 35.5 33.4 29.7
- ------------------------------------------------------------------------------------------
Net Propane Revenues 29.6 29.8 26.8
- ------------------------------------------------------------------------------------------
Other revenues 86.4 76.2 74.8
- ------------------------------------------------------------------------------------------
Net Revenues 123.1 112.8 104.6
- ------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 90.4 76.3 90.8
Depreciation and depletion 7.9 7.1 5.9
Other taxes 5.5 5.3 4.8
- ------------------------------------------------------------------------------------------
Total Operating Expenses 103.8 88.7 101.5
- ------------------------------------------------------------------------------------------
OPERATING INCOME $ 19.3 $ 24.1 $ 3.1
- ------------------------------------------------------------------------------------------
OTHER ENERGY OPERATING HIGHLIGHTS
1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 14.1 15.1 11.2 15.0 10.2
- --------------------------------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions) 68.9 68.5 58.1 63.3 70.5
Customers 74,308 68,218 67,895 65,899 64,618
- --------------------------------------------------------------------------------------------------------------
39
40
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
BANKRUPTCY MATTERS
On November 28, 1995, Columbia and its wholly-owned subsidiary, Columbia
Transmission, emerged from Chapter 11 protection of the Federal Bankruptcy
Code. Both Columbia and Columbia Transmission operated under Chapter 11 since
filing for protection on July 31, 1991. The companies were granted
debtor-in-possession status under the Bankruptcy Code, allowing them to conduct
normal business operations subject to the jurisdiction of the United States
Bankruptcy Court for the District of Delaware (Bankruptcy Court).
Events that Led to Bankruptcy Filings
Both Columbia's and Columbia Transmission's Chapter 11 filings were
precipitated by a combination of events that adversely affected Columbia
Transmission's financial viability. Most notable were federal legislative and
regulatory actions, instituted years after Columbia Transmission signed gas
purchase contracts that significantly impacted Columbia Transmission's ability
to sell gas at a price which would allow it to recover the contracted purchase
price. These problems were compounded by record-setting warm weather in 1990
and 1991, that caused spot market prices for gas to plunge and created excess
transportation capacity, thus making an unexpected and persistent oversupply of
bargain-priced gas available to Columbia Transmission's customers. As a
result, Columbia Transmission's ability to market its gas was severely
undercut, substantially reducing both sales volumes and revenues.
Settlement of Prepetition Obligations
In settlement of its prepetition obligations, Columbia distributed
approximately $3.6 billion to its creditors, which included $2.3 billion for
Columbia's prepetition debt and approximately $1 billion for interest on that
debt. The amounts represented full payment of creditors' prepetition claims.
This distribution was funded by:
- $2 billion in new long-term debt securities, with maturities ranging
from 5 to 30 years;
- $1 billion in cash, funded by cash on hand and approximately $370
million of new bank debt; and
- $200 million in Series A - Preferred Stock and $200 million in Series
B - DECS.
The interest rates on the new debt securities and the dividend rates and other
financial terms of the new equity securities were based on market levels at the
time of emergence. Columbia's new long-term debt obligations were rated as
investment grade by three major rating agencies. (See Liquidity and Capital
Resources discussion on page 19 for more information.)
The provisions of Columbia Transmission's Plan provided for a total
distribution at or after emergence of approximately $3.9 billion to its
creditors, including:
- 100% of all priority and administrative claims, which together
amounted to $255 million;
- 100% of Columbia's secured claim of approximately $2 billion,
including interest, which was funded with approximately $900 million
of secured debt securities of reorganized Columbia Transmission and
all of its equity;
- 100% of all unsecured claims of $25,000 or less, which amounted to $8
million;
- 72.5% of all miscellaneous unsecured creditor claims in excess of
$25,000, which amounted to $40 million;
- approximately $130 million in customer refunds as provided under terms
of a customer settlement agreement. 68.875 to 72.5% of the $351
million unsecured claim of Columbia, that will be ultimately
determined by the final distribution percentage received by unsecured
producers; and
- an estimated $1.2 billion to unsecured producers (based on 100%
acceptance by producers of the settlement amounts proposed in the
Plan). Columbia Transmission's Plan included a producer settlement
that provided for a total proposed allowed amount of producer claims
of $1.6 billion and for distributions of 72.5% to those creditors who
had claims under those contracts in excess of $25,000.
Columbia Transmission's Plan provides that producers who rejected settlement
offers contained in Columbia Transmission's Plan may continue to litigate their
claims under the Bankruptcy Court-approved estimation procedures, described
below, and will receive the same percentage payout on their claims, when and if
ultimately allowed, as received by the settling producers. Columbia
Transmission's Plan further provided that the actual distribution percentage
for producer claims, which would not be less than 68.875% or greater than
72.5%, would not be determined
40
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
until the total amount of contested producer claims is established, and that
until such time, 5% of the amount to be distributed to producer claimants and
Columbia for unsecured debt will be withheld.
The 5% holdback from settling producers and a matching contribution by
reorganized Columbia Transmission, to the extent necessary, will be used to
fund any distributions on producer claims ultimately liquidated in an aggregate
amount in excess of those proposed by Columbia Transmission's Plan. If the
holdback and matching contributions are exhausted, any further distribution
would be funded entirely by Columbia Transmission. Columbia has guaranteed the
payment of the remaining distributions to producers, either in cash or, to the
extent that a nonsettling producer's finally allowed claim exceeds its proposed
settlement value, in Columbia's common stock.
Producer Claims Estimation Process
In 1992, the Bankruptcy Court approved the appointment of a Claims Mediator and
the implementation of a claims estimation procedure for the quantification of
claims arising from the rejection of above-market gas purchase contracts and
other claims by producers related to gas purchase contracts with Columbia
Transmission. In late 1994 and early 1995, the Claims Mediator issued the
Initial Report and Recommendations of the Claims Mediator on generic issues for
Natural Gas Contract Claims and a Supplement to Initial Report and
Recommendations of the Claims Mediator (Report) and directed producer claimants
to submit to him recalculated claims prepared pursuant to the instructions
contained in the Report. The recommendations and instructions set out in the
Report have not been considered by the Bankruptcy Court. In mid-1995,
producers with which Columbia Transmission had not yet negotiated settlements
liquidating their claims submitted recalculated claims to the Claims Mediator.
As submitted, those recalculated claims initially amounted to over $2 billion.
Since mid-1995, numerous additional producers settled their claims and those
settlements became final with the confirmation of Columbia Transmission's Plan.
In addition, several recalculated claims have been amended by producer
claimants.
The estimation procedures remain in place under the Plan for use in the
post-confirmation liquidation of producer claims that were not resolved with
the confirmation of the Plan. The recalculated claims still subject to the
estimation process total about $490 million, as submitted and amended. The
estimation process is now proceeding with discovery, motions for dismissal or
summary judgement and evidentiary hearings before the Claims Mediator to
address individual producer claims, including specific issues not addressed by
the Report. The recommendations of the Claims Mediator concerning the amounts
at which particular claims should be allowed, as issued, are being submitted to
the Bankruptcy Court for consideration. The parties have rights of appellate
review with respect to the resulting orders of the Bankruptcy Court. When
claims are allowed by the Bankruptcy Court and the allowances become final,
Columbia Transmission will make additional distributions pursuant to the Plan.
The timing of the completion of this litigation process is impossible to
predict.
Based on the information received and evaluated to date, Columbia Transmission
believes that most of the remaining claims will be settled at amounts
approximating the settlement values, but expects that some claims may be
settled or resolved through litigation at amounts higher or lower than the
proposed settlement values. Although Columbia Transmission does not have
sufficient information to fully evaluate all claims and the outcome of
litigation is subject to uncertainty, it currently estimates that the ultimate
payment to producers, after litigation and after giving effect to the producer
holdback, is likely to exceed the $1.2 billion distribution projected in the
Plan (which is based on 100% producer acceptance of amounts proposed in the
Plan) but is unlikely to exceed $1.3 billion. The foregoing estimation is
based on the information currently available, and there can be no assurance as
to the timing or amounts of settlements with producers or as to the amount
ultimately allowed or paid with respect to the remaining claims.
Intercompany Complaint
Columbia Transmission's Plan provided for the withdrawal of a complaint filed
by the Official Committee of Unsecured Creditors of Columbia Transmission with
the Bankruptcy Court. The complaint alleged, among other items, that the $1.7
billion of Columbia Transmission's secured and unsecured debt securities held
by Columbia should be recharacterized as capital contributions (rather than
loans) and equitably subordinated to the claims of Columbia Transmission's
other creditors.
41
42
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Internal Revenue Service Matters
Columbia received a favorable ruling from the Internal Revenue Service (IRS) in
October 1995, stating that payments made by Columbia Transmission pursuant to
its Plan to producers in connection with their contract rejection claims were
deductible for tax purposes in the year in which the payments were made.
Because of the magnitude of the payments, obtaining a favorable ruling from the
IRS was a condition of both Plans.
Security Holder and Derivative Litigation
On July 18, 1995, Columbia reached a settlement that resolved a consolidated
class action complaint filed in the District Court in 1991 against Columbia and
its directors and certain officers of the debtor companies. Under the terms of
the settlement Columbia paid approximately $16.5 million of the total $36.5
million settlement. The remainder was shared among the insurance carrier for
the director and officer defendants and the other defendants to the litigation.
The settlement was implemented upon Columbia's emergence from Chapter 11. Also
in 1991, three derivative actions were filed in the Court of Chancery in and
for New Castle County (Delaware) alleging that directors had breached their
fiduciary duties to Columbia. Consistent with the recommendation of a special
committee of Columbia's Board of Directors it was determined that it was in the
best interest of Columbia to dispose of the litigation. The derivative
litigation was released and dismissed pursuant to Columbia's Plan.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------------------------------------------------------
Index Page
- --------------------------------------------------------------------------------------------------------------------------------
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Statements of Consolidated Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
Statements of Consolidated Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Statements of Consolidated Common Stock Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Schedule II - Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
- --------------------------------------------------------------------------------------------------------------------------------
42
43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of The Columbia Gas System, Inc.:
We have audited the accompanying consolidated balance sheets of The Columbia
Gas System, Inc. (a Delaware corporation, the "Corporation") and subsidiaries
as of December 31, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
As discussed in Note 5B, effective January 1, 1994, the Corporation changed its
method of accounting for postemployment benefits pursuant to standards
promulgated by the Financial Accounting Standards Board.
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 5, 1996
43
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31 (in millions except per share amounts) 1995* 1994* 1993*
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Gas sales $1,929.0 $2,031.3 $2,574.3
Transportation 487.7 505.7 518.4
Other 218.5 210.1 221.1
- --------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,635.2 2,747.1 3,313.8
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Products purchased 820.6 984.2 1,577.7
Operation 826.7 774.4 702.3
Maintenance 116.6 133.7 165.5
Depreciation and depletion 270.0 261.7 239.8
Other taxes 211.1 209.0 198.0
Writedown of investment in CLG - - 57.5
- --------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,245.0 2,363.0 2,940.8
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 390.2 384.1 373.0
- --------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
Interest income and other, net (Note 14) (58.2) 35.2 7.7
Interest expense and related charges** (Note 15) (988.4) (14.8) (101.5)
Reorganization items, net (Note 2) 13.4 (12.3) 8.9
- --------------------------------------------------------------------------------------------------------------------------------
Total Other Income (Deductions) (1,033.2) 8.1 (84.9)
- --------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES, EXTRAORDINARY
ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE (643.0) 392.2 288.1
Income taxes (Note 6) (210.7) 146.0 135.9
- --------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (432.3) 246.2 152.2
Extraordinary item (Note 5A) 71.6 - -
Cumulative effect of change in accounting
for postemployment benefits (Note 5B) - (5.6) -
- --------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $(360.7) $ 240.6 $ 152.2
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
(based on average shares outstanding)
Before extraordinary item and accounting change $(8.57) $ 4.87 $ 3.01
Extraordinary item 1.42 - -
Change in accounting for postemployment benefits - (0.11) -
- --------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) on Common Stock $(7.15) $ 4.76 $ 3.01
- --------------------------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (thousands) 50,468 50,560 50,559
- --------------------------------------------------------------------------------------------------------------------------------
*Reference is made to Note 2 of Notes to Consolidated Financial Statements.
**Due to the bankruptcy filings, interest expense of approximately $230 million
and $210 million was not recorded in 1994 and 1993, respectively (see Note 2
of Notes to Consolidated Financial Statements). Interest expense of $982.9
million including write-off of unamortized discounts on debentures, was
recorded in the fourth quarter of 1995.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
44
45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS
The Columbia Gas System, Inc. and Subsidiaries
ASSETS as of December 31 (in millions) 1995* 1994*
- --------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant, at original cost $6,903.2 $6,637.5
Accumulated depreciation and depletion (3,322.0) (3,180.8)
- --------------------------------------------------------------------------------------------------------------------------------
Net Gas Utility and Other Plant 3,581.2 3,456.7
- --------------------------------------------------------------------------------------------------------------------------------
Oil and gas producing properties, full cost method 516.3 1,261.9
Accumulated depletion (141.1) (637.6)
- --------------------------------------------------------------------------------------------------------------------------------
Net Oil and Gas Producing Properties 375.2 624.3
- --------------------------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment 3,956.4 4,081.0
- --------------------------------------------------------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
Accounts receivable - noncurrent 91.2 211.2
Unconsolidated affiliates 78.2 80.7
Assets held for sale (Note 13B) 182.8 -
Other 2.4 14.5
- --------------------------------------------------------------------------------------------------------------------------------
Total Investments and Other Assets 354.6 306.4
- --------------------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 8.0 1,481.8
Accounts receivable
Customers (less allowance for doubtful accounts
of $12.3 and $11.6, respectively) 429.2 425.5
Other 81.8 122.3
Income tax refund 271.5 -
Gas inventory 172.3 230.3
Other inventories - at average cost 41.5 42.0
Prepayments 56.9 63.3
Regulatory assets 76.5 39.9
Other 138.2 117.3
- --------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,275.9 2,522.4
- --------------------------------------------------------------------------------------------------------------------------------
REGULATORY ASSETS 422.0 212.1
DEFERRED CHARGES 48.1 43.0
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $6,057.0 $7,164.9
- --------------------------------------------------------------------------------------------------------------------------------
*Reference is made to Note 2 of Notes to Consolidated Financial Statements.
**Due to the bankruptcy filings, accrued interest of approximately $730 million
was not recorded as of December 31, 1994.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
45
46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CAPITALIZATION AND LIABILITIES as of December 31 (in millions) 1995* 1994*
- --------------------------------------------------------------------------------------------------------------------------------
COMMON STOCK EQUITY
Common stock, par value $10 per share - outstanding 49,204,025
and 50,563,335 shares, respectively $506.2 $505.6
Additional paid in capital 595.8 601.9
Retained earnings 69.8 430.5
Less: Cost of treasury stock (1,416,155 shares) 57.8 -
Unearned employee compensation - (70.0)
- --------------------------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 1,114.0 1,468.0
PREFERRED STOCK (Note 9) 399.9 -
LONG-TERM DEBT (Note 10) 2,004.5 4.3
- --------------------------------------------------------------------------------------------------------------------------------
Total Capitalization 3,518.4 1,472.3
- --------------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Short-term debt (Note 11) 338.9 -
Accounts and drafts payable 215.7 153.2
Accrued taxes 271.3 175.2
Accrued interest** 94.3 -
Estimated rate refunds 96.1 92.2
Estimated supplier obligations 178.3 69.7
Overrecovered gas costs 41.7 59.5
Transportation and exchange gas payable 46.7 35.1
Other 295.6 275.0
- --------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,578.6 859.9
- --------------------------------------------------------------------------------------------------------------------------------
LIABILITIES SUBJECT TO CHAPTER 11 PROCEEDINGS (Note 2) - 3,977.7
- --------------------------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Deferred income taxes - noncurrent 468.6 344.1
Investment tax credits 38.6 38.6
Postretirement benefits other than pensions 208.2 236.3
Regulatory liabilities 44.9 26.2
Other 199.7 209.8
- --------------------------------------------------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits 960.0 855.0
- --------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2, 3 and 13) - -
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $6,057.0 $7,164.9
- --------------------------------------------------------------------------------------------------------------------------------
46
47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31 (in millions) 1995* 1994* 1993*
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) $(360.7) $240.6 $152.2
Adjustments for items not requiring (providing) cash:
Depreciation and depletion 270.0 261.7 239.8
Deferred income taxes 66.1 72.2 19.1
Reapplication of SFAS 71 (71.6) - -
Estimated loss on sale of Columbia Gas Development
Corporation 77.8 - -
Change in accounting for postemployment benefits - 5.6 -
Interest expense settled at emergence 702.9 - -
Payment of Chapter 11 liabilities (1,169.1) - -
Other - net** (94.0) (25.0) 239.8
Changes in components of working capital:
Accounts receivable 99.7 135.9 (1.4)
Gas inventory 58.0 (32.5) 115.7
Prepayments 12.3 (8.0) 2.4
Accounts payable 38.3 (35.5) (59.3)
Accrued taxes (314.9) 45.7 5.5
Estimated rate refunds (56.6) (133.3) (59.4)
Estimated supplier obligations (44.0) (49.7) 131.2
Under/Overrecovered gas costs (18.0) 106.7 (23.2)
Exchange gas payable 10.4 (31.7) (10.1)
Other working capital (14.0) 20.1 98.1
- --------------------------------------------------------------------------------------------------------------------------------
Net Cash From Operations (807.4) 572.8 850.4
- --------------------------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
Capital expenditures (411.0) (433.6) (345.7)
Sale of partnership interest 10.9 - -
Other investments - net 25.2 (1.3) 3.9
- --------------------------------------------------------------------------------------------------------------------------------
Net Investment Activities (374.9) (434.9) (341.8)
- --------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Retirement of prepetition debt obligations (637.3) - -
Retirement of long-term debt (0.8) (0.9) (0.8)
Issuance of common stock 1.8 - -
Increase in short-term debt and other financing activities 344.8 4.4 12.0
- --------------------------------------------------------------------------------------------------------------------------------
Net Financing Activities (291.5) 3.5 11.2
- --------------------------------------------------------------------------------------------------------------------------------
Increase (Decrease) in cash and temporary cash investments (1,473.8) 141.4 519.8
Cash and temporary cash investments
at beginning of year 1,481.8 1,340.4 820.6
- --------------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 8.0 $ 1,481.8 $ 1,340.4
- --------------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest 284.9 0.8 0.5
Cash paid for income taxes (net of refunds) 42.3 37.4 88.7
- --------------------------------------------------------------------------------------------------------------------------------
*Reference is made to Note 2 of Notes to Consolidated Financial Statements.
**Includes changes in Liabilities Subject to Chapter 11 Proceedings of
($2,842.0) in 1995, $61.1 million in 1994, and ($39.4) million in 1993.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
47
48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
The Columbia Gas System, Inc. and Subsidiaries
Common Stock*
----------------------------------- Additional Unearned
(In millions except Shares Par Treasury Paid In Retained Employee
for share amounts) Outstanding(000) Value Stock Capital Earnings Compensation Total
- --------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1992 50,559 $505.6 $ - $601.8 $ 37.7 $(70.0) $1,075.1
Net Income 152.2 152.2
- --------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1993 50,559 505.6 - 601.8 189.9 (70.0) 1,227.3
Net Income 240.6 240.6
Common stock issued:
Long-Term Incentive Plan 4 0.1 0.1
- --------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1994 50,563 505.6 - 601.9 430.5 (70.0) 1,468.0
Net Loss (360.7) (360.7)
Termination of LESOP (1,416) (57.8) (7.9) 70.0 4.3
Common stock issued:
Long-Term Incentive Plan 57 0.6 1.8 2.4
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1995 49,204 $506.2 $(57.8) $595.8 $ 69.8 $ - $1,114.0
- --------------------------------------------------------------------------------------------------------------------------------
*100 million shares authorized at December 31, 1995, 1994, 1993 and 1992 - $10
par value.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
48
49
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 Columbia and all subsidiaries. All
intercompany accounts and transactions have been eliminated.
Certain reclassifications have been made to the 1994 and 1993
financial statements to conform to the 1995 presentation.
B. CASH AND CASH EQUIVALENTS. Columbia considers all highly liquid debt
instruments to be cash equivalents.
In settlement of its prepetition obligations, Columbia distributed
approximately $3.6 billion to its creditors, which included $2.3
billion for Columbia's prepetition debt and approximately $1.0 billion
for interest on that debt. This distribution was funded by $2.0
billion in new long-term debt securities, $0.9 billion in cash, which
included cash on hand and $0.4 billion of new bank debt, and $0.2
billion in Series A - Preferred Stock and $0.2 billion in Series
B-DECS. The issuance of these securities represents non-cash
financing activities.
C. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation," (SFAS No. 71) provides that
rate-regulated public utilities account for and report assets and
liabilities consistent with the economic effect of the way in which
regulators establish rates, if the rates established are designed to
recover the costs of providing the regulated service and if the
competitive environment makes it reasonable to assume that such rates
can be charged and collected. As more fully discussed in Note 5A,
Columbia's transmission subsidiaries reapplied the provisions of SFAS
No. 71 concurrent with the emergence from Chapter 11 protection.
Columbia's gas distribution subsidiaries continue to follow the
accounting and reporting requirements of SFAS No. 71.
Certain expenses and credits subject to utility regulation or rate
determination normally reflected in income are deferred on the balance
sheet and are recognized in income as the related amounts are included
in service rates and recovered from or refunded to customers.
Condensed information for assets and liabilities subject to utility
regulation and rate determination are as follows:
Transmission Distribution
Subsidiaries Subsidiaries
At December 31 ($ in millions) 1995 1994 1995 1994
---------------------------------------------------------------------------------------------------
ASSETS
Environmental costs 132.5 - 8.2 8.4
Postemployment and postretirement benefits 75.9 - 137.7 138.0
Percent of income plan - - 16.5 20.4
Retirement income plan 10.3 - 17.2 11.0
Regulatory effects of accounting for income taxes, net - - 50.9 51.5
Post in service carrying charges - - 24.4 -
Other 14.1 - 10.8 22.7
---------------------------------------------------------------------------------------------------
Total regulatory assets 232.8 - 265.7 252.0
===================================================================================================
LIABILITIES
Rate refunds and reserves 36.0 - 60.1 80.1
Overrecovered gas costs - - 41.7 60.3
Regulatory effects of accounting for income taxes, net 23.4 - 25.5 26.2
Other 5.2 - - -
---------------------------------------------------------------------------------------------------
Total regulatory liabilities 64.6 - 127.3 166.6
===================================================================================================
D. 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
companies includes an allowance for funds used during construction
(AFUDC). Property, plant and equipment of other subsidiaries includes
interest during construction (IDC). The 1995, 1994 and 1993
before-tax rates for AFUDC and IDC were 8.0 percent and 9.6 percent,
respectively.
49
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
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 2.6 percent in 1995, 2.7 percent in 1994
and 2.6 percent in 1993. The average annual depreciation rate for the
distribution subsidiaries' property was 3.3 percent in 1995, 1994 and
1993.
E. OIL AND GAS PRODUCING PROPERTIES. Columbia's subsidiaries engaged in
exploring for and developing oil and gas 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 in a countrywide cost center. If
costs exceed the sum of the estimated present value of the cost
center's net future oil and gas 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 oil and gas properties are normally
recorded as adjustments to capitalized costs, except in the case of a
sale of a significant amount of properties, which could be reflected
in the income statement.
Depletion for subsidiaries is based upon the ratio of current-year
revenues to expected total revenues, utilizing current prices, over
the life of production.
On October 23, 1995 Columbia announced its intent to sell Columbia Gas
Development Corporation, (Columbia Development) the southwest
exploration and production company (see Note 13B).
F. COMMODITY HEDGING. Premiums paid for option and swap agreements are
included as current assets in the consolidated balance sheet until
they are exercised or expire. Margin requirements for natural gas,
crude oil and propane futures are also recorded as current assets.
Unrealized gains and losses on all futures contracts 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 and crude oil futures, options and swaps are included in
revenues or products purchased as appropriate. Realized gains and
losses from the settlement of propane futures contracts are included
in products purchased.
G. GAS INVENTORY. The distribution companies gas inventory is carried at
cost on a last-in, first-out (LIFO) basis. The excess of replacement
cost of gas inventory at December 31, 1995, over the carrying value is
approximately $89 million. Liquidation of LIFO layers related to gas
delivered by the distribution companies does not affect income since
the effect is passed through to customers as part of purchased gas
adjustment tariffs.
H. 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.
I. 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.
J. 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.
50
51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
K. 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.
L. 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 future recovery of
environmental remediation costs is expected through the regulatory
process.
M. 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.
N. STOCK OPTIONS AND AWARDS. 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.
For stock appreciation rights, compensation expense is recognized on
the aggregate difference between the market price of Columbia's stock
and the option price. Compensation expense related to contingent
stock awards is recognized over the vesting period. Columbia sets
the grant price of the options at one cent below the market price of
the stock on the grant date. In accordance with Accounting Principles
Board Opinion No. 25 expense 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 minimus, no compensation
expense is recognized.
2. EMERGENCE FROM CHAPTER 11 OF THE BANKRUPTCY CODE
A. GENERAL. On November 28, 1995, both Columbia and Columbia
Transmission emerged from Bankruptcy Court protection under Chapter 11
of the Federal Bankruptcy Code. While under Chapter 11 protection,
actions by creditors to collect prepetition indebtedness were stayed
and other contractual obligations could not be enforced against either
Columbia or Columbia Transmission. Both Columbia and Columbia
Transmission had the right, subject to Bankruptcy Court approval and
certain other limitations, to assume or reject executory contracts and
unexpired leases. Any claims for damages resulting from rejection
were treated as general unsecured claims in the reorganization. The
parties affected by these rejections had the right to file claims with
the Bankruptcy Court in accordance with bankruptcy procedures.
Prepetition claims which were contingent or unliquidated at the
commencement of the Chapter 11 proceeding were generally allowable
against the debtor companies in amounts fixed by the Bankruptcy Court.
Substantially all liabilities as of the petition date were subject to
resolution under plans of reorganization approved by the Bankruptcy
Court. Columbia's reorganization plan was also approved by the
Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935.
B. SETTLEMENT OF PREPETITION OBLIGATIONS. 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. Columbia's approved plan of reorganization (Plan)
provided for payment to its creditors of the full amount of their
principal balances and accrued prepetition and postpetition interest
and interest on overdue interest through distribution of:
- $2 billion in new debt securities, with maturities ranging
from 5 to 30 years;
- $1 billion in cash, funded by cash on hand and new bank debt;
and
- $200 million in Redeemable Preferred Stock, Series A and $200
million in Convertible Preferred Stock, Series B.
The interest rates on the new debt securities and the dividend rates
and other financial terms of the new equity securities were based on
market levels at the time of emergence. Columbia's new long-term debt
obligations were rated as investment grade by three major rating
agencies.
51
52
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Columbia Transmission's Plan is guaranteed financially by Columbia,
and provided a total distribution of approximately $3.9 billion to its
creditors, including:
- 100% of all priority and administrative claims, which together
amounted to $255 million;
- 100% of Columbia's secured claim of approximately $2 billion,
including interest, which was funded with approximately $900
million secured debt securities of reorganized Columbia
Transmission and all of its equity;
- 100% of all unsecured claims of $25,000 or less, which
amounted to $8 million;
- 72.5% of all miscellaneous unsecured creditor claims in excess
of $25,000, which amounted to $40 million;
- Approximately $130 million in customer refunds as provided
under terms of a Customer Settlement Agreement;
- 68.875% to 72.5% of the $351 million unsecured claim of
Columbia, that will be ultimately determined by the final
distribution percentage received by unsecured producers; and
- $1.2 billion to producers (based on a 100% acceptance of the
claim amounts proposed in the Plan). Columbia Transmission's
Plan provided a total proposed allowed amount of producer
claims of $1.6 billion and for distributions of 72.5% to those
creditors who had claims under those contracts in excess of
$25,000.
Columbia Transmission's Plan provides that producers who rejected
settlement offers contained in Columbia Transmission's Plan may
continue to litigate their claims under the Bankruptcy Court-approved
estimation procedure, described below, and will receive the same
percentage payout on their claims, when and if ultimately allowed, as
received by the settling producers. Columbia Transmission's Plan
further provided that the actual distribution percentage for producer
claims, which would not be less than 68.875% or greater than 72.5%,
would not be determined until the total amount of contested producer
claims is established, and that until such time, 5% of the amount to
be distributed to producer claimants and Columbia for unsecured debt
will be withheld.
The 5% holdback from settling producers and a matching contribution by
reorganized Columbia Transmission, to the extent necessary, will be
used to fund any distributions on producer claims ultimately
liquidated in an aggregate amount in excess of those proposed by
Columbia Transmission's Plan. If the holdback and matching
contributions are exhausted, any further distribution would be funded
entirely by Columbia Transmission. Columbia has guaranteed the payment
of the remaining distributions to producers, either in cash or, to the
extent that a nonsettling producer's finally allowed claim exceeds its
proposed settlement value, in Columbia's common stock.
PRODUCER CLAIMS ESTIMATION PROCESS
In 1992, the Bankruptcy Court approved the appointment of a Claims
Mediator and the implementation of a claims estimation procedure for
the quantification of claims arising from the rejection of
above-market gas purchase contracts and other claims by producers
related to gas purchase contracts with Columbia Transmission. In late
1994 and early 1995, the Claims Mediator issued the Initial Report and
Recommendations of the Claims Mediator on generic issues for Natural
Gas Contract Claims and a Supplement to Initial Report and
Recommendations of the Claims Mediator (Report) and directed producer
claimants to submit to him recalculated claims prepared pursuant to
the instructions contained in the Report. The recommendations and
instructions set out in the Report have not been considered by the
Bankruptcy Court. In mid-1995, producers with which Columbia
Transmission had not yet negotiated settlements liquidating their
claims submitted recalculated claims to the Claims Mediator. As
submitted, those recalculated claims initially amounted to over $2
billion. Since mid-1995, numerous additional producers settled their
claims and those settlements became final with the confirmation of
Columbia Transmission's Plan. In addition, several recalculated
claims have been amended by producer claimants.
The estimation procedures remain in place under the Plan for use in
the post-confirmation liquidation of producer claims that were not
resolved with the confirmation of the Plan. As of early 1996, the
recalculated claims still subject to the estimation process total
about $490 million, as submitted and amended. The estimation process
is now proceeding with discovery, motions for dismissal or summary
judgement and evidentiary hearings before the Claims Mediator to
address individual producer claims, including specific issues not
addressed by the Report. The recommendations of the Claims Mediator
concerning the amounts at which particular claims should be allowed,
as issued, are being submitted to the Bankruptcy Court for
52
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
consideration. The parties have rights of appellate review with
respect to the resulting orders of the Bankruptcy Court. When claims
are allowed by the Bankruptcy Court and the allowances become final,
Columbia Transmission will make additional distributions pursuant to
the Plan. The timing of the completion of this litigation process is
impossible to predict.
Based on the information received and evaluated to date, Columbia
Transmission believes that most of the remaining claims will be
settled at amounts approximating the settlement values, but expects
that some claims may be settled or resolved through litigation at
amounts higher or lower than the proposed settlement values. Although
Columbia Transmission does not have sufficient information to fully
evaluate all claims and the outcome of litigation is subject to
uncertainty, it currently estimates that the ultimate payment to
producers, after litigation and after giving effect to the producer
holdback, is likely to exceed the $1.2 billion distribution projected
in the Plan (which is based on 100% producer acceptance) but is
unlikely to exceed $1.3 billion. The foregoing estimation is based on
the information currently available, and there can be no assurance as
to the timing or amounts of settlements with producers or as to the
amount ultimately allowed or paid with respect to the remaining
claims.
INTERCOMPANY COMPLAINT
Columbia Transmission's Plan provided for the withdrawal of a
complaint filed by the Official Committee of Unsecured Creditors of
Columbia Transmission with the Bankruptcy Court. The complaint
alleged, among other items, that the $1.7 billion of Columbia
Transmission's secured and unsecured debt securities held by Columbia
should be recharacterized as capital contributions (rather than loans)
and equitably subordinated to the claims of Columbia Transmission's
other creditors.
INTERNAL REVENUE SERVICE MATTERS
Columbia received a favorable ruling from the Internal Revenue Service
(IRS) in October 1995, stating that payments made by Columbia
Transmission pursuant to its Plan, to producers in connection with
their contract rejection claims were deductible for tax purposes in
the year in which the payments were made. Because of the magnitude of
the payments, obtaining a favorable ruling from the IRS was a
condition of both Plans.
SECURITY HOLDER AND DERIVATIVE LITIGATION
On July 18, 1995, Columbia reached a settlement that resolved a
consolidated class action complaint filed in the District Court in
1991 against Columbia and its directors and certain officers of the
debtor companies. Under the terms of the settlement Columbia paid
approximately $16.5 million of the total $36.5 million settlement.
The remainder was shared among the insurance carrier for the director
and officer defendants and the other defendants to the litigation.
The settlement was implemented upon Columbia's emergence from Chapter
11.
Also in 1991, three derivative actions were filed in the Court of
Chancery in and for New Castle County (Delaware) alleging that
directors had breached their fiduciary duties to Columbia. Consistent
with the recommendation of a special committee of Columbia's Board of
Directors, the derivative litigation was released and dismissed
pursuant to Columbia's Plan.
REORGANIZATION ITEMS
During 1995, 1994 and 1993 Columbia and Columbia Transmission have
earned interest income on cash accumulated from the suspension of
payments related to prepetition liabilities and incurred expenses
associated with professional fees and other related services.
Included in 1995 is approximately $47.7 million of expense for items
related to emergence from bankruptcy and 1994 reflected additional
expense of $40 million for adjustments to reserves for producer claim
levels based on the Claims Mediator's Report.
($ in millions) 1995 1994 1993
-------------------------------------------------------------------------------------------------------
Interest income on accumulated cash 93.5 63.4 39.9
Professional fees and related expenses (28.2) (35.4) (29.9)
Other reorganization items, net (51.9) (40.3) (1.1)
-------------------------------------------------------------------------------------------------------
REORGANIZATION ITEMS, NET 13.4 (12.3) 8.9
-------------------------------------------------------------------------------------------------------
53
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
3. REGULATORY MATTERS
A. On June 15, 1995, the FERC issued an order approving a settlement
(Customer Settlement) between Columbia Transmission, Columbia Gulf,
their firm customers, state regulatory agencies, customer
representatives, and other parties. The Customer Settlement was
incorporated in Columbia Transmission's approved reorganization plan
(Plan) and resolves virtually all of the transmission segment's
outstanding regulatory proceedings before the FERC. Generally, the
Customer Settlement defined Columbia Transmission's and Columbia
Gulf's refund obligations to their customers in certain pending
regulatory proceedings, and established Columbia Transmission's
ability to recover certain costs associated with the restructuring of
its services under FERC Order No. 636 (Order 636).
The Customer Settlement was implemented on November 28, 1995,
following approval of Columbia Transmission's Plan by the Bankruptcy
Court. The Customer Settlement provided for payment to Columbia
Transmission's customers of an estimated $170 million in refunds and
recovery of $250 million in costs from Columbia Transmission's
customers.
B. Columbia Transmission owns and operates natural gas gathering and
processing facilities in various production areas. In its orders
addressing the company's restructuring proposals under Order 636, the
FERC allowed Columbia Transmission to maintain its existing rate
structure and recover costs associated with these facilities until it
filed its next general rate case with the FERC which occurred in
August 1995. Columbia Transmission proposed in its August 1995 FERC
rate filing to recover over a five year period its net investment in
gathering facilities and substantially all of its net investment in
gas processing facilities that were "stranded" as a result of the
implementation of Order 636. The total level of such stranded
facilities amounted to approximately $60 million.
C. In its September 1993 order on Columbia Transmission's and Columbia
Gulf's 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 the FERC's abandonment authorization to reduce capacity
on its mainline facilities. In a response to the FERC in late 1993,
Columbia Gulf asserted that no abandonment filing was required.
During 1994 and early 1995, Columbia Transmission and Columbia Gulf
responded to information requests from the FERC's staff. Management
continues to believe that an abandonment filing was not necessary;
however, the ultimate outcome of this issue is uncertain at this time.
D. In early 1995, Columbia Transmission made its annual filing to recover
costs it continues to incur under transportation contracts with
upstream pipelines. The filing provided for recovery of costs
Columbia Transmission projected it would incur under contracts it
continues to utilize in system operations, costs associated with
contracts for which exit fees had not yet been implemented, and
continued amortization of exit fees paid to an upstream pipeline. In
addition, the filing proposed to implement a surcharge to recover an
undercollection of transportation costs incurred during 1994. This
underrecovery related, in part, to amounts paid by Columbia
Transmission to Columbia Gulf under the provisions of the
cost-of-service contract between the two companies prior to October
31, 1994, the date on which the agreement was terminated. Under the
Customer Settlement, customers and others retain the right to
challenge Columbia Transmission's recovery of approximately $39
million of Columbia Gulf costs it incurred between November 1, 1993
and October 31, 1994. Various parties protested Columbia
Transmission's filing, and challenged among other things Columbia
Transmission's ability to recover costs attributable to Columbia Gulf.
A technical conference among the parties was held at the FERC and
written comments were filed with the FERC by Columbia Transmission,
Columbia Gulf and intervenors in support of their position.
4. COMMODITY HEDGING ACTIVITIES
Subsidiaries in Columbia's oil and gas and other energy operations engage
in commodity hedging activities to minimize the risk of market fluctuations
associated with the price of crude oil and natural gas production, propane
inventories and commitments for natural gas purchases and sales. The
hedging objectives include assurance of stable and known minimum cash
flows, fixing favorable prices and margins when they become available and
participation in any long-term increases in value. Under internal
guidelines, speculative positions are prohibited.
54
55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Columbia's oil and gas production companies utilize futures, options and
swaps on futures as well as commodity price swaps and basis swaps. Futures
help manage commodity price risk by fixing prices for future production
volumes. 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. At December 31,
1995 there were a total of 285 open contracts representing a notional
quantity amounting to 2.9 Bcf of natural gas production through March of
1996. A total of $0.5 million of unrealized losses have been deferred on
the consolidated balance sheet with respect to these open contracts. At
December 31, 1994 there were a total of 1,700 open contracts representing a
notional quantity amounting to 17.0 Bcf of natural gas production through
September of 1995. A total of $0.5 million in option premium costs as well
as $1.7 million of unrealized gains were deferred on the consolidated
balance sheet with respect to these open contracts at December 31, 1994.
During the years ended December 31, 1995 and 1994, a total of $6.8 million
and $3.6 million, respectively, were recognized in operating income as
realized gains on the settlement of crude oil and natural gas option and
swap contracts.
Columbia's gas marketing and propane operations utilize futures contracts
and basis swaps to assure adequate margins on the purchase and resale of
natural gas as well as protecting the value and margins of its propane
inventories. At December 31, 1995 there were a total of 482 open contracts
through January 1997, representing a notional quantity amounting to 4.8 Bcf
of natural gas. At December 31, 1994 there were a total 773 open contracts
through December 1995, representing a notional quantity amounting to 7.8
Bcf of natural gas. A total of $0.8 million and $3.1 million of unrealized
losses have been deferred on the consolidated balance sheet with respect to
these open contracts at December 31, 1995 and December 31, 1994,
respectively. These unrealized losses are offset by gains which take place
when the products are sold.
During the years ended December 31, 1995 and 1994, respectively, a total of
$4.9 million and $2.7 million of losses were recognized in operating income
on the settlement of natural gas futures and basis swaps. Gains and losses
on propane and gas marketing hedging activities were offset by amounts
realized from the sale of the underlying products.
Columbia and its subsidiaries are exposed to credit losses in the event of
nonperformance by the counterparties to its various hedging contracts.
Management has evaluated such risk and believes that overall business risk
is minimized as a result of these hedging contracts which are primarily
with major investment grade financial institutions.
5. ACCOUNTING STANDARDS
A. As a result of emergence from bankruptcy and significant industry
changes culminating with Order 636, the operating experience gained
since implementation of Order 636, a new Columbia Transmission rate
case that was filed on August 1, 1995, and the resolution of gas
contract difficulties and various customer issues, Columbia
Transmission and Columbia Gulf reapplied SFAS No. 71 upon Columbia
Transmission's emergence from bankruptcy. Management believes that
cost of service rate concepts will continue to be applicable to
Columbia's FERC-regulated transmission subsidiaries for the
foreseeable future. The reapplication of SFAS No. 71 results in the
recognition of regulatory assets for certain costs previously
expensed, which are expected to be recovered in rates, mainly
environmental and postemployment benefit costs, and recording revenues
and expenses in a manner to reflect the ratemaking process. As a
result of reapplying SFAS No.71, an extraordinary gain of $71.6
million was recorded in 1995.
B. Effective January 1, 1994, Columbia adopted the Financial Accounting
Standards Board's Statement of Financial Accounting Standards No. 112,
"Employers' Accounting for Postemployment Benefits." This statement
requires employers to recognize obligations to provide benefits to
former or inactive employees after employment, but before retirement.
Such benefits include, but are not limited to, salary continuation,
supplemental unemployment, severance, disability, job training,
counseling, and continuation of benefits such as health care and life
insurance coverage.
55
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The adoption of this statement resulted in an accrual of $14.4 million
of which $5.6 million was deferred by certain of the distribution
subsidiaries as a regulatory asset pending rate recovery authorization
from their respective state commissions. The after-tax effect of the
remainder reduced net income by $5.6 million.
C. In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of" (SFAS No. 121). This statement establishes accounting
standards for the impairment of long-lived assets, certain
identifiable intangibles, and goodwill related to those assets to be
held and used and for long-lived assets and certain identifiable
intangibles to be disposed of. SFAS No. 121 requires these assets be
reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. This statement will be effective for fiscal years
beginning after December 15, 1995, and Columbia plans to adopt the
statement on January 1, 1996. Based on the facts and circumstances
known today, Columbia does not expect the adoption of SFAS No. 121 to
have a material impact on its financial statements.
D. In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation" (SFAS No. 123). This statement establishes
a fair value based method of accounting for stock based compensation
plans. Under the fair value based method, compensation cost is
measured at the grant date based on the value of the award and is
recognized over the service period, which is usually the vesting
period. SFAS No. 123 encourages entities to adopt that method in
place of the provisions of Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB Opinion No. 25)
for all arrangements under which employees receive shares of stock or
other equity instruments of the employer or the employer incurs
liabilities to employees in amounts based on the price of the stock.
Entities that continue to apply APB Opinion No. 25 must comply with
the disclosure requirements of SFAS No. 123, including the pro forma
effects on earnings. The statement's disclosure requirements will be
effective for fiscal years beginning after December 15, 1995.
Columbia expects to continue to apply APB Opinion No. 25.
6. INCOME TAXES
The components of income tax expense are as follows:
Year Ended December 31 ($ in millions) 1995 1994 1993
------------------------------------------------------------------------------------------------------
INCOME TAXES
Current
Federal (284.8) 63.8 107.2
State 8.1 10.0 9.6
------------------------------------------------------------------------------------------------------
Total Current (276.7) 73.8 116.8
------------------------------------------------------------------------------------------------------
Deferred
Federal 69.7 78.9 17.6
State (2.2) (5.3) 2.3
------------------------------------------------------------------------------------------------------
Total Deferred 67.5 73.6 19.9
------------------------------------------------------------------------------------------------------
Deferred Investment Credits (1.5) (1.4) (0.8)
------------------------------------------------------------------------------------------------------
Income taxes included in income before extraordinary item and
cumulative effect of accounting change (210.7) 146.0 135.9
Deferred taxes related to extraordinary item and cumulative
effect of accounting change 36.9 (3.3) -
------------------------------------------------------------------------------------------------------
TOTAL INCOME TAXES (173.8) 142.7 135.9
------------------------------------------------------------------------------------------------------
56
57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Total income taxes are different than the amount which 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) 1995 1994 1993
-------------------------------------------------------------------------------------------------------
Book income (loss) before income taxes,
extraordinary item and cumulative effect (643.0) 392.2 288.1
of accounting change
Tax expense (benefit) at statutory Federal
income tax rate (225.0) 35.0% 137.3 35.0% 100.8 35.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal
income tax benefit 4.7 (0.7) 2.6 0.6 7.6 2.7
Estimated non-deductible expenses 9.0 (1.4) 6.4 1.6 8.1 2.8
Effect of change in tax rates on deferred taxes
previously provided - - - - 8.7 3.0
Adjustment to prior years' tax provision due to
pending settlement - - - - 9.2 3.2
Other 0.6 (0.1) (0.3) - 1.5 0.5
-------------------------------------------------------------------------------------------------------
INCOME TAXES BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (210.7) 32.8% 146.0 37.2% 135.9 47.2%
-------------------------------------------------------------------------------------------------------
57
58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Deferred tax balances are as follows:
At December 31 ($ in millions) 1995 1994
---------------------------------------------------------------------------------------
Net current liabilities (assets)
Federal (30.9) (23.8)
State (6.2) (3.7)
---------------------------------------------------------------------------------------
Total (37.1) (27.5)
---------------------------------------------------------------------------------------
Net noncurrent liabilities
Federal 401.6 280.6
State 67.0 63.5
---------------------------------------------------------------------------------------
Total 468.6 344.1
---------------------------------------------------------------------------------------
TOTAL DEFERRED INCOME TAXES 431.5 316.6
---------------------------------------------------------------------------------------
Deferred income taxes result from temporary differences between the
financial statement carrying amounts and the tax basis of existing
assets and liabilities. The source of these differences and tax
effect of each is as follows:
At December 31 ($ in millions) 1995 1994
---------------------------------------------------------------------------------------
Property basis differences 610.5 627.8
Accrued interest on debt - 230.5
Gas purchase costs 15.1 (7.9)
Transportation costs 2.0 20.8
Partnership deferrals 26.0 27.0
Deferred revenue (0.9) 11.4
Estimated supplier obligations (59.6) (345.3)
Estimated rate refunds (13.1) (69.9)
Postretirement benefits (17.0) (49.4)
Environmental liabilities (17.2) (49.6)
Capitalized inventory overheads (25.5) (41.5)
Unbilled utility revenue (12.5) (11.1)
Net operating loss carryforward (19.9) -
Alternative minimum tax (91.0) -
Debt forgiveness 50.7 -
Other (16.1) (26.2)
---------------------------------------------------------------------------------------
TOTAL DEFERRED INCOME TAXES 431.5 316.6
---------------------------------------------------------------------------------------
58
59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
7. PENSION AND OTHER POSTRETIREMENT BENEFITS
A. PENSION PLANS. Columbia has a noncontributory, qualified defined
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.
Columbia also has a nonqualified pension plan that provides benefits to
some employees in excess of the qualified plan's Federal tax limits.
The following table shows the components of net pension expense for the
qualified and nonqualified plans and the annual contributions for each of
the three years ended December 31:
PENSION COSTS ($ in millions) 1995 1994 1993
------------------------------------------------------------------------------------------------------------------------
Service cost 26.7 34.2 31.7
Interest cost 69.9 68.8 68.8
Actual return on assets (202.5) (11.3) (126.9)
Net amortization (deferral) 124.8 (66.1) 56.5
------------------------------------------------------------------------------------------------------------------------
NET PENSION EXPENSE 18.9 25.6 30.1
------------------------------------------------------------------------------------------------------------------------
CONTRIBUTION 1.2 7.0 18.0
------------------------------------------------------------------------------------------------------------------------
The following table provides a reconciliation of the plans' funded status
and amounts reflected in Columbia's balance sheet at December 31:
PLAN ASSETS AND OBLIGATIONS ($ in millions) 1995 1994
------------------------------------------------------------------------------------------------------------------------
Plan assets at fair value 1,034.6 893.6
------------------------------------------------------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Vested benefits 760.2 628.5
Nonvested benefits 56.1 45.8
------------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation 816.3 674.3
Effect of projected future salary increases 190.8 153.5
------------------------------------------------------------------------------------------------------------------------
PROJECTED BENEFIT OBLIGATION 1,007.1 827.8
------------------------------------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 27.5 65.8
Unrecognized net gain (131.8) (158.2)
Unrecognized prior service cost 56.5 60.7
Unrecognized transition obligation 8.1 9.3
------------------------------------------------------------------------------------------------------------------------
ACCRUED PENSION COST (39.7) (22.4)
------------------------------------------------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION 7.0% 8.5%
------------------------------------------------------------------------------------------------------------------------
COMPENSATION GROWTH RATE ASSUMPTION 5.0% 5.5%
------------------------------------------------------------------------------------------------------------------------
ASSET EARNINGS RATE ASSUMPTION 9.0% 9.0%
------------------------------------------------------------------------------------------------------------------------
Plan assets consist of primarily equity (international and domestic) and
fixed income securities.
As of December 31, 1995, the discount rate assumption and the average
compensation growth rate were revised downward to 7.0% and 5.0%
respectively. The net effect of these changes was to increase the
accumulated benefit obligation and the projected benefit obligation by
$121.4 million and $158.5 million, respectively.
B. OTHER POSTRETIREMENT BENEFITS. Columbia also provides medical coverage
and life insurance to retirees. Essentially all active employees are
eligible for these benefits upon retirement after completing ten
consecutive years of service after age 45. Normally, spouses and
dependents of retirees are also eligible for medical benefits.
59
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The following table shows components of other postretirement costs for each
of the three years ended December 31:
OTHER POSTRETIREMENT COSTS ($ in millions) 1995 1994 1993
--------------------------------------------------------------------------------------------------------------------------
Service cost 11.3 15.3 16.2
Interest cost 24.1 24.6 25.9
Actual return on assets (30.0) (2.1) (12.6)
Other, net amortization (deferral) 16.0 (4.9) 7.8
--------------------------------------------------------------------------------------------------------------------------
OTHER POSTRETIREMENT COSTS 21.4 32.9 37.3
--------------------------------------------------------------------------------------------------------------------------
CONTRIBUTIONS 41.8 20.7 16.9
--------------------------------------------------------------------------------------------------------------------------
The following table provides a reconciliation of other postretirement
plans' funded status and amounts reflected on Columbia's balance sheet at
December 31:
PLAN ASSETS AND OBLIGATIONS ($ in millions) 1995 1994
--------------------------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retiree 172.1 168.2
Fully eligible active plan participants 60.5 73.9
Other participants 83.2 61.9
--------------------------------------------------------------------------------------------------------------------------
Total 315.8 304.0
Plan assets at fair value (149.1) (91.2)
Unrecognized actuarial net gain 72.8 52.1
--------------------------------------------------------------------------------------------------------------------------
ACCRUED POSTRETIREMENT BENEFIT COST 239.5 264.9
--------------------------------------------------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION 7.0% 8.5%
--------------------------------------------------------------------------------------------------------------------------
MEDICAL COST TREND 8.0-5.5% 9.0-6.0%
--------------------------------------------------------------------------------------------------------------------------
COMPENSATION GROWTH RATE ASSUMPTION 5.0% 5.5%
--------------------------------------------------------------------------------------------------------------------------
ASSET EARNINGS RATE ASSUMPTION* 9.0% 9.0%
--------------------------------------------------------------------------------------------------------------------------
*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%.
Plan assets consist of shares in various equity (international and
domestic) and fixed income mutual funds and represent assets held in three
trust accounts and one 401(h) account used to fund the plans.
As of December 31, 1995, the discount rate assumption was revised downward
to 7.0% from 8.5% and the compensation growth rate was revised downward to
5.0% from 5.5%. The medical accumulated postretirement benefit obligation
(APBO) at December 31, 1995 and 1994 also reflects medical inflation trend
rates, starting at 8% and 9.0% and decreasing to 5.5% and 6.0% after six
years. The net effect of these changes was a $33.4 million increase in the
accumulated postretirement benefit obligation. A one percent increase in
medical inflation trend rates for each future year would have increased the
APBO by another $16.6 million and other postretirement costs by $2.8
million in 1995.
All of Columbia's subsidiaries participate in funding for retiree life
insurance benefits, using a voluntary employee beneficiary association
(VEBA) trust. Columbia's funding policy is to make annual contributions to
this trust, subject to the maximum tax-deductible limit. Contributions of
approximately $3.8 million, and $3.8 million were made to the retiree life
insurance VEBA trust in 1995 and 1994, respectively.
8. LONG-TERM INCENTIVE PLAN
The Columbia Long-Term Incentive Plan (Plan), 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 Plan'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.
60
61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Transactions for the three years ended December 31, 1995, are as follows:
Options
---------------------------
Without Stock With Stock Option
Appreciation Appreciation Price
Rights Rights Range
----------------------------------------------------------------------------------------------------------------------------
Outstanding 12/31/92 529,350 163,650 $34.30-$46.68
----------------------------------------------------------------------------------------------------------------------------
1993
Granted - - -
Exercised - - -
Cancelled (23,730) (7,500) $34.30-$46.68
Converted - - -
Outstanding 12/31/93 505,620 156,150 $34.30-$46.68
----------------------------------------------------------------------------------------------------------------------------
1994
Granted - - -
Exercised - - -
Cancelled (20,655) - $34.30-$46.68
Converted - - -
Outstanding 12/31/94 484,965 156,150 $34.30-$46.68
----------------------------------------------------------------------------------------------------------------------------
1995
Granted 93,000 - $28.99-$31.05
Exercised (33,245) (6,100) $28.99-$38.30
Cancelled (20,400) - $34.30-$46.68
Converted - - -
----------------------------------------------------------------------------------------------------------------------------
OUTSTANDING (ALL EXERCISABLE) 12/31/95 524,320 150,050 $28.99-$46.68
----------------------------------------------------------------------------------------------------------------------------
In addition to the options, contingent stock awards totaling 27,500 shares
were issued to two key executives in 1995. As of December 31, 1995, 17,500
of these shares have vested and been issued and 10,000 shares remain
outstanding.
During 1995, $1.1 million was expensed for the Long-Term Incentive Plan.
There were de minimus amounts expensed for the Long-Term Incentive Plan in
1994 and 1993.
The Board of Directors has approved the adoption of a new Long-Term
Incentive Plan (New Plan) subject to shareholder approval at the April 26,
1996 annual meeting of Columbia's shareholders. The New Plan, to be
effective for ten years, beginning February 21, 1996, provides for the
granting of nonqualified stock options, stock appreciation rights,
contingent stock awards and restricted stock awards to officers, key
employees and outside directors. A total of 3,000,000 shares of Columbia's
authorized common stock will be made available under the New Plan's
provisions.
The Board of Directors has also approved an incentive compensation plan for
outside directors, also subject to shareholder approval at the April 26,
1996 annual meeting, 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.
61
62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
9. PREFERRED STOCK
As of December 31, 1995, Columbia has authorized 40,000,000 shares of
preferred stock, par value $10 per share, and had outstanding 7,999,494
shares of 7.89% Redeemable Preferred Stock, Series A (Series A - Preferred
Stock) and 4,898,946 shares of 5.22% Convertible Preferred Stock, Series B
(Series B - DECS).
In early February 1996, Columbia gave an irrevocable notice to holders of
Series A - Preferred Stock and Series B - DECS that all outstanding shares
of preferred stock would be redeemed for cash on February 26, 1996. Series
A - Preferred Stock will be redeemed at $25 per share for an aggregate
amount of $199,987,350 (7,999,494 shares outstanding). Series B - DECS
will be redeemed at $40.82 per share for an aggregate amount of
$199,974,975 (4,898,946 shares outstanding). Holders of Series A -
Preferred Stock and Series B - DECS will not be entitled to receive
dividends in connection with the redemption.
The Series A - Preferred Stock was issued at $25 per share and has an
aggregate liquidation value of $199,987,350. Series A - Preferred Stock is
redeemable by Columbia, in whole or in part, at any time on or prior to
March 27, 1996 and on or after November 28, 2000, payable in cash at a rate
of $25 per share, plus unpaid accumulated dividends, if any. Series A -
Preferred Stock is not subject to mandatory redemption by Columbia and is
not convertible into or exchangeable for any other securities.
The Series B - DECS was issued at $40.82 per share with an aggregate
liquidation value of $199,974,975. Each share of Series B - DECS
mandatorily converts into shares of common stock on the mandatory
conversion date of November 28, 2000, including an amount in cash equal to
unpaid accumulated dividends, if any. Columbia has the option to redeem
Series B - DECS on or prior to March 27, 1996, payable in cash, at $40.82
per share (plus accrued dividends of $0.5325 per share if redeemed after
February 26, 1996 but before March 27, 1996). Columbia also has the option
to redeem Series B - DECS on or after the regular redemption date of
November 28, 1999 and prior to November 28, 2000, payable in shares of
common stock plus any accrued dividends. Each share of Series B - DECS is
convertible at the option of the holder after March 27, 1996 and before
November 28, 1999 into common stock.
Dividends for preferred stock outstanding are cumulative and are payable
quarterly at an annual rate of $1.97 per share for Series A - Preferred
Stock and $2.13 per share for Series B - DECS. Holders of preferred stock
have no voting rights. However, if dividends are in arrears and unpaid for
six quarterly dividend periods, the holders of preferred stock, voting as a
separate class, will be entitled to vote for the election of two directors
of Columbia. (Such directors to be in addition to the existing Board of
Directors). Preferred stock ranks prior to common stock both as to payment
of dividends and distribution of assets upon liquidation. As a result of
the February 1996 notice, no dividends on preferred stock have been
accrued.
62
63
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
10. LONG-TERM DEBT
The long-term debt (exclusive of current maturities) of Columbia and its
subsidiaries is as follows:
At December 31 ($ in millions) 1995 1994
------------------------------------------------------------------------------------------------------------------
The Columbia Gas System, Inc.
Debentures
6.39% Series A due November 28, 2000 311.0 -
6.61% Series B due November 28, 2002 281.5 -
6.80% Series C due November 28, 2005 281.5 -
7.05% Series D due November 28, 2007 281.5 -
7.32% Series E due November 28, 2010 281.5 -
7.42% Series F due November 28, 2015 281.5 -
7.62% Series G due November 28, 2025 281.5 -
------------------------------------------------------------------------------------------------------------------
Total Debentures 2,000.0 -
Subsidiary Debt:
Capitalized lease obligations 2.9 2.5
Other 1.6 1.8
------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 2,004.5 4.3
------------------------------------------------------------------------------------------------------------------
The aggregate maturities of long-term debt and capitalized lease
obligations during the next five years are as follows:
($ in millions)
------------------------------------------------------------------------------------------------------------------
1996 0.5
1997 0.4
1998 0.4
1999 0.5
2000 311.3
------------------------------------------------------------------------------------------------------------------
11. SHORT-TERM DEBT AND CREDIT FACILITIES
Effective November 1995, Columbia entered into an unsecured Revolving
Credit Agreement (Credit Facility). The Credit Facility consists of a five
year revolving credit agreement maturing November 2000. The Credit
Facility has an initial commitment amount of $1 billion with scheduled
quarterly commitment reductions of $25 million beginning on December 31,
1997. Interest rates on borrowing are based upon the London Interbank
Offered Rate, Certificate of Deposit rates or other short-term interest
rates. Compensating balances are not required. Columbia is required to
pay a facility fee on the commitment amount at a rate which is based on
Columbia's public debt rating. The facility fee rate as of December 31,
1995 is 0.14%. The Credit Facility contains certain covenants that must be
met to borrow funds including; restrictions on the incurrence of liens, a
maximum leverage ratio, and a minimum consolidated net worth. Columbia had
outstanding $338.9 million under the Credit Facility at December 31, 1995
at an average rate of 6.46%. The maximum amount outstanding during the
year occurred on November 28, 1995 in the amount of $370 million at an
interest rate of 8.75%.
The Credit Facility provides for the issuance of up to $100 million of
standby letters of credit. As of December 31, 1995, Columbia had $58.8
million of letters of credit outstanding under the Credit Facility. Fees
for letters of credit issued are calculated at rates that are based on
Columbia's public debt rating plus a commission of
63
64
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
0.125% to the issuing bank. At December 31, 1995, fees for letters of
credit issued in connection with certain financial obligations were at a
rate of 0.2775%.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
Statement of Financial Accounting Standards No. 107, "Disclosures about
Fair Value of Financial Instruments" extends existing fair value disclosure
practices by requiring 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.
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:
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. The
estimated fair values of Columbia's other financial instruments are
reflected in the accompanying table.
Long-term investments
Long-term investments include an income tax refund receivable with
associated interest ($80.1 million and $30.3 million for 1995 and 1994,
respectively) whose carrying amount approximates fair value. Also included
are loans receivable ($3.9 million for 1995 and $4.0 million for 1994)
whose estimated fair values are based on the present value of estimated
future cash flows using an estimated rate for similar loans extended
currently. The financial instruments included in long-term investments are
primarily reflected in Investments and Other Assets in the consolidated
balance sheets.
Long-term Debt
The estimated fair value of Columbia's debentures, including accrued
interest, is based on estimates provided by brokers.
Liabilities subject to Chapter 11 proceedings
At December 31, 1994, the estimated fair value of Columbia's debentures and
medium-term notes was based on quoted market prices for those issues traded
on an exchange, and estimates provided by brokers for other issues. The
quoted market prices and broker estimates inherently included judgments
concerning the ultimate outcome of Columbia's and Columbia Transmission's
Chapter 11 proceedings.
It was not practicable to estimate fair value of the remaining long-term
debt that included the Subordinated Guarantee of the Leveraged Employee
Stock Ownership Plan debt ($87 million) and miscellaneous debt of Columbia
Transmission ($1.4 million), because no reliable measurement methodology
existed. It was also not practicable to determine the fair value for the
bank loans and commercial paper and the other liabilities subject to the
Chapter 11 proceedings since these items were subject to determination or
adjustment by the Bankruptcy Court and there was no assurance as to the
amount or the timing of the ultimate payments of these obligations.
64
65
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
1995 1994
---------------- -----------------
Carrying Fair Carrying Fair
At December 31 ($ in millions) Amount Value Amount Value
----------------------------------------------------------------------------------------------------------------------------
Long-term investments for which it is:
Practicable to estimate fair value 84.0 83.6 60.1 59.7
Not practicable to estimate fair value 6.6 - 146.7 -
Long-Term Debt 2,012.9 2,044.7 - -
Liabilities subject to Chapter 11 proceedings for which it is:
Practicable to estimate fair value
Long-term debt - - 1,390.8 1,664.8
Not practicable to estimate fair value
Long-term debt - - 88.4 -
Bank loans and commercial paper - - 892.6 -
Other - - 1,617.1 -
----------------------------------------------------------------------------------------------------------------------------
13. OTHER COMMITMENTS AND CONTINGENCIES
A. CAPITAL EXPENDITURES. Capital expenditures for 1996 are currently
estimated at $327 million. Of this amount, $133 million is for
transmission operations, $160 million for distribution operations, $21
million for oil and gas operations, and $13 million for other energy
operations.
B. PROPOSED SALE OF COLUMBIA GAS DEVELOPMENT CORPORATION. On October
23, 1995, Columbia announced its intention to sell Columbia
Development which has approximately 196 billion cubic feet equivalent
of proved oil and natural gas reserves located in the Gulf of Mexico
and on-shore continental United States. Based on the proposed sale of
this subsidiary in early 1996, an estimated loss of $54.8 million
after-tax was recorded in the fourth quarter of 1995. It is expected
that any sale of Columbia Development may take several months to
complete and the financial impact of the sale may be different once
finalized. At this time there are no plans to sell Columbia's
Appalachian oil and gas subsidiary, Columbia Natural Resources, Inc.
(CNR).
C. OTHER LEGAL PROCEEDINGS. 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.
TriStar Ventures Corporation (TriStar), a wholly-owned subsidiary of
Columbia, is a general partner in the Binghamton, Pedericktown, and
Vineland Cogeneration partnerships. All moneys paid and to be paid by
the partners are assigned as collateral for loans to various banks (or
in the case of Vineland, to the Indenture Trustee). TriStar's
investment in the partnerships, as of December 31, 1995, amounted to
$31.4 million.
E. INTERNAL REVENUE SERVICE (IRS) AUDIT. A review by the IRS of
Columbia's 1991 and 1992 federal income tax returns have been
concluded. The major unresolved issues are included in the Revenue
Agents Report, the resolution of which are currently being pursued
with the Appeals Division of the IRS. Management believes that these
same items will also be issues in the 1993 through 1995 tax returns.
Based on the facts known at this time, adequate reserves have been
established for these issues.
F. OPERATING LEASES. Payments made in connection with operating leases
are charged to operation and maintenance expense as incurred. Such
amounts were $61.6 million in 1995, $56.6 million in 1994 and $55.5
million in 1993.
65
66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Future minimum rental payments required under operating leases that have
initial or remaining noncancelable lease terms in excess of one year are:
($ in millions)
-----------------------------------------------------------------------------------------------------------------
1996 18.9
-----------------------------------------------------------------------------------------------------------------
1997 15.0
-----------------------------------------------------------------------------------------------------------------
1998 14.6
-----------------------------------------------------------------------------------------------------------------
1999 12.0
-----------------------------------------------------------------------------------------------------------------
2000 6.7
-----------------------------------------------------------------------------------------------------------------
After 69.9
-----------------------------------------------------------------------------------------------------------------
G. 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.
Certain subsidiaries have received notice from the United States
Environmental Protection Agency (EPA) that they are among several
parties responsible under federal law for placing wastes at Superfund
sites and may be required to share in the cost for remediation of
these sites. However, considering known facts, existing laws and
possible insurance and rate recoveries, management does not believe
the identified Superfund matters will have a material adverse effect
on future annual income or on Columbia's financial position.
Columbia's transmission subsidiaries continue their reviews of
compliance with existing environmental standards, including reviews of
past operational activities, identification of potential problems
through site reviews and the formulation of remediation programs where
necessary. The progress of Columbia Transmission's efforts in the
last year, was limited by a 1995 EPA Administrative Order by Consent
(AOC) that requires Columbia Transmission to obtain prior EPA approval
of its investigation, characterization and remediation efforts.
Progress was further limited because of the more than 19,000 miles of
pipeline that Columbia Transmission operates, the exceptionally large
number of sites at which it conducts or has conducted operations, and
the long time period over which operations have been conducted.
Management had previously estimated, based on studies conducted since
1990 by independent consultants, that site investigation,
characterization and remediation costs might range between $135
million and $280 million. The primary focus of these prior studies was
to analyze discrete issues to assist management in its on-going
environmental evaluations. In 1994, in anticipation of implementation
of the AOC, Columbia Transmission commissioned a new study (1995
Study) to reflect costs that might arise from the EPA's
recommendations with respect to site assessment and remediation under
the AOC and to reflect information gathered since the previous
studies. The 1995 Study was structured to be a comprehensive review
of all environmental issues currently known to management. The 1995
Study estimated that the cost of Columbia Transmission's environmental
program under the AOC may range between $204 million and $319 million
over the life of the program. This estimate was based on a limited
amount of actual data available and utilized a variety of assumptions,
including: the number of sites to be investigated, characterized and
remediated; the location, nature and levels of wastes that will be
treated at or disposed of from each site; the amount of time and
nature of equipment required for such activities; the appropriate
remediation levels and the technology to be utilized; and the
frequency with which groundwater contamination might be discovered at
sites requiring remediation. The 1995 Study did not include
previously identified costs, aggregating approximately $50 million,
for which Columbia Transmission already had reasonable estimates.
66
67
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Following an extensive review of bases utilized and assumptions
contained in the 1995 Study, management has concluded that 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). This conclusion was
based upon the fact that the actual characterization and remediation
experience of Columbia Transmission was extremely limited and
information on environmental conditions at many of the sites or former
sites of operations is not yet available. The nature and condition of
such sites varies greatly, and any change in any of the numerous
assumptions used in the 1995 Study may materially alter the estimated
range of costs, with no assurance that actual costs will not exceed
amounts specified in the range. Columbia Transmission is unable, at
this time, to accurately estimate the timeframe and potential costs of
all site screening, characterization and remediation. As Columbia
Transmission continues its program pursuant to the AOC, additional
costs will become probable and reasonably estimable and will be
recorded. Moreover, in time, management expects that, as additional
work is performed and more facts become available, it will then 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 and SFAS
No. 5.
Based upon its current review, Columbia Transmission estimates the
future costs of investigating, characterizing, and remediating sites
upon which it has adequate information will be approximately $136.6
million. This resulted in the recognition of an additional liability
of approximately $21 million in the fourth quarter of 1995. As
contemplated by the AOC, Columbia Transmission's environmental
expenditures are expected to approximate $20 million in 1996 and to
continue at that level for the foreseeable future. These expenditures
will be charged against Columbia's previously recorded liability.
Management does not believe that Columbia Transmission's environmental
expenditures will have a material adverse effect on Columbia's
operations, liquidity or financial position, based on known facts and
existing laws and regulations and the long period over which
expenditures will be made. In addition, as a result of reapplying
SFAS No. 71, Columbia Transmission has recorded a regulatory asset to
the extent environmental expenditures are expected to be recovered
through rates, and therefore, environmental expenditures will have
less potential impact upon Columbia's financial results.
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. Columbia Transmission is unable at this time to
determine if it will become liable for any characterization or
remediation costs at such sites.
The distribution subsidiaries' (Distribution) primary environmental
issues relate to 14 former manufactured gas plant sites.
Investigations or remedial activities are currently underway at five
sites and additional site investigations may be required at some of
the remaining sites. To the extent Distribution 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
allowed or is anticipated.
On October 18, 1995, Columbia of Pennsylvania was served in a
Comprehensive Environmental Response Compensation and Liability Act
cost recovery action related to the Keystone Sanitation Company
Landfill/Superfund site. Columbia of Pennsylvania may be named as a
Potentially Responsible Party (PRP) by virtue of trash hauling
services provided to Columbia of Pennsylvania's service center by the
city of Hanover, Pennsylvania. Columbia of Pennsylvania believes
based on a preliminary investigation of the facts, that involvement at
this site, if any, will not have a material impact on Columbia.
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
67
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
on information currently available which resulted in a total recorded
net liability of approximately $142 million for Columbia at December
31, 1995. As new issues are identified, additional liabilities will
be recorded.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve
mutually acceptable compliance plans. However, there can be no
assurance that fines and penalties will not be incurred. Management
expects most environmental assessment and remediation costs to be
recoverable through rates.
14. INTEREST INCOME AND OTHER, NET
Year Ended December 31 ($ in millions) 1995 1994 1993
----------------------------------------------------------------------------------------------------------------------
Interest income 22.8 31.8 9.8
Estimated loss on the proposed sale of Columbia
Gas Development Corporation (77.8) - -
Miscellaneous (3.2) 3.4 (2.1)
----------------------------------------------------------------------------------------------------------------------
TOTAL (58.2) 35.2 7.7
----------------------------------------------------------------------------------------------------------------------
15. INTEREST EXPENSE AND RELATED CHARGES
Year Ended December 31 ($ in millions) 1995 1994 1993
----------------------------------------------------------------------------------------------------------------------
Interest on emergence, including amortization of
discounts on long-term debt 982.9 - -
Interest on debt 15.1 0.2 0.2
Interest on rate refunds 17.7 9.0 8.4
Interest on prior years' taxes 17.6 (8.8) 74.5
Allowance for borrowed funds used and interest during
construction (52.4) - -
Other interest charges 7.5 14.4 18.4
----------------------------------------------------------------------------------------------------------------------
TOTAL 988.4 14.8 101.5
----------------------------------------------------------------------------------------------------------------------
16. BUSINESS SEGMENT INFORMATION
Columbia is a registered holding company under the Public Utility
Holding Act of 1935, as amended, and derives substantially all of its
revenues and earnings from the operating results of its 18 direct
subsidiaries. Columbia's subsidiaries are divided into four primary
business segments. The transmission segment offers transportation and
storage services for local distribution companies and industrial and
commercial customers located in northeastern, middle Atlantic,
midwestern and southern states and the District of Columbia. The
distribution segment provides natural gas service for residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia,
Kentucky and Maryland. The oil and gas segment explores for,
develops, produces, and markets oil and natural gas in the United
States. Columbia has announced the proposed sale of its wholly-owned
southwest exploration and production subsidiary (see Note 13B). Other
energy operations include the sale of propane at wholesale and retail
to customers in eight states, participation in natural gas fueled
cogeneration projects, the leasing of coal reserves located in the
Appalachian area, the marketing of natural gas to distribution
companies, independent power producers and other large end users and
gas peaking services. In addition, other energy includes a company
that provides centralized data processing, financial, accounting,
legal and other services to Columbia and other subsidiaries.
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
68
69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
and expenses directly associated with each segment. Identifiable
assets include only those attributable to the operations of each
segment.
($ in millions) 1995 1994 1993
---------------------------------------------------------------------------------------------------------------------
REVENUES
Transmission -Unaffiliated 432.4 475.9 1,055.8
-Intersegment 324.3 282.8 642.9
---------------------------------------------------------------------------------------------------------------------
TOTAL 756.7 758.7 1,698.7
---------------------------------------------------------------------------------------------------------------------
Distribution -Unaffiliated 1,780.6 1,830.7 1,830.7
-Intersegment 2.5 - -
---------------------------------------------------------------------------------------------------------------------
TOTAL 1,783.1 1,830.7 1,830.7
---------------------------------------------------------------------------------------------------------------------
Oil and Gas -Unaffiliated 111.5 121.7 181.2
-Intersegment 69.1 83.6 41.0
---------------------------------------------------------------------------------------------------------------------
TOTAL 180.6 205.3 222.2
---------------------------------------------------------------------------------------------------------------------
Other energy -Unaffiliated 310.7 304.1 237.9
-Intersegment 78.7 67.4 69.9
---------------------------------------------------------------------------------------------------------------------
TOTAL 389.4 371.5 307.8
---------------------------------------------------------------------------------------------------------------------
Adjustments -Unaffiliated - 14.7 8.2
and eliminations -Intersegment (474.6) (433.8) (753.8)
---------------------------------------------------------------------------------------------------------------------
TOTAL (474.6) (419.1) (745.6)
---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED 2,635.2 2,747.1 3,313.8
---------------------------------------------------------------------------------------------------------------------
69
70
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
($ in millions) 1995 1994 1993
--------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS)
Transmission 214.1 209.7 176.9
Distribution 163.6 128.3 146.4
Oil and gas 3.7 30.6 53.6
Other energy 19.3 24.1 3.1
Corporate (10.5) (8.6) (7.0)
--------------------------------------------------------------------------------------------------------------
CONSOLIDATED 390.2 384.1 373.0
--------------------------------------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
Transmission 103.8 103.9 97.8
Distribution 70.9 64.5 62.3
Oil and gas 86.9 86.2 73.8
Other energy 7.9 7.1 5.9
Adjustments and eliminations 0.5 - -
--------------------------------------------------------------------------------------------------------------
CONSOLIDATED 270.0 261.7 239.8
--------------------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Transmission 2,962.9 4,138.1 4,156.6
Distribution 2,295.7 2,168.9 2,065.5
Oil and gas 412.4 746.4 732.0
Other energy 192.5 128.3 128.6
Adjustments and eliminations (352.4) (387.1) (376.3)
Corporate and unallocated 545.9 370.3 251.5
--------------------------------------------------------------------------------------------------------------
CONSOLIDATED 6,057.0 7,164.9 6,957.9
--------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Transmission 169.1 179.1 137.2
Distribution 151.8 151.4 117.8
Oil and gas 86.8 101.6 95.1
Other energy 14.1 15.1 11.2
--------------------------------------------------------------------------------------------------------------
CONSOLIDATED 421.8 447.2 361.3
--------------------------------------------------------------------------------------------------------------
70
71
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data does not always reveal the trend of
the System's business operations due to bankruptcy matters,
nonrecurring items and seasonal weather patterns which affect
earnings and related components of operating revenues and
expenses.
First Second Third Fourth
($ in millions except per share data) Quarter Quarter Quarter Quarter
---------------------------------------------------------------------------------------------------------
1995
Operating Revenues 1,030.7 454.6 366.3 783.6
Operating Income 199.9 26.9 14.3 149.1
Income (Loss) before
Extraordinary Item 128.8 30.9 19.3 (611.3)
Extraordinary Item - - - 71.6
Net Income (Loss) 128.8 (a) 30.9 (b) 19.3 (c) (539.7) (d)
Per Share Amounts
Earnings (Loss) before Extraordinary item 2.55 0.61 0.38 (12.17)
Extraordinary Item - - - 1.43
Earnings (Loss) on Common Stock 2.55 0.61 0.38 (10.74)
---------------------------------------------------------------------------------------------------------
1994
Operating Revenues 1,117.2 509.6 372.1 748.2
Operating Income 222.2 39.6 20.8 101.5
Income (Loss) before Cumulative
Effect of Accounting Change 140.2 47.8 (15.0) 73.2
Cumulative Effect of
Accounting Change (5.6) - - -
Net Income (Loss) 134.6 (e) 47.8 (f) (15.0) (g) 73.2 (h)
Per Share Amounts
Earnings (Loss) before
Accounting Change 2.77 0.95 (0.30) 1.45
Change in Accounting (0.11) - - -
Earnings (Loss) on Common Stock 2.66 0.95 (0.30) 1.45
---------------------------------------------------------------------------------------------------------
(a) Includes a decrease in net income of $5.3 million for
professional fees and related expenses resulting
from bankruptcy. Net income benefited $42.1 million
from not recording estimated interest expense on
prepetition debt.
(b) Includes a decrease in net income of $6.1 million
for professional fees and related expenses resulting
from bankruptcy. Net income benefited $43.7 million
from not recording estimated interest expense on
prepetition debt.
(c) Includes a decrease in net income of $6.7 million
for professional fees and related expenses resulting
from bankruptcy. Net income benefited $43.7 million
from not recording estimated interest expense on
prepetition debt.
(d) Includes a decrease for the impact of emergence from
bankruptcy and customer settlement of $649.4, the
estimated loss on the proposed sale of Columbia Gas
Development Corp. of $54.8 and an improvement of
$71.6 for the reapplication of SFAS No. 71.
(e) Includes an increase in net income of $10.3 million
for an adjustment to the reserve for the IRS
settlement and an increase in net income of $8.3
million for surcharge collections of certain prior
period gas costs. Net income benefited $35.2
million from not recording estimated interest
expense on prepetition debt.
(f) Includes a decrease in net income of $4.3 million
for a weather normalization adjustment resulting
from a regulatory settlement and a decrease in net
income of $2.1 million associated with employee
relocation costs, partially offset by an increase in
net income of $3.2 million for an adjustment to a
reserve for a resolution of a royalty dispute. Net
income benefited $35.7 million from not recording
estimated interest expense on prepetition debt.
(g) Includes a decrease in net income of $35.4 million
resulting from an increase to a reserve for
take-or-pay and other miscellaneous producer claims.
Net income benefited $38.4 million from not
recording estimated interest expense on prepetition
debt.
(h) Includes a decrease in net income of $22.8 million
for a reserve established for regulatory issues.
Net income benefited $39.9 million from not
recording estimated interest expense on prepetition
debt.
71
72
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
18. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
INTRODUCTION. On October 23, 1995, Columbia announced its
intent to sell Columbia Development, its wholly-owned
Southwest oil and gas production subsidiary. The information
contained in the following tables includes amounts
attributable to the operations and reserves of Columbia
Development.
Reserve information contained in the following tables for the
U.S. properties is management's estimate, which was reviewed
by the independent consulting firm of Ryder Scott Company
Petroleum Engineers. Reserves are reported as net working
interest. Gross revenues are reported after deduction of
royalty interest payments.
CAPITALIZED COSTS
--------------------------------------------------------------------------------------------------------------
($ in millions) 1995 1994 1993
--------------------------------------------------------------------------------------------------------------
CAPITALIZED COSTS AT YEAR END
Proved properties 486.2 1,185.8 1,129.6
Unproved properties(a) 30.1 76.1 79.1
--------------------------------------------------------------------------------------------------------------
Total capitalized costs 516.3 1,261.9 1,208.7
Accumulated depletion (141.1) (637.6) (600.0)
--------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS 375.2 624.3 608.7
--------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR(B)
Acquisition
Proved properties - - -
Unproved properties 1.1 7.5 7.1
Exploration 4.3 24.3 17.5
Development 15.5 69.0 70.1
--------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED 20.9(c) 100.8 94.7
--------------------------------------------------------------------------------------------------------------
(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 to Consolidated Financial
Statements of $1.7 million in 1995, $6.4 million in 1994 and
$6.0 million in 1993.
(c) Excludes capital expenditures for properties held for sale.
HISTORICAL RESULTS
OF OPERATIONS APPALACHIA SOUTHWEST TOTAL
-----------------------------------------------------------------------------------------------------------------------
($ in millions) 1995 1994 1993 1995 1994 1993 1995 1994 1993
-----------------------------------------------------------------------------------------------------------------------
Gross revenues
Unaffiliated 46.6 56.6 78.7 60.1 74.3 103.0 106.7 130.9 181.7
Affiliated 32.8 29.5 17.2 35.9 39.2 23.7 68.7 68.7 40.9
Production costs 21.2 23.0 22.1 26.7 29.0 28.5 47.9 52.0 50.6
Depletion 39.5 37.4 31.6 47.0 48.4 41.9 86.5 85.8 73.5
Income tax expense 6.5 9.0 14.8 7.8 12.6 19.7 14.3 21.6 34.5
-----------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 12.2 16.7 27.4 14.5 23.5 36.6 26.7 40.2 64.0
-----------------------------------------------------------------------------------------------------------------------
Results of operations for producing activities exclude administrative and
general costs, corporate overhead and interest expense. Income tax expense
is expressed at statutory rates less Section 29 credits.
72
73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
OTHER OIL AND GAS PRODUCTION DATA
-----------------------------------------------------------------------------------------------------
1995 1994 1993
-----------------------------------------------------------------------------------------------------
Average sales price per Mcf of gas ($) 1.96 2.18 2.28
Average sales price per barrel of oil and
other liquids ($) 16.17 15.09 16.17
Production (lifting) cost per dollar of
gross revenue ($) 0.27 0.26 0.23
Depletion rate per dollar of
gross revenue ($) 0.49 0.43 0.33
-----------------------------------------------------------------------------------------------------
RESERVE QUANTITY INFORMATION
-----------------------------------------------------------------------------------------------------
Oil and Other
Gas Liquids
Proved Reserves (Bcf) (000 Bbls)
-----------------------------------------------------------------------------------------------------
Reserves as of December 31, 1992 779.5 14,650
Revisions of previous estimate (60.1) (589)
Extensions, discoveries and other additions 52.4 2,334
Production (71.5) (3,603)
Sale of reserves-in-place (3.3) -
-----------------------------------------------------------------------------------------------------
Reserves as of December 31, 1993 697.0 12,792
Revisions of previous estimate (31.3) 1,650
Extensions, discoveries and other additions 81.7 1,386
Production (66.7) (3,611)
Purchase of reserves-in-place 3.6 38
Sale of reserves-in-place (0.5) -
-----------------------------------------------------------------------------------------------------
Reserves as of December 31, 1994 683.8 12,255
Revisions of previous estimate 72.4 (522)
Extensions, discoveries and other additions 53.6 2,668
Production (65.4) (2,849)
Sale of reserves-in-place (7.9) -
-----------------------------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1995(a) 736.5 11,552
-----------------------------------------------------------------------------------------------------
Proved developed reserves as of December 31,
1993 573.7 10,793
1994 543.3 11,504
1995(b) 583.3 10,569
-----------------------------------------------------------------------------------------------------
(a) Includes reserves held for sale of 137.0 Bcf and 9,901,000 Bbls.
(b) Includes reserves held for sale of 111.7 Bcf and 8,961,000 Bbls.
73
74
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
---------------------------------------------------------------------------------------------------------------------------
APPALACHIA SOUTHWEST TOTAL
---------------------------------------------------------------------------------------------------------------------------
($ in millions) 1995 1994 1993 1995 1994 1993 1995 1994 1993
---------------------------------------------------------------------------------------------------------------------------
Future cash inflows 1,793.8 1,274.8 1,756.3 462.8 392.5 450.1 2,256.6 1,667.3 2,206.4
Future production costs (606.7) (380.9) (387.0) (104.9) (111.1) (121.0) (711.6) (492.0) (508.0)
Future development costs (166.3) (124.5) (94.2) (51.4) (43.5) (77.8) (217.7) (168.0) (172.0)
Future income tax expense (327.1) (233.8) (413.1) (79.9) (46.8) (49.9) (407.0) (280.6) (463.0)
---------------------------------------------------------------------------------------------------------------------------
Future net cash flows 693.7 535.6 862.0 226.6 191.1 201.4 920.3 726.7 1,063.4
Less 10% discount 377.7 285.4 474.5 42.7 35.0 37.5 420.4 320.4 512.0
---------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF
DISCOUNTED FUTURE
NET CASH FLOW 316.0 250.2 387.5 183.9 156.1 163.9 499.9 406.3 551.4
---------------------------------------------------------------------------------------------------------------------------
Future cash inflows are computed by applying year-end prices to
estimated future production of proved oil and gas 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 percent 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 oil and gas 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.
74
75
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
oil and gas reserves for the three years ending December 31 follows:
------------------------------------------------------------------------------------------------------
($ in millions) 1995 1994 1993
------------------------------------------------------------------------------------------------------
Beginning of year 406.3 551.4 661.1
------------------------------------------------------------------------------------------------------
Oil and gas sales,
net of production
costs (124.3) (147.6) (172.0)
Net changes in prices
and production costs 132.7 (236.5) (56.5)
Change in future
development costs (49.7) 4.1 (9.2)
Extensions, discoveries
and other additions,
net of related costs 106.5 68.2 66.9
Revisions of previous
estimates, net of
related costs 72.5 (17.3) (71.1)
Sales of reserves-in-place (11.7) (0.5) (4.4)
Purchases of reserves-in-place - 1.0 -
Accretion of discount 55.2 77.8 92.4
Net change in income taxes (64.9) 80.8 36.8
Timing of production
and other changes (22.7) 24.9 7.4
------------------------------------------------------------------------------------------------------
END OF YEAR 499.9 406.3 551.4
------------------------------------------------------------------------------------------------------
The estimated discounted future net cash flows increased
during 1995 primarily due to net changes in prices and
production costs, extensions, discoveries and other additions,
as well as revisions to the economic feasibility of producing
certain wells.
Under Order 636, the natural gas pipeline industry is required
to eventually unbundle gathering services from other
transportation services. Columbia Transmission provides
transportation services, including gathering services, for a
significant portion of gas produced from CNR's reserves, and
in its August 1, 1995 general rate filing, Columbia
Transmission requested an increase in its gathering rate to
reflect partial unbundling of this service.
Columbia Transmission is currently preparing the regulatory
filings necessary for abandonment of selected gathering
facilities and transfer of those assets to CNR. Capital
expenditures may be incurred for compression and measurement.
Operation and maintenance costs associated with these
facilities will be partially offset by the absence of Columbia
Transmission's gathering charges on wells located in southern
West Virginia coupled with additional revenue generated from
transportation of third party gas. However, if the transfer
of properties does not occur and if there is a significant
increase in gathering rates as a result of unbundling, certain
reserves could be uneconomical to produce which could have a
material adverse effect on CNR's operating strategies and
financial results beginning in 1996.
75
76
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule II
VALUATION AND QUALIFYING ACCOUNTS
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31,
($ in Millions)
Additions - Charged to
------------------------
Beginning Other Deductions Ending
Description Balance Income Accounts (a) (b) Balance
- ----------- --------- ------ ------------- ---------- -------
Reserves deducted in the balance sheet
from the assets to which they apply:
Allowance for doubtful accounts
1995 11.6 31.6 11.3 42.2 12.3
1994 11.8 21.5 15.8 37.5 11.6
1993 11.8 17.9 12.6 30.5 11.8
(a) Reflects reclassification 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.
76
77
ITEM 9.
CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
There has not been a change of accountants nor any disagreements concerning
accounting and financial disclosure within the past two years.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this is contained in Columbia's Proxy Statement related
to the 1996 Annual Meeting of Stockholders, filed pursuant to Section 14 of the
Securities Exchange Act of 1934 and is incorporated herein by reference.
Information regarding Columbia's executive officers, is as follows:
OLIVER G. RICHARD III, 43, Chairman, Chief Executive Officer and President
of The Columbia Gas System, Inc. (effective 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 of
Enron Gas Pipeline Group from 1987 to 1989. 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, 49, Senior Vice President and Chief Legal Officer of
Columbia and Columbia Gas System Service Corporation since August 1995.
Senior Vice President of Columbia and Columbia's Service Corporation 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, 51, Senior Vice President and Chief Financial Officer
of Columbia since October 1993. Senior Vice President and Assistant Chief
Financial Officer of the Columbia Gas System Service Corporation since 1989.
LOGAN W. WALLINGFORD, 63, Senior Vice President of Columbia Gas System
Service Corporation since March 1989. Senior Vice President of Planning and
Storage for Columbia Transmission from July 1988 to February 1989. Senior
Vice President, Gas Acquisition from July 1987 to June 1988.
RICHARD E. LOWE, 55, Vice President of Columbia and Columbia Gas System
Service Corporation since September 1988. Vice President and General
Auditor of Columbia's Service Corporation from April 1987 to August 1988.
CATHERINE GOOD ABBOTT, 45, Chief Executive Officer of Columbia Transmission
and 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.
C. RONALD TILLEY, 60, Chairman and Chief Executive Officer of Columbia
Distribution Companies from January 1987 to January 1996.
77
78
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in Columbia's Proxy Statement
related to the 1996 Annual Meeting of Stockholders, 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 1996 Annual Meeting of Stockholders, 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 1996 Annual Meeting of Stockholders, filed pursuant to Section
14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Exhibits
Reference is made to pages 81 through 83 for the list of exhibits filed as a
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 SEC 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 November 22, 1995, containing the Bankruptcy
Court's orders, dated November 15, 1995, confirming the reorganization plans of
Columbia and Columbia Transmission, a Press Release published on November 15,
1995 regarding the orders with a summary of the material features of the plans,
and an unaudited condensed consolidated balance sheet for Columbia giving the
effect of the plans as confirmed. The report on Form 8-K also contained
certain factors, as published by Columbia on November 20, 1995, which could be
used to estimate distributions upon emergence with respect to outstanding
prepetition debt of Columbia. The report on Form 8-K also contained a Press
Release published on November 21, 1995 regarding the projected interest and
dividend rates for debentures and preferred stock to be issued upon emergence
assuming that emergence occurs on November 28, 1995.
A report on Form 8-K was filed on November 30, 1995 discussing Columbia's and
Columbia Transmission's emergence from Chapter 11 on November 28, 1995.
A report on Form 8-K was filed on February 8, 1996, containing a Press Release
published on February 5, 1996, regarding the financial and operating results
for the year ended December 31, 1995. Also included in this Form 8-K
78
79
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
was a Press Release dated February 8, 1996, concerning Columbia's intention to
redeem its Series B - DECS and Series A - Preferred Stock.
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, Columbia undertakes the following, which is
incorporated by reference into the registration statements on Form S-8, Nos.
33-10004 (filed November 26, 1986) and 33-42776 (filed September 13, 1991):
Insofar as indemnification for liabilities arising under the Securities Act of
1933 (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 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.
79
80
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.
THE COLUMBIA GAS SYSTEM, INC.
-----------------------------
(Registrant)
Dated: February 21, 1996
By: /s/ Michael W. O'Donnell
----------------------------
(Michael W. O'Donnell)
Senior Vice President and
Chief Financial 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.
Feb. 21, 1996 /s/Oliver G. Richard III Feb. 21, 1996 /s/Richard E. Lowe
---------------------------------------- -----------------------------------
Director (Principal Vice President
Executive Officer) (Principal Accounting
Officer)
Feb. 21, 1996 /s/Richard F. Albosta Feb. 21, 1996 /s/Robert H. Beeby
--------------------------------------- -----------------------------------
Director Director
Feb. 21, 1996 /s/Wilson K. Cadman Feb. 21, 1996 /s/Malcolm T. Hopkins
------------------------------------- -----------------------------------
Director
Feb. 21, 1996 /s/Donald P. Hodel Feb. 21, 1996 /s/William E. Lavery
---------------------------------------- -----------------------------------
Director Director
Feb. 21, 1996 /s/Malcolm Jozoff Feb. 21, 1996 /s/Douglas E. Olesen
---------------------------------------- -----------------------------------
Director Director
Feb. 21, 1996 /s/Gerald E. Mayo Feb. 21, 1996 /s/James R. Thomas, II
---------------------------------------- -----------------------------------
Director Director
Feb. 21, 1996 /s/Ernesta G. Procope Feb. 21, 1996 /s/William R. Wilson
--------------------------------------- -----------------------------------
Director Director
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81
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
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.
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
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.
10-P(a) - Pension Restoration Plan of The Columbia Gas 1-1098 10-P
System, Inc., amended October 9, 1991.
10-Q(a) - Thrift Restoration Plan of The Columbia Gas 1-1098 10-Q
System, Inc. dated January 1, 1989.
10-T - Agreement and Bridge Agreement dated 1-1098 10-T
December 1, 1993, between Columbia Gas
Transmission Corporation and Consol
Pennsylvania Coal Company.
10-AE - U.S. Environmental Protection Agency Administrative 1-1098 10-AE
Order by Consent for Removal Actions for Columbia Gas
Transmission Corporation dated September 22,1994.
10-AF* - Amended and Restated Indenture of Mortgage and
Deed of Trust by Columbia Gas Transmission
Corporation to Wilmington Trust Company,
dated as of November 28, 1995
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(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
* Filed herewith.
81
82
ITEM 14. EXHIBIT INDEX (Continued)
Reference
-----------------
File No. Exhibit
-------- -------
10-BB(a) - Annual Incentive Compensation Plan of 1-1098 10-BB
The Columbia Gas 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, 1-1098 10-BV
between The Columbia Gas System, Inc. and
Anderson Exploration Ltd. and Montreal Trust
Company of Canada.
10-BW - Kotaneelee Litigation Indemnity Agreement dated 1-1098 10-BW
as of December 31, 1991, among The Columbia
Gas System, Inc. and Columbia Gas Development
of Canada Ltd. and Anderson Exploration Ltd.
10-BX - Specified Litigation Indemnity Agreement made 1-1098 10-BX
as of December 31, 1991, among The Columbia
Gas System, Inc. and Columbia Gas Development
of Canada Ltd. and Anderson Exploration Ltd.
10-BY(a) - Columbia Gas Restoration Security Trust 1-1098 10-BY
Agreement dated June 1, 1991 with Dauphin
Deposit Bank and Trust Company.
10-CA(a) - The Columbia Gas System, Inc. Retirement Plan 1-1098 10-CA
for Outside Directors, as amended, August 21, 1991.
10-CB* - Credit Agreement, dated as of
November 28, 1995, among The Columbia Gas System,
Inc., certain banks party thereto and Citibank, N.A.
10-CC* - First Amendment and Supplement to Credit
Agreement, dated December 6, 1995
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.
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.
11* - Statements Re: Computation of Per Share Earnings.
12* - Statements of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends.
21* - Subsidiaries of The Columbia Gas System, Inc.
23-A* - Letter report, dated January 29, 1996, and the written
consent to the filing and use of information contained
in such letter report, Reports and Registration Statements
filed during 1996, of Ryder Scott Company Petroleum Engineers,
independent petroleum and natural gas consultants.
- ------------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
* Filed herewith.
82
83
ITEM 14. EXHIBIT INDEX (Continued)
Reference
-----------------
File No. Exhibit
-------- -------
23-B* - Written consent of Arthur Andersen LLP,
independent public accountants, to the
incorporation by reference of their report
included in the 1995 Annual Report on Form
10-K of The Columbia Gas System, Inc. and
their report included in The Columbia Gas
System, Inc.'s 1995 Annual Report to Shareholders
in the registration statements on Form S-8
(File No. 33-10004), and Form S-8
(File No. 33-42776).
27* - Financial Data Schedule for the period ended
December 31, 1995.
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*Filed herewith.
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