<PAGE> 1
Commission File No. 1-1098
As filed with the United States Securities and Exchange Commission on March 14,
1997.
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, 1996
or
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.
-------------------------------------------------------
(Exact name of registrant as specified in its charter)
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<S> <C>
Delaware 13-1594808
(State or other Jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
12355 Sunrise Valley Drive, Suite 300, Reston, VA 20191-3420
(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code (703)295-0300
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
------------------- ---------------------
Common Stock, $10 Par Value........... New York Stock Exchange
Debentures
6.39% Series A due November 28, 2000
6.61% Series B due November 28, 2002
6.80% Series C due November 28, 2005
7.05% Series D due November 28, 2007
7.32% Series E due November 28, 2010
7.42% Series F due November 28, 2015
7.62% Series G due November 28, 2025
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the proceeding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days: Yes _X_ or No ___.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the outstanding common shares of the Registrant
held by nonaffiliates as of January 31, 1997, was $3,586,056,000. 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,
1997, was: Common Stock $10 Par Value: 55,343,729 shares outstanding.
Documents Incorporated by Reference
Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the 1997 Annual Meeting of Stockholders.
<PAGE> 2
CONTENTS
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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...................... 12
Part II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters............................... 12
Item 6. Selected Financial Data.................................................. 13
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................... 15
Item 8. Financial Statements and Supplementary Data.............................. 40
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure.......................................... 75
Part III
Item 10. Directors and Executive Officers of the Registrant....................... 75
Item 11. Executive Compensation................................................... 76
Item 12. Security Ownership of Certain Beneficial Owners and Management........... 76
Item 13. Certain Relationships and Related Transactions........................... 76
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......... 76
Undertaking made in Connection with 1933 Act Compliance on Form S-8............... 76
Signatures........................................................................ 77
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<PAGE> 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
natural gas and oil. 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, 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 (Bankruptcy Code) on July 31, 1991. During the
bankruptcy period both Columbia and Columbia Transmission were
debtors-in-possession under the Bankruptcy Code and continued to operate their
businesses in the normal course subject to the jurisdiction of the United States
Bankruptcy Court for the District of Delaware.
Transmission and Storage Operations
Columbia's two interstate pipeline subsidiaries, Columbia Transmission and
Columbia Gulf Transmission Company (Columbia Gulf), operate a 23,100-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.
Columbia Transmission 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.
Columbia LNG Corporation is a partner with Potomac Electric Power Company in the
Cove Point LNG Limited Partnership (Partnership). The Partnership owns one of
the largest natural gas peaking and storage facilities in the United States
located 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.
Distribution Operations
Columbia's five distribution subsidiaries provide natural gas service to
approximately 2 million residential, commercial and industrial customers in
Ohio, Pennsylvania, Virginia, Kentucky and Maryland. The distribution
subsidiaries sell gas to high priority (mostly residential) customers and
transport gas for certain industrial and commercial customers who purchase gas
from other sources. Approximately 31,100 miles of distribution pipelines serve
these major markets.
Exploration and Production Operations
Columbia's exploration and production subsidiary, Columbia Natural Resources,
Inc. (Columbia Resources), explores for, develops and produces natural gas and
oil in Appalachia. As of December 31, 1996, Columbia Resources held interest in
more than 2 million net acres of gas and oil leases and had proved gas reserves
of approximately 645 Bcf. Columbia sold its southwest exploration and production
subsidiary effective December 31, 1995. For additional information, see Item 7,
page 33.
3
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ITEM 1. BUSINESS (Continued)
Marketing, Propane and Power Generation Operations
Columbia Energy Services Corporation (Columbia Energy), 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. Columbia Energy 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. Columbia Energy formed a
wholly-owned subsidiary, Columbia Service Partners, Inc. (Columbia Service), to
provide a variety of new nonregulated services to both homeowners and
businesses. In the second quarter of 1996, Columbia Service introduced Appliance
Partner, a service which offers customers appliance repair from qualified
independent contractors for a monthly premium. Another service provided by
Columbia Service is Gas Line Guarantee, which provides maintenance for gas
service lines running from the street to the house. Columbia Service has also
initiated a billing insurance program, Payment Partner, for customers within
certain areas of the distribution subsidiaries' service territory. As of
year-end 1996, Columbia Service had nearly 26,100 customers among the three
programs. In the future, Columbia Service expects to complement these services
with warranty and energy management services to commercial and industrial
customers. These new programs are part of Columbia's ongoing effort to become a
full service provider of energy and energy-related services.
TriStar Ventures Corporation (TriStar), a wholly-owned subsidiary of Columbia,
is involved in three cogeneration projects that produce both electricity and
useful thermal energy. These projects are fueled principally by natural gas.
TriStar holds various interests in these facilities that have a total capacity
of nearly 250 megawatts.
Columbia Propane Corporation and Commonwealth Propane, Inc., wholly-owned
subsidiaries of Columbia, sell propane at wholesale and retail to 79,650
customers in parts of ten eastern states and the District of Columbia. In total,
the propane companies sold nearly 76 million gallons of propane in 1996.
In 1996, Columbia formed Columbia Network Services Corporation (Columbia
Network), a wholly-owned subsidiary, to provide telecommunications and
information services. Columbia Network's primary focus is to assist personal
communications service (PCS) and other microwave radio service licensees in
locating and constructing antenna facilities as well as maintaining and managing
PCS sites for the licensees. In October 1996, Columbia Network entered into an
agreement with SABRE Decision Technologies, a division of The SABRE Group, Inc.
to jointly develop a centralized electronic energy data exchange. During the
initial phase, a standardized electronic bulletin board (EBB) will be designed
for use by the natural gas industry. The EBB will be consistent with
FERC-mandated business standards for electronic gas transportation transactions
and provide a single centralized interface that customers can utilize to conduct
business with a multitude of gas transportation service providers (TSPs). This
type of system is expected to reduce the overall transaction costs of trading
and transporting gas, support the standardization of gas transactions for the
natural gas industry, and allow TSPs to concentrate on their core businesses.
Columbia Network also plans to offer energy management services relating to the
collection and management of customer energy usage information. In addition,
these services may provide opportunities for real-time interactive
communications with customers with respect to a wide variety of information,
products, and services not exclusively energy-related.
For additional discussion of Columbia's business segments, including financial
information for the last three fiscal years, see Item 7, pages 15 through 39 and
Note 17 on pages 66 through 68 of Item 8.
Competition and Business Strategies
The natural gas and energy markets are undergoing tremendous change. Over the
past ten years open access to natural gas supplies over interstate pipelines 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. This "unbundling" of services and deregulation of the
commodity price is occurring at the distribution company level as well.
Columbia's distribution subsidiaries are involved in pilot programs that provide
residential customers the opportunity to purchase their natural gas requirements
from third parties and use the distribution subsidiaries for transportation
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
4
<PAGE> 5
ITEM 1. BUSINESS (Continued)
transmission of electricity is under investigation by the Federal Energy
Regulatory Commission (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.
For additional information, regarding competition, see Item 7.
In order to capitalize on the opportunities presented by this increasingly
competitive environment, Columbia's management is developing a more responsive,
entrepreneurial, 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. Columbia intends to focus on and
expand its core businesses, allocating approximately 87% of planned 1997 capital
investment to the transmission and distribution segments. Consistent with this
focus Columbia has undertaken a $270 million expansion of Columbia
Transmission's storage and transportation systems that will be phased in over a
three year period beginning in late 1997. Columbia's sale of its southwest
exploration and production subsidiary, Columbia Gas Development Corporation, is
consistent with this new strategy, following a 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 exploration and production
subsidiary, Columbia Resources, have greater strategic value due to their
location and may even be expanded if the appropriate business opportunities
present themselves.
Exploit Synergies. Unlike the structure of many of its peers,
Columbia's distribution, storage and exploration and production operations form
a grid connected from within by Columbia Transmission. Columbia is embarking on
a system-wide 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 Nonregulated 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 nonregulated
energy-related products and services. Through Columbia Energy, Columbia Service
and Columbia Network, Columbia expects to offer nonregulated energy-related
products and services to all energy consumers within its wholesale and retail
market area.
Streamline Organizational Structure. In 1996, Columbia's
subsidiaries completed a top-down review of their management structure and
operations in an effort to streamline their organizational structure and improve
customer service. The studies examined all aspects of Columbia's operations
including the configuration and location of its management. The benefits of this
reengineering initiative, called Project Phoenix, are beginning to be realized
through cost savings and improved efficiencies.
Implement CVA. An integral part of Columbia's financial strategy is
the recent application of a value added approach, called Columbia Value Added
(CVA), to all of its businesses. CVA is a financial process as well as a
financial measure that determines whether the anticipated return on a business
activity or project exceeds its risk adjusted capital cost. All
discretionary capital expenditures will be subject to the CVA process. This new
management tool aided Columbia in its decisions to allocate capital to Columbia
Transmission's planned expansion, as discussed in Item 7, page 21, 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 in late-1995, 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 1996, had a 56% ratio of long-term debt to total
capitalization. Columbia's long-term debt rating was recently upgraded by Fitch
Investor Service LP to BBB+, from BBB, and is currently rated Baa3 by Moody's
Investors Services and BBB by Standard & Poor's Corporation. One of management's
objectives is to improve the quality of its credit rating over time and 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
5
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ITEM 1. BUSINESS (Continued)
quality or debt ratios or that such credit ratings will continue for any given
period of time or that they will not be revised downward or withdrawn entirely
by these rating agencies. Credit ratings reflect only the views of the rating
agencies, whose methodology and the significance of their ratings may be
obtained from them.
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. Security holders and prospective
security holders should understand that several factors govern whether any
forward-looking statement contained herein will be or can be achieved. Important
factors, many of which are beyond the control of Columbia, 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 1996 Annual
Report to Shareholders.
As of January 31, 1997, the System had 9,274 full-time employees of which 1,948
are subject to collective bargaining agreements.
Information relating to environmental matters is detailed in Item 7 pages 23
through 24, page 29 and in Item 8, Note 14F on pages 63 through 65.
For a listing of the direct 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 page 48 of Item 8 under Note 1E. The System also owns coal
interests in the Appalachian area. Assets under lien and other guarantees are
described on page 63 in Note 14C 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.
EXPLORATION AND DEVELOPMENT DATA
Acreage - At December 31, 1996
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Developed Acreage Undeveloped Acreage
------------------------- ---------------------
Gross Net Gross Net
--------- --------- ------- -------
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Appalachian... 1,635,443 1,544,500 623,125 493,368
========= ========= ======= =======
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Net Wells Completed - 12 Months Ended December 31
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Exploratory Development Total
------------------ ------------------ --------------------
Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- ---
<S> <C> <C> <C> <C> <C> <C>
1996..... 0 0 19 8 19(a) 8
1995..... 4 4 64 21 68(a) 25
1994..... 3 9 78 14 81(a) 23
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Productive and Drilling Wells - At December 31, 1996
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Production Wells
- - ---------------------------------------------
Gross(b) Net Wells Drilling
- - ------------------ ----------------- ----------------
Gas Oil Gas Oil Gross Net
- - ----- --- ----- --- ----- ---
<C> <C> <C> <C> <C> <C>
6,115 128 5,627 80 17 7
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(a) Includes 1 net horizontal well in 1996, 18 net horizontal wells in 1995
and 17 net horizontal wells in 1994.
(b) Includes 773 multiple completion gas wells, all of which are included as
single wells in the table.
Also includes 1 gross productive horizontal well.
7
<PAGE> 8
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1996
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Miles of Pipeline Compressor Stations
Underground ------------------------------ --------------------
Storage Gathering Installed
---------------- and Trans- Distri- Capacity
Subsidiaries State Acreage Wells Storage mission bution Number (hp)
- - ------------------------------------- ----- ------- ----- --------- ------- ------ ------ ---------
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Columbia Gas of Kentucky, Inc........ KY - - - - 2,316 - -
Columbia Gas of Maryland, Inc........ MD - - - - 593 - -
Columbia Gas of Ohio, Inc............ OH - - - - 17,621 - -
Columbia Gas of Pennsylvania, Inc.... PA 3,364 8 4 - 6,816 1 800
Commonwealth Gas Services, Inc....... VA - - - - 3,725 - -
Columbia Gas Transmission
Corporation........................ DE - - - 3 - - -
KY - - 932 758 - 9 19,470
MD 945 - 22 227 - 1 12,000
NJ - - - 69 - - -
NY 26,083 143 58 486 - 4 8,190
NC - - - 1 - 1 1,200
OH 486,810 2,463 2,764 4,062 - 30 101,441
PA 63,806 263 615 2,062 - 29 66,555
VA - - 130 1,123 - 11 56,630
WV 293,204 815 3,038 2,519 - 54 303,273
Columbia Gulf Transmission Company... AR - - - 8 - - -
KY - - - 716 - 2 70,290
LA - - - 2,041 - 6 201,200
MS - - - 659 - 3 118,800
TN - - - 556 - 2 83,000
TX - - - 200 - - -
WY - - - 10 - - -
Columbia Natural Resources, Inc...... KY - - 434 - - - -
MI - - 6 - - - -
NY - - 2 - - - -
OH - - 102 - - - -
PA - - 11 - - - -
VA - - 25 - - - -
WV - - 176 - - - -
------- ----- ----- ------ ------ --- ---------
Total................................ 874,212 3,692 8,319 15,500 31,071 153 1,042,849
======= ===== ===== ====== ====== === =========
</TABLE>
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
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ITEM 3. LEGAL PROCEEDINGS
I. Purchase and Production Matters
A. Matters that have been resolved
Daniel Garshman v. Columbia Gas Transmission Corp., No.
ATL-L-000172-88, (Sup. Ct. of N.J. 1993). As reported in the Quarterly Report on
Form 10-Q for the third quarter of 1996, the parties proposed a resolution to
this dispute which was approved by the U. S. Bankruptcy Court for the District
of Delaware (the "Bankruptcy Court"). The resolution of this case did not have a
material effect on the financial condition of Columbia.
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 section of this Report.
2. New Ulm and Fox v. Mobil Oil Corp., Columbia Gas
Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655 (155th
Judicial Dist. Ct. of Austin County, TX). 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 gas
contracts.
After the Bankruptcy Court entered an order modifying the
automatic stay provided under the Federal Bankruptcy Code, jury trial began in
Texas state court 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. Thereafter, Columbia Transmission appealed to the
Court of Appeals for the First District of Texas.
On July 28, 1994, the Court of Appeals found that evidence
proffered by Columbia Transmission was improperly excluded from trial.
Consequently, the Court of Appeals reversed the trial court's judgment and
remanded the matter to the trial court for proceedings not inconsistent with the
Court of Appeals's opinion. On January 11, 1996, the Texas Supreme Court granted
both Columbia Transmission's and New Ulm's application for writ of error. On
October 18, 1996, the Texas Supreme Court reversed the judgment of the Court of
Appeals on New Ulm's contract interpretation claim and rendered judgment in
favor of Columbia Transmission on that issue. The Texas Supreme Court also
affirmed, in part, the appellate court's judgment by remanding New Ulm's fraud
claim to the trial court for further proceedings. The Texas Supreme Court denied
New Ulm's request for rehearing on December 13, 1996 on the contract
interpretation claim, and on February 3, 1997 issued the mandate of its judgment
to the Texas trial court.
3. 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 than the market-out price Columbia Transmission paid for past
periods under the same gas purchase contract price provision involved in the New
Ulm case discussed above. On January 10, 1989, Columbia Transmission removed the
case to the United States District Court for the Southern District of Texas (No.
H-89-0072).
By order entered December 7, 1992, the Bankruptcy Court
modified the automatic stay provided under the Federal Bankruptcy Code to allow
the U.S. District 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 its August
11, 1995 order, but stated that it would withdraw and vacate its order if the
Bankruptcy Court determined that it was in violation of the automatic stay. On
November 2, 1995, the Bankruptcy Court denied New Bremen's motion for an order
that the August 11, 1995 order was a violation of the automatic stay. The U.S.
District Court, on March 12, 1996, acting upon a motion filed by Columbia
Transmission, entered an order finding that there was no just reason to delay
entry of judgment and therefore entered final judgment of its August 11, 1995
order which granted Columbia Transmission's motion for partial summary judgment.
New Bremen appealed the U.S. District Court's grant of
partial summary judgment to the U.S. Court of Appeals for the Fifth Circuit. On
February 10, 1997, the Fifth Circuit denied New Bremen's appeal and upheld the
U. S.
9
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ITEM 3. LEGAL PROCEEDINGS (Continued)
District Court's grant of partial summary judgment in favor of Columbia
Transmission on the contract pricing issue. Columbia Transmission will seek to
have New Bremen's claim allowed by the Bankruptcy Court in accordance with the
Fifth Circuit decision and the claims mediator's report and recommendations
issued in the claims estimation proceedings (resolving issues not covered by the
Fifth Circuit decision).
II. Regulatory Matters
A. Matters that have been resolved
Tennessee Gas Pipeline Take-or-Pay Transition Cost Recovery
Filing, Docket No. RP96-61. As reported in the Quarterly Report on Form 10-Q for
the third quarter of 1996, on July 22, 1996, the FERC issued an order holding
that Tennessee Gas Pipeline Company may not bill new take-or-pay costs to
Columbia Transmission. On August 6, 1996, Tennessee filed tariff sheets to
comply with that order. No requests for a rehearing of that order were filed,
thereby concluding this proceeding with respect to Columbia Transmission.
B. Direct Billing of Past Period Production and
Production-Related Costs
Columbia Gas Transmission Corp. v. FERC, C.A. No. 94-1727 (U.S.
Ct. of App., D.C. Circuit). On February 9, 1990, the U.S. Court of Appeals for
the District of Columbia Circuit 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 violate 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 the rate recovery of the settlement payments to Columbia Transmission's
pipeline suppliers 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 a settlement with the fifth pipeline supplier,
Transcontinental Gas Pipeline Corporation ("Transco"), on February 13, 1995.
Columbia Transmission and its pipeline suppliers filed petitions for review of
the FERC's orders with the D.C. Court of Appeals.
In late 1995 and early 1996 new settlements were reached with
all pipeline suppliers except Transco, whereby the pipeline suppliers refunded
amounts previously billed to Columbia Transmission, plus interest. On September
10, 1996, the D.C. Circuit issued a decision which reversed a prior
determination by the FERC and directed that a previous settlement reached
between Columbia Transmission and Transco be approved. Reserves adequate in the
opinion of management were established in the third quarter of 1996 by Columbia
Transmission to reflect the court's decision. The matter was remanded to the
FERC, which issued its order on remand on January 21, 1997, approving the
settlement with Transco and ordering Columbia Transmission to refund to Transco
all amounts Transco had refunded to Columbia Transmission in excess of the
refunds required by the settlement, plus interest, within fifteen days of the
order.
On January 30, 1997, Columbia Transmission filed with the FERC
a request for rehearing and a request for deferral of action pending action by
the Bankruptcy Court. On the same day, Columbia Transmission filed with the
Bankruptcy Court its objection to Transco's bankruptcy claim for the refunds
paid to Columbia Transmission. Approximately $7 million (plus interest) is at
issue with Transco in this matter.
On February 28, 1997, the FERC granted Columbia Transmission's
request for rehearing, relieving it of the obligation to refund amounts to
Transco within 15 days of the order and requiring Columbia Transmission to
report any action taken by the Bankruptcy Court.
C. Transportation Costs Recovery Adjustment (TCRA)
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 30, 1995, the FERC accepted Columbia
Transmission's semi-annual filing to recover operational and stranded Account
No. 858 costs (including exit fees) paid to upstream pipelines, subject to
refund and conditions. However, Columbia Transmission was required to further
document and support why it was appropriate to recover an additional $39 million
of costs paid to Columbia Gulf Transmission Company ("Columbia Gulf"). An April
17, 1995 settlement approved by the FERC on June 15, 1995, in
10
<PAGE> 11
ITEM 3. LEGAL PROCEEDINGS (Continued)
Docket No. GP94-2, resolved all issues in this docket except Columbia
Transmission's recovery of costs paid to Columbia Gulf under the T-1 Rate
Schedule.
On April 2, 1996, the FERC issued an order ruling generally
that Columbia Gulf could bill the costs to Columbia Transmission and that
Columbia Transmission could recover the costs from its customers, and denying
all protests and denying UGI's request for a rehearing. The FERC did, however,
make recovery of operation and maintenance costs (approximately $19 million)
subject to the FERC's next audit of Columbia Gulf, and directed its staff to
audit Columbia Gulf's non-environmental costs to assure that they were
appropriately billed to Columbia Transmission. The FERC also established hearing
procedures concerning whether Columbia Gulf's environmental costs (approximately
$20 million) were prudently incurred. Two parties filed testimony on September
30, 1996 advocating, among other things, disallowance of recovery of certain
costs by Columbia Transmission. A hearing date is currently set for late March
1997.
III. Environmental
A. In re Marcor Environmental, Inc. v. Columbia Gas
Transmission Corp., (U.S. EPA Reg. III, No. CAA-III-055) (September 30, 1994).
As reported in the Quarterly Report on Form 10-Q for the second quarter of 1996,
Marcor has agreed to indemnify Columbia Transmission for all liabilities arising
from the complaint. Settlement was reached between EPA Region III and the
parties for a civil penalty of $40,000. The settlement was filed with the Chief
Administrative Law Judge on May 21, 1996. Therefore, this matter is concluded
with respect to Columbia Transmission.
B. Columbia Gas Transmission Corp. v. Aetna Casualty &
Surety Co., et al., C.A. No. 94-C-454 (Kanawha (W.Va.) Cir. Ct. March 14, 1994).
Columbia Transmission filed a complaint in West Virginia state court seeking
coverage from various insurers under various insurance policies for
environmental cleanup costs. These costs are discussed more fully in the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section of this Report. All insurers have responded to the complaint
denying such claims. The case is currently stayed under the evergreen provision
of the agreed scheduling order entered by the state court on November 29, 1995,
in order to allow informal discussions among the parties to the litigation. The
parties have also entered into an agreed order concerning a special discovery
master which was entered by the court.
C. Columbia Gulf Transmission Co. v. Aetna Casualty &
Surety Co., et al., C.A. No. 95-C-177 (Kanawha (W.Va.) Cir. Ct. January 19,
1995). Columbia Gulf filed a complaint in West Virginia state court seeking
coverage from various insurers under various insurance policies for
environmental cleanup costs. These costs are discussed more fully in the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section of this Report. All insurers have responded to the complaint
denying such claims. The case is currently stayed under the evergreen provision
of the agreed scheduling order entered by the state court on December 1, 1995,
in order to allow informal discussions among the parties to the litigation. The
parties have also entered into an agreed order concerning a special discovery
master which was entered by the court.
IV. Other
A. Canada Southern Petroleum Ltd. v. Columbia Gas
Development of Canada Ltd. (C.A. No. 9001-03466, Court of Queen's Bench,
Alberta, Canada, filed March 7, 1990). The 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' 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 plaintiff amended its 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. ("Anderson") effective
December 31, 1991.
11
<PAGE> 12
ITEM 3. LEGAL PROCEEDINGS (Continued)
A trial commenced in the third quarter of 1996 in the Court
of Queen's Bench, and has since been adjourned while the plaintiff sought to
have Amoco's counsel removed based upon a conflict of interest. At a hearing on
the matter, the court ruled against the plaintiff, and a subsequent appeal by
the plaintiff was dismissed. Due to the complex nature of the litigation,
Columbia cannot predict the length of the trial. Management continues to believe
that its defenses are meritorious, and that the risk of any material liability
to Columbia is de minimis.
Pursuant to an Indemnification Agreement regarding the
Kotaneelee Litigation entered into when Columbia Canada was sold to Anderson,
Columbia agreed to indemnify and hold Anderson harmless for losses due to this
litigation arising out of actions occurring prior to December 31, 1991. An
escrow account now funded by a letter of credit in the amount of approximately
$71,690,000 (Cdn) provides security for the indemnification obligation.
B. LG&E Natural Marketing Inc. v. Columbia Gulf
Transmission Co. and Columbia Gas Transmission Corp., Case No. 1:96CV02238 (U.S.
Dist. Ct. for the District of Columbia) and C.A. No. 96-CA07745 (Sup. Ct. of the
District of Columbia). On September 27, 1996, LG&E Natural Marketing Inc.
("LG&E") filed two similar complaints in the United States District Court for
the District of Columbia and in the Superior Court of the District of Columbia
(Civil Division). The complaints alleged that Columbia Transmission and Columbia
Gulf breached purported obligations to make certain pipeline transportation
capacity available to LG&E. The complaints sought $10 million under each of a
number of different counts and punitive and treble damages under some of them.
Both cases were dismissed without prejudice. The parties are discussing the
possibility of a mutually satisfactory business arrangement to resolve this
matter. Management believes that the complaints' claims, should they be
reasserted, do not represent a material exposure to Columbia.
C. Cathodic Protection. In September 1995, the management
of Commonwealth Gas Services, Inc. ("Commonwealth") advised the Staff of the
Virginia State Corporation Commission that there had been deficiencies in
Commonwealth's cathodically protected pipeline distribution system in its
Northern Operating Area in Virginia. Following several months of informal
investigation, on March 1, 1996 the Commission issued a subpoena for
Commonwealth to produce documents related to its cathodic protection program in
the Northern Operating Area. Commonwealth complied with the subpoena, and
continues to provide monthly reports to the Commission updating the status of
remedial work in the Northern Operating Area and annual test station monitoring.
Given the early status of this investigation, Columbia is unable to determine at
this time the likelihood or magnitude of any penalties that might be assessed.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of Columbia is traded on the New York Stock Exchange under the
ticker symbol CG and abbreviated as either ColumGas or ColGs in trading reports.
The number of shareholders of record on January 31,1997, was approximately
40,766 and the stock closed at $64.875, as reflected in the New York Stock
Exchange Composite Transactions as reported by The Wall Street Journal. On
February 19, 1997, Columbia declared a quarterly dividend of $0.15 per share for
the first quarter of 1997, payable on or about March 14, 1997, to holders of
record on March 3, 1997.
See Item 7 on page 20 for additional information regarding Columbia's common
stock prices and dividends.
12
<PAGE> 13
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
($ in millions except per share amounts) 1996 1995* 1994* 1993* 1992* 1991*
- - ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA ($)
Total operating revenues 3,354.0 2,635.2 2,747.1 3,313.8 2,859.2 2,463.7
Products purchased 1,481.1 820.6 984.2 1,577.7 1,236.9 1,056.5
Earnings (Loss) on common stock before
extraordinary item and accounting changes 221.6 (432.3) 246.2 152.2 90.9 (794.8)
Earnings (Loss) on common stock 221.6 (360.7) 240.6 152.2 51.2 (694.4)
- - ---------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Earnings (Loss) per common share ($):
Before extraordinary item and
accounting changes 4.12 (8.57) 4.87 3.01 1.79 (15.72)
Earnings (Loss) on common stock 4.12 (7.15) 4.76 3.01 1.01 (13.74)
Dividends:
Per share ($) 0.60 -- -- -- -- 1.16
Payout ratio (%) 14.6 N/A N/A N/A N/A N/A
Average common shares outstanding (000) 53,782 50,468 50,560 50,559 50,559 50,537
- - ---------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt
subject to Chapter 11:
Common stock equity 1,553.6 1,114.0 1,468.0 1,227.3 1,075.1 1,006.9
Preferred stock -- 399.9 -- -- -- --
Long-term debt 2,003.8 2,004.5 4.3 4.8 5.4 6.1
Short-term debt N/A N/A -- -- -- N/A
Current maturities of long-term debt 0.8 0.5 1.2 1.3 1.4 2.9
Debt subject to Chapter 11 -- -- 2,317.1 2,317.1 2,317.1 2,317.1
Total 3,558.2 3,518.9 3,790.6 3,550.5 3,399.0 3,333.0
Total assets 6,004.6 6,057.0 7,164.9 6,957.9 6,505.9 6,332.2
- - ---------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including
current maturities**):
Common stock equity 43.7 31.7 38.7 34.6 31.6 30.2
Preferred stock -- 11.4 -- -- -- --
Debt 56.3 56.9 61.3 65.4 68.4 69.8
Capital expenditures ($) 314.8 421.8 447.2 361.3 299.7 381.9
Net cash from operations ($) 462.7 (807.4) 572.8 850.4 765.4 531.6
Book value per common share ($) 28.11 22.07 29.03 24.27 21.26 19.92
Return on average common equity
before extraordinary item
and accounting changes (%) 16.6 (33.5) 18.3 13.2 8.7 N/A
- - ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
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 $982.9 million including write-off of
unamortized discounts on debentures, was recorded in the fourth quarter of 1995.
**Prior to 1991, Columbia made extensive use of variable rate debt since the
associated cost was normally less than senior long-term debt. Inclusion of the
short-term debt in years prior to 1991 makes those historical ratios more
meaningful.
13
<PAGE> 14
ITEM 6. SELECTED FINANCIAL DATA (Continued)
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
($ in millions except per share amounts) 1990 1989 1988 1987 1986
- - -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA ($)
Total operating revenues 2,346.7 3,189.3 3,157.5 2,855.7 3,407.7
Products purchased 846.8 1,669.0 1,822.3 1,534.2 2,002.9
Earnings (Loss) on common stock before
extraordinary item and accounting changes 104.7 145.8 119.0 111.3 99.4
Earnings (Loss) on common stock 104.7 145.8 111.1 100.5 75.3
- - -----------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Earnings (Loss) per common share ($):
Before extraordinary item and
accounting changes 2.21 3.21 2.46 2.30 2.12
Earnings (Loss) on common stock 2.21 3.21 2.46 2.30 1.82
Dividends:
Per share ($) 2.20 2.00 2.29 3.18 3.18
Payout ratio (%) 99.5 62.3 93.3 138.3 174.7
Average common shares outstanding (000) 47,316 45,494 45,190 43,763 41,436
- - -----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization including debt subject to Chapter 11:
Common stock equity 1,757.8 1,620.3 1,552.6 1,523.7 1,448.7
Preferred stock -- -- -- 110.0 115.0
Long-term debt 1,428.7 1,196.0 1,038.4 1,438.0 1,378.5
Short-term debt 735.5 634.2 697.1 327.5 393.4
Current maturities of long-term debt 35.2 47.2 52.7 69.6 432.5
Debt subject to Chapter 11 -- -- -- -- --
Total 3,957.2 3,497.7 3,340.8 3,468.8 3,768.1
Total assets 6,196.3 5,878.4 5,641.0 5,440.9 5,590.2
- - -----------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including short-term debt and current
maturities**):
Common stock equity 44.4 46.3 46.5 43.9 38.4
Preferred stock -- -- -- 3.2 3.1
Debt 55.6 53.7 53.5 52.9 58.5
Capital expenditures ($) 629.6 473.5 307.9 298.8 232.3
Net cash from operations ($) 420.1 400.5 429.4 702.0 550.5
Book value per common share ($) 34.83 35.50 34.18 34.08 34.06
Return on average common equity
before extraordinary item
and accounting changes (%) 6.2 9.2 7.7 7.5 6.9
- - -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
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 the fourth quarter of 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.
14
<PAGE> 15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
Index Page
- - ----------------------------------------------------
<S> <C>
Consolidated Review...................... 15
Liquidity and Capital Resources.......... 17
Transmission and Storage Operations...... 21
Distribution Operations.................. 27
Exploration and Production Operations.... 33
Marketing, Propane and Power Generation.. 36
Bankruptcy Matters....................... 39
- - ----------------------------------------------------
</TABLE>
Management's Discussion and Analysis contains "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934. Shareholders and prospective
shareholders should understand that several factors govern whether any
forward-looking statement contained herein will be or can be achieved. Any one
of those factors could cause actual results to differ materially from those
projected herein. These forward-looking statements include Columbia's plans,
objectives and expected performance, expenditures and recovery of expenditures
through rates. These forward-looking statements are based on assumptions that
management believes to be reasonable, however, there can be no assurance that
actual results will not differ materially. Realization of Columbia's objectives
and expected performance is subject to a wide range of risks and can be
adversely affected by, among other things, competition, weather, regulatory and
legislative changes as well as changes in general economic and capital market
conditions, many of which are beyond the control of Columbia.
CONSOLIDATED REVIEW
Net Income (Loss)
Columbia's 1996 net income was $221.6 million, or $4.12 per share, compared to a
net loss of $360.7 million, or $7.15 per share, last year which included pre-tax
interest expense of $983 million on prepetition debt that was recorded at
Columbia's emergence from bankruptcy in November 1995.
After adjusting for unusual items, net income for 1996 was $251.7 million, or
$4.68 per share, up $98.4 million, or more than 64%, over 1995's adjusted
results. Contributing to this improvement was the after-tax effect of nearly $45
million for higher rates for the regulated subsidiaries, $24 million
attributable to higher prices for gas production and $17 million resulting from
colder weather experienced primarily in early-1996. Also improving results were
lower operation and maintenance expenses, net of restructuring charges,
reflecting the efficiencies gained through recently implemented restructuring
initiatives.
Unusual and Bankruptcy Related Items
After-tax effect on Net Income
(in millions)
<TABLE>
<CAPTION>
Twelve Months
Ended December 31,
1996 1995
------- -------
<S> <C> <C>
Reported Net Income (Loss) $ 221.6 $(360.7)
Less (plus):
Bankruptcy related issues
Entries recorded at emergence, primarily interest costs -- (649.4)
Interest costs on prepetition debt not recorded -- 158.0
Professional fees and related expenses -- (26.8)
Adoption of SFAS No. 71 -- 71.6
Sale of Columbia Development 5.6 (54.8)
Restructuring-related costs (35.7) (3.8)
Other -- (8.8)
------- -------
Total adjustments (30.1) (514.0)
------- -------
Net Income after adjusting for unusual and bankruptcy items $ 251.7 $ 153.3
======= =======
</TABLE>
15
<PAGE> 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Unusual items in 1996 included $35.7 million for the after-tax effect of
restructuring costs, primarily for severance expense, that were incurred to
improve customer service and operating efficiencies. A second unusual item in
1996 was a $5.6 million improvement to net income for a favorable adjustment
from the sale of Columbia Gas Development Corporation (Columbia Development),
Columbia's southwest gas and oil subsidiary, that was sold effective year end
1995.
Adjustments for 1995 unusual items included after-tax expense of $518.2 million
related to bankruptcy issues, primarily for interest expense to settle
prepetition obligations; an improvement to net income of $71.6 million for the
readoption of an accounting standard pertaining to the accounting in a rate
regulated environment, Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71); $54.8
million to record the estimated after-tax loss on the sale of Columbia
Development; $3.8 million after-tax costs for restructuring activities and
after-tax expense of $8.8 million for miscellaneous other unusual items.
Revenues
Operating revenues for 1996 of $3,354 million, increased $718.8 million over
1995, reflecting, among other things, additional sales by Columbia Energy
Services Corporation, Columbia's marketing affiliate, and the distribution
subsidiaries. Also contributing to increased revenues were sharply higher gas
prices that increased both the gas commodity portion of the rates for the
distribution subsidiaries and prices received for gas production, as well as the
effect of colder weather experienced primarily in early 1996. In addition,
higher base rates in effect for the regulated subsidiaries provided an increase
to revenues of $68.7 million. In 1996, $13.9 million of the increase in revenues
over 1995 was due to surcharges that were offset in operating expense and had no
effect on income. Partially offsetting these improvements was the effect of the
sale of Columbia Development which had $96.1 million of revenues in 1995 and a
$12.2 million non-recurring increase in 1995 from exit fee payments received by
Columbia Gulf Transmission Company (Columbia Gulf).
In 1995 operating revenues decreased $111.9 million from 1994 due to lower
natural gas prices which reduced revenues for the distribution segment and
decreased the price received for gas produced. The decrease was partially offset
by both higher revenues from additional retail sales and higher rates in effect
for the non-gas portion of the sales rate for the distribution segment.
Improving 1995 operating revenues were the exit fee payments received by
Columbia Gulf and $10.3 million in surcharges that were offset in operating
expense.
Expenses
Operating expenses in 1996 of $2,875.8 million, increased $630.8 million over
1995. The higher expenses primarily reflected an increase of $660.5 million in
products purchased caused by additional volumes purchased to meet increased
sales requirements and higher gas prices. Also increasing operating expense was
$22.6 million higher operation and maintenance expense which included $54.9
million restructuring costs in 1996 and $5.8 million in 1995, expense of
approximately $13.9 million for surcharges that are offset in revenues, as
mentioned above. Prior year's expenses included $39.1 million of expenses
associated with Columbia Development's operations. After adjusting for
restructuring charges, operation and maintenance expenses were down by
approximately $30 million for 1996. Depreciation and depletion expense decreased
$54.8 million as a result of reduced depletable plant due to the sale of
Columbia Development and a lower depletion rate attributable to higher natural
gas prices, partially offset by additional plant in service and higher
depreciation rates for the regulated subsidiaries.
In 1995, operating expenses of $2,245 million were down $118 million from 1994
due largely to lower cost of gas for resale. Despite additional purchases
necessary to meet increased sales requirements, the cost of gas purchased in
1995 was lower than the year earlier by $163.6 million, reflecting lower average
prices. In 1995, operating and maintenance expense was $35.2 million higher than
the year earlier reflecting generally higher costs. Mitigating this increase was
the effect of a $19.1 million environmental reserve addition recorded in 1994.
Depreciation and depletion expense was also up $8.3 million due to additional
plant in service. Operating expense included $10.3 million that was offset by
revenue surcharges mentioned above.
16
<PAGE> 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Other Income (Deductions)
<TABLE>
<CAPTION>
Twelve Months Ended December 31,
(in millions) 1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Interest income and other, net $ 26.1 $ (58.2) $ 35.2
Interest expense and related charges (166.8) (988.4) (14.8)
Reorganization items, net -- 13.4 (12.3)
-------- --------- --------
Total Other Income (Deductions) $ (140.7) $(1,033.2) $ 8.1
======== ========= ========
</TABLE>
For the twelve months ended December 31, 1996, Other Income (Deductions) reduced
income $140.7 million, compared to a decrease to income of $1,033.2 million in
1995. Interest income and other, net of $26.1 million in 1996 primarily
reflected an adjustment of $8.6 million recorded in the second quarter of 1996
for the 1995 sale of Columbia Development; $5.6 million of interest earned on
certain tax issues, $3.3 million of interest income on temporary cash
investments and a $1.8 million gain on the sale of Columbia Gulf's interests in
the Overthrust pipeline partnership. Interest expense and related charges in
1996 reflected $140.4 million of interest expense on long-term debt and $11.7
million of interest expense on short-term debt obligations. Also included in
1996 interest expense was $3.9 million of interest on rate refunds recorded by
the rate regulated subsidiaries.
Other Income (Deductions) reduced income in 1995 by $1,033.2 million, whereas in
1994, income was improved $8.1 million. Interest expense and related charges for
1995 was $973.6 million higher than 1994 due primarily to bankruptcy-related
interest costs on prepetition debt obligations of $983 million recorded at
emergence. A $15.8 million reduction to a reserve for interest charges was
recorded in 1994 for an IRS settlement that was largely offset by $14.7 million
of interest expense associated with producer claims recorded in the same year.
The $93.4 million decrease for Interest income and other, net primarily
reflected an estimated loss of $77.8 million recorded in 1995 for the sale of
Columbia Development and an improvement of $21 million in 1994 for the reversal
of a reserve for carrying charges on exchange gas. Reorganization items, net
increased $25.7 million from the prior year due to $40 million recorded for the
principal portion of the producer claim reserve in 1994 and $30.1 million for
higher interest earned on cash accumulated during the Chapter 11 proceedings.
These improvements were offset by $44 million for bankruptcy-related emergence
adjustments as well as additional expense for professional fees and related
charges.
Income Taxes
Income tax expense in 1996 decreased income $115.9 million, whereas in 1995 when
a pre-tax loss was recorded, a tax benefit of $210.7 million was reflected. Tax
expense was $146 million in 1994. These changes between years were caused
principally by changes in pre-tax book income. (See Note 7 in Notes to
Consolidated Financial Statements for additional information.)
Extraordinary Items
In 1995, Columbia recorded an extraordinary after-tax gain of $71.6 million for
the cumulative adjustment for the reapplication of SFAS No. 71 for Columbia
Transmission and Columbia Gulf. The impact of the reapplication resulted 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 Federal Energy Regulatory Commission
(FERC) regulated transmission subsidiaries for the foreseeable future.
LIQUIDITY AND CAPITAL RESOURCES
Cash From Operations
A significant portion of Columbia's operations is 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
cash on hand, together with external financing as needed, is 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.
For the year ended December 31, 1996, net cash from operations was $462.7
million whereas in 1995, a cash deficit of $807.4 million was reported due to
cash paid to producers and other creditors on emergence from bankruptcy.
Included in the 1995 cash from operations was approximately $1.4 billion of cash
paid on emergence to satisfy allowed claims filed against Columbia and Columbia
Transmission. After adjusting the 1995 deficit for these emergence payments,
17
<PAGE> 18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
cash from operations in 1996 decreased $179.9 million from 1995. Reducing cash
was a lag in the recovery of gas costs by the distribution subsidiaries in the
current period, together with increased prepayments and the effect of a higher
average cost of gas placed in storage. The lag in recovering gas costs resulted
from the rise in prices during 1996 that exceeded the distribution subsidiaries'
current recovery levels. These higher costs will be recovered over the next
several months through future adjustments to the commodity portion of rates as
provided for under the regulatory process. Partially offsetting this decrease
was a working capital improvement of $271.5 million for income tax refunds that
resulted from the filing of Columbia's 1995 Federal Income Tax return that
included a net operating loss carryback claim to recover income taxes. Cash also
improved as a result of the favorable effect of colder weather that increased
sales for the distribution subsidiaries, as well as higher base rates in effect
for the regulated subsidiaries.
After adjusting the 1995 deficit for emergence issues, net cash from operations
was $73.1 million higher than 1994, primarily reflecting payments made in 1994
for Order 500/528 refunds. Cash from operations for both 1995 and 1994 was
affected by supplier refunds and payments made by Columbia Transmission.
Financing Activities
Columbia satisfies its liquidity requirements through internally generated funds
and the use of its $1 billion unsecured bank revolving credit facility (Credit
Facility). Columbia also may pursue obtaining additional short-term financing
through the use of bid notes and the establishment of a commercial paper
program.
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 and cash from bank borrowings under the
Credit Facility as discussed below, and cash on hand were used to settle claims
in accordance with approved plans of reorganization for Columbia and Columbia
Transmission. Maturities of the new debentures ranged from 5 to 30 years with an
average interest cost of approximately 7.03%. In February 1996, Columbia
redeemed the Series B - DECS and Series A - Preferred Stock as allowed under the
terms of Columbia's approved plan of reorganization. Permanent funding for the
preferred stock redemption was provided by $191 million received in April 1996,
from the sale of Columbia Development and approximately $240 million received
from the issuance of new common stock under a shelf registration statement, as
more fully described below.
Columbia's $1 billion Credit Facility provides for scheduled quarterly
reductions of $25 million of the aggregate committed amount starting December
31, 1997, that will reduce the Credit Facility commitments to $700 million by
September 30, 2000. The Credit Facility also provides for the issuance of up to
$150 million of letters of credit. As of December 31, 1996, Columbia had $250
million of borrowings and approximately $87 million of letters of credit
outstanding under the Credit Facility.
Interest rates on borrowings are based upon the London Interbank Offered Rate,
Certificate of Deposit rates or other short-term interest rates. Columbia is
required to pay a facility fee on the commitment amount at a rate based on
Columbia's public debt rating. The facility fee rate, as of December 31, 1996,
is 0.14%. Such rate would be reduced to 0.11% were Columbia to achieve a BBB+ or
Baa1 rating from Standard & Poor's or Moody's Investors Service, respectively.
Columbia has an effective shelf registration statement on file with the U. S.
Securities and Exchange Commission for the issuance of up to $1 billion in
aggregate of debentures, common stock or preferred stock in one or more series.
In March 1996, Columbia issued 5,750,000 shares of common stock under the shelf
registration and used the proceeds to reduce borrowings incurred under the
Credit Facility. No further issuances under the remaining $750 million are
scheduled at this time.
18
<PAGE> 19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Capital Expenditures
The table below reflects actual capital expenditures by segment for 1995 and
1996 and an estimate for 1997:
<TABLE>
<CAPTION>
(in millions) 1997 1996 1995
- - ----------------------------------------------------------------
<S> <C> <C> <C>
Transmission and Storage $269 $143 $172
Distribution 160 148 152
Exploration and Production 39* 12 87
Marketing, Propane and Power Generation 8 6 7
Corporate 14 6 4
- - ----------------------------------------------------------------
Total $490 $315 $422
- - ----------------------------------------------------------------
</TABLE>
* Does not reflect approximately $27 million for gathering facilities that
Columbia Transmission abandoned and transferred to Columbia Natural
Resources, Inc.
Columbia's 1996 capital expenditures were $315 million, a decrease of $107
million from 1995. The decrease primarily reflected lower expenditures for
exploration and production due to the sale of Columbia Development effective
December 31, 1995. The largest portion of the transmission and storage segment's
investments is 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.
Capital expenditures for 1997 are expected to increase $175 million to $490
million. This increase reflects $117 million of additional expenditures for
Columbia Transmission's market expansion program and higher expenditures for the
exploration and production segment as a result of the increased drilling
activity by Columbia Natural Resources, Inc. (Columbia Resources). Ongoing
replacement and upgrading of the distribution and pipeline facilities of
approximately $188 million will represent a significant portion of the 1997
program.
All discretionary capital expenditures are subject to Columbia's value added
approach (CVA), 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 employees to think in terms of value enhancement.
Restructuring Activities
In 1996, $60.9 million (pre-tax) of expense was recorded to reflect
reengineering-related costs, primarily for severance and benefits. Partially
offsetting this expense was a $6 million gain on the sale of the Wilmington,
Delaware, headquarters building. This reengineering initiative, called Project
Phoenix, began in 1995 to streamline operations and make them more efficient and
cost-competitive. As these reengineering activities continue into 1997,
additional expense will be incurred. The beneficial effect of any efficiencies
gained will be realized through improved profitability of Columbia's operations
and reduced rates being charged to customers of the regulated subsidiaries.
As indicated in the results of operations, Columbia is beginning to realize
lower operation and maintenance costs as a result of implementing these
reengineering initiatives in its various operations. It is anticipated that the
favorable effect of these initiatives will continue in the future as additional
phases of the program are implemented. Once the project is fully implemented,
which is expected by the end of 1997, the total number of employees System-wide
is anticipated to decrease by approximately 10% from the year-end 1995 level of
nearly ten thousand.
Reporting of Segment Results
Effective with this report the transmission segment has been renamed
Transmission and Storage Operations and now includes the results of Columbia LNG
Corporation (Columbia LNG) since its primary line of business is storage
services which are regulated by the FERC. Columbia LNG is a partner in Cove
Point LNG Limited Partnership (Cove Point LNG) which recently began commercial
operation of one of the largest natural gas peaking and storage facilities in
the United States located near Cove Point, Maryland. The facility liquefies
natural gas to meet winter peak day requirements of utilities and other large
gas users. Previously the results of Columbia LNG were included in Other Energy
Operations which has been renamed Marketing, Propane and Power Generation to
reflect the diverse energy-related operations of
19
<PAGE> 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
this segment of Columbia's business. Columbia's oil and gas segment has been
renamed Exploration and Production Operations.
COMMON STOCK PRICES AND DIVIDENDS
<TABLE>
<CAPTION>
Market Price
--------------------------- Quarterly
Quarter Ended High Low Close Dividends Paid
- - --------------------------------------------------------------
<S> <C> <C> <C> <C>
$ $ $ $
1996
December 31 66 1/4 56 63 5/8 .15
September 30 59 5/8 51 56 .15
June 30 52 1/8 43 3/4 51 7/8 .15
March 31 46 1/2 42 1/4 45 7/8 .15
- - --------------------------------------------------------------
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 --
- - --------------------------------------------------------------
</TABLE>
20
<PAGE> 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
TRANSMISSION AND STORAGE OPERATIONS
Marketing Initiatives
In January 1997, FERC issued a preliminary determination approving the
non-environmental portion of the expansion of Columbia Transmission's pipeline
and storage systems to serve the increasing needs of customers. Columbia
Transmission has signed 15-year agreements with 23 customers, subject to
Columbia Transmission obtaining regulatory approval of the project, for
approximately 500,000 Mcf per day (Mcf/d) of additional firm service to be
phased in over a three-year period beginning November 1, 1997. FERC approved
Columbia Transmission's request to roll the cost of the project into existing
rates rather than charge an incremental rate to the market expansion customers.
The project as approved includes a reduction to the project's initial estimated
$350 million cost to approximately $270 million, with no change in customer
service levels. The reduced cost reflects an agreement between Columbia
Transmission and Texas Eastern Transmission Corporation (Texas Eastern) under
which Texas Eastern will increase capacity on its Pennsylvania pipeline system
and provide the new capacity to Columbia Transmission. The environmental aspects
of the expansion project are pending before FERC and will be addressed in a
subsequent order. Final approval of Columbia Transmission's market expansion
application is anticipated by mid-1997.
Regulatory Matters
Columbia Transmission's Rate Filing
In August 1995, Columbia Transmission filed with FERC its first general rate
case since 1991. The filing requested an increase in annual revenues of
approximately $147 million and proposed to recover the net investment in
gathering and certain gas processing facilities over a period of five years.
In January 1997, the FERC administrative law judge presiding over the rate case
certified to FERC a settlement filed on November 22, 1996 by Columbia
Transmission. The settlement, which is supported by all of Columbia
Transmission's firm service customers, will resolve virtually all issues,
including rate design, cost of service, and the unbundling of gathering and
products extraction costs from Columbia Transmission's transportation rates.
Excluded from the settlement is the environmental cost recovery issue which is
scheduled to be addressed in a second phase of the proceeding. Pending the
outcome of that proceeding, Columbia Transmission will continue to collect
approximately $18 million per year, subject to refund, for environmental costs.
The certified settlement:
- - - establishes an annual cost-of-service level of $614 million, which is an
increase of $55 million (excluding $18 million for environmental cost
recovery) for the February 1996, through January 1997 period. This will
decrease to $602 million for the February 1997 through January 2000 period;
- - - provides for a moratorium on general rate increase filings through January
31, 2000 with certain limited exceptions;
- - - provides for the sharing of profits between Columbia Transmission and its
customers from the sale of certain amounts of storage base gas;
- - - provides for the unbundling of Columbia Transmission's gathering and gas
processing costs from transportation rates, that will be phased in
throughout the settlement period; and
- - - establishes the method by which Columbia Transmission will have the
opportunity to recover its investment in production-area facilities,
including the spindown of approximately 40% of Columbia Transmission's
gathering facilities to Columbia Resources.
The certified settlement is currently pending FERC review and approval, which is
anticipated in 1997.
Recovery of Columbia Gulf's Pre-November 1994 Transportation Costs
On March 1, 1995, Columbia Transmission filed with FERC to recover $69 million
of annual projected transportation costs and $39 million of unrecovered
transportation costs that were billed to Columbia Transmission by Columbia Gulf.
Several parties filed protests with FERC regarding the Columbia Gulf charges.
FERC subsequently ruled that approximately $19 million of the Columbia Gulf
charges were recoverable by Columbia Transmission, subject to a general FERC
audit, which is underway. The remaining $20 million of costs are associated with
environmental issues. FERC scheduled a hearing for the first quarter of 1997
concerning the recovery of such environmental costs.
Two parties filed testimony on September 30, 1996, advocating, among other
things, disallowance of recovery of certain costs by Columbia Transmission.
Responsive testimony has been filed by Columbia Transmission addressing each of
the proposed disallowances. While the outcome of the hearing is uncertain,
management believes Columbia Transmission has a valid basis for recovering these
costs. It is not expected that the outcome will have a material adverse impact
on Columbia's financial statements.
21
<PAGE> 22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Columbia Gulf Transmission's Rate Filing
On October 31, 1996, Columbia Gulf filed a general rate case with FERC that will
be effective May 1, 1997, subject to refund. A prior rate case settlement
required Columbia Gulf to file a new general rate case at this time. The filing
reflects a small increase of $0.9 million in the cost of service level and
addresses several rate design and cost allocation issues. On November 27, 1996,
the FERC accepted the filing subject to refund. The case has been assigned to an
administrative law judge for hearing.
Columbia Gulf Show Cause Proceeding
In its September 1993 order on Columbia Transmission's and Columbia Gulf's Order
No. 636 compliance filings, FERC initiated a proceeding concerning Columbia
Gulf's transportation service to Columbia Transmission. It directed Columbia
Gulf to show cause as to why it had not filed for FERC abandonment authorization
to reduce capacity on its mainline facilities. In a response to 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 FERC staff. Management continues to believe that no
abandonment filing was necessary; however, the ultimate outcome of this issue is
uncertain.
Partnership Issues
In late 1996, FERC approved a proposal by Columbia Gulf and its partners in the
Trailblazer Pipeline System, Northern Natural Gas Company and Natural Gas
Pipeline Company of America, to expand the eastern-most segment of the system.
The estimated $9 million expansion project includes installation of a
5,200-horsepower compressor to increase capacity along the 436-mile segment by
approximately 104,500 Mcf/d to a total volume of 492,000 Mcf/d. This additional
capacity is fully committed under precedent agreements for firm 10-year
contracts and should be available by August 1, 1997. This increased capacity
will allow producers to move Rocky Mountain natural gas to the Chicago area via
the Trailblazer System. The cost of the expansion is expected to lower
Trailblazer's rates by approximately 13 percent in the next rate case filing
which is anticipated to be filed in mid-1997. Columbia Gulf has a 33% ownership
interest in the Trailblazer Pipeline System.
In September 1996, Columbia Gulf recorded a gain of approximately $1.8 million
for the sale of its partnership interests in the Overthrust Pipeline System to
Questar Pipeline Company. Columbia Gulf held an 18% interest in the partnership
at the time of the sale. Columbia Gulf originally entered into the investment to
provide a gas supply source for Columbia Transmission. Under FERC Order No. 636,
Columbia Transmission discontinued its merchant function which eliminated its
need for this supply source.
Capital Expenditure Program
The transmission and storage segment's net capital expenditure program was
approximately $143 million in 1996 while its net capital expenditure program is
expected to be approximately $269 million in 1997. This included approximately
$9 million in 1996 and will include $126 million in 1997 for the market
expansion initiatives described previously. Other expenditures are for
modernizing and upgrading facilities.
Restructuring Activities
Columbia Transmission and Columbia Gulf began the Project Phoenix restructuring
project in early 1996 to streamline the business functions and improve
productivity by focusing on all processes within the transmission companies.
Implementation of key recommendations from the project began in 1996 and is
expected to be completed in stages throughout 1997.
Columbia Transmission also began the process of selling portions of its
gathering facilities as a result of FERC's Order No. 636, which requires natural
gas pipelines to unbundle their gathering costs and services from other
transportation costs. Approximately 3,000 miles of gas gathering lines will be
sold to Columbia Resources in mid-1997. Columbia Transmission has concluded an
open-bidding process for the remaining 3,600 miles of gathering lines.
Subsequent negotiations have resulted in various letters of intent for the sale
to various parties of certain of these gathering systems located in Ohio and
Pennsylvania (approximately 2,200 miles). It is likely that the facilities will
be sold before year-end 1997 to various purchasers and will result in
consolidation of some field operations and reductions in staffing levels.
As a result of these restructuring activities, expense of $24.6 million was
recorded in 1996, primarily for severance and benefits programs applicable to
staff level reductions.
22
<PAGE> 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Environmental Matters
Columbia's transmission subsidiaries have implemented programs to continually
review compliance with existing environmental standards. In addition, Columbia
Transmission continues to review past operational activities and to formulate
remediation programs where necessary. Columbia Transmission is currently
conducting assessment, characterization and remediation activity of specific
sites under a 1995 EPA Administrative Order by Consent (AOC).
In 1995, Columbia Transmission estimated that the cost of its 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 estimate did not include previously identified costs
for certain specific activities, aggregating approximately $50 million, for
which Columbia Transmission already had reasonable estimates.
Following an extensive review of assumptions utilized in arriving at the
estimate, 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 was not yet available. The nature and condition of such sites varies
greatly, and any change in any of the numerous assumptions used in the estimate
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 time frame and potential costs
of all site screening, characterization and remediation. As Columbia
Transmission continues its program pursuant to the AOC and costs become probable
and reasonably estimable, the associated reserves will be adjusted as
appropriate. 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, SFAS No. 5 and American Institute of Certified
Public Accountants Statement of Position 96-1.
Activities under the AOC in 1996 were focused on obtaining EPA approval to begin
the assessment and characterization of certain major facilities, some select
liquid removal points, and other select mercury measurement stations. In 1996,
the EPA authorized Columbia Transmission to begin the characterization of twelve
major facilities. Columbia Transmission expects EPA approval to begin
characterization of an additional 60 major facilities in 1997.
Columbia Transmission also continued to conduct assessment and remediation of
impacted soils at locations prior to normal construction and maintenance
activities under its EPA approved Construction and Operations Work Plan (COWP).
In 1996, Columbia Transmission conducted assessments at 216 sites and based on
these assessment results, performed remedial activities in varying degrees at
approximately 100 locations.
As a result of these 1996 activities, Columbia Transmission recorded in 1996 an
additional liability of $3.3 million in the fourth quarter and $2.5 million in
the second quarter. Actual expenditures of approximately $17 million during 1996
charged to the liability plus additions of nearly $6 million mentioned above
resulted in a remaining overall liability of $126 million. Columbia
Transmission's environmental cash expenditures are expected to be approximately
$18 million in 1997 and continue annually at that level for the foreseeable
future. These expenditures will be charged against Columbia Transmission's
previously recorded liability. Management does not believe that Columbia
Transmission's environmental expenditures will have a material adverse effect on
its operations, liquidity or financial position, based on known facts and
existing laws and regulations and the long period over which expenditures will
be made. In addition, as a result of reapplying SFAS No. 71 in 1995, a
regulatory asset has been recorded to the extent environmental expenditures are
expected to be recovered through rates. Columbia Transmission is also currently
involved in pursuing recovery of environmental expenditures from its insurance
carriers. At this time, management is unable to determine the extent, if any, of
recovery.
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.
23
<PAGE> 24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
From its investigations, Columbia Transmission is unable at this time to
determine if it will become liable for any characterization or remediation costs
at such sites.
Secondary Market Transactions
In 1996, FERC initiated a pilot program to assess the impact of lifting price
caps on secondary market transactions and selected Columbia Transmission and one
of its customers as potential participants. While Columbia Transmission was
prepared to proceed with the pilot, the distribution company chose to withdraw.
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). In 1995, Cove
Point LNG began commercial operation of one of the largest natural gas peaking
and storage facilities in the United States located near Cove Point, Maryland.
The facility has a capacity to liquefy natural gas at a rate of 15,000 Mcf/d and
stores the resulting liquefied natural gas (LNG) until needed for the winter
peak-day requirements of utilities and other customers. Cove Point LNG also owns
a pipeline system in Maryland and Northern Virginia that provides natural gas
transportation services.
In addition to its peaking and transportation operations, Cove Point LNG
maintains a currently inactive marine terminal capable of unloading LNG tankers.
Cove Point may reactivate the marine terminal at a future date if warranted by
market conditions and customer demand for its LNG and natural gas services.
Volumes
Columbia Transmission's throughput consists of transportation and storage
services for local distribution companies and other customers within its market
area. Throughput is recorded for market-area storage services as gas is
withdrawn from storage. Throughput for Columbia Gulf consists of mainline
transportation services from Louisiana to West Virginia and short-haul
transportation services from the Gulf of Mexico to Rayne, Louisiana.
Total throughput for the transmission and storage segment totaled 1,378.1 Bcf
for 1996, an increase of 41.9 Bcf over 1995 largely due to increased marketing
efforts on Columbia Gulf's system and increased demand resulting from the colder
weather in 1996. Total throughput for 1995 was 1,336.2 Bcf, an increase of 64.2
Bcf from 1994. This improvement reflected increased demand stemming from the
colder weather during the fourth quarter of 1995 and increased summer-related
requirements from electric cogeneration facilities.
Columbia Transmission's market area transportation is 3.7 Bcf lower in 1996
primarily due to additional transportation services utilized in the summer of
1995 and increased storage withdrawals in the last quarter of 1995 to meet
colder weather demands. Partially offsetting the decline was an increase in
transportation services due to the 14% colder weather in the first quarter of
1996. Market area transportation increased 67.5 Bcf in 1995 over 1994 due to the
impact of colder weather in 1995 which resulted in customers increasing
utilization of Columbia Transmission's transportation services.
Mainline transportation increased 28.7 Bcf in 1996 reflecting the impact of
colder weather during the 1995-1996 winter heating season which had the effect
of substantially depleting Columbia Transmission customers' storage inventories.
As a result, Columbia Gulf's mainline transportation services were heavily
utilized during the 1996 summer period to refill depleted gas inventories for
the 1996-1997 winter heating season.
An increase of 45.1 Bcf in short-haul transportation in 1996 reflected increased
production at Vermillion and Eugene Island as well as new sources of supply in
the Eugene Island, South Marsh Island and West Cameron areas. New
interconnections in Louisiana also contributed to the increase in throughput. In
1995, short-haul transportation was essentially unchanged from the prior year as
the impact of customers using facilities other than Columbia Gulf's to transport
gas requirements was offset by colder weather and additional natural gas
supplies available for transportation and increased marketing efforts.
Under Order 636, a significant portion of the transmission and storage segment's
fixed costs are being recovered through a monthly demand charge. As a result,
variations in throughput have little effect on income.
24
<PAGE> 25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Operating Revenues
Operating revenue for 1996 of $810.8 million increased $50.5 million over the
prior period. After adjusting for the recovery of upstream transportation costs
and certain other revenues that are fully offset in operating expense, current
period operating revenues increased $37.7 million. This increase was primarily
due to the new rates in place for Columbia Transmission effective February 1,
1996, subject to refund. Partially offsetting these improvements was the
recognition of $12.2 million in exit fees collected by Columbia Gulf during
1995.
Operating revenues for 1995 were relatively unchanged from 1994 at $760.3
million.
Operating Income
Operating income for 1996 decreased $5.2 million compared to 1995 to a level of
$207.8 million. Operating expenses increased $55.7 million in 1996 due in large
part to an increase of $29 million for restructuring charges, employee incentive
awards and items that had no effect on income. The non-income effecting items
are primarily costs that are allowed to be recovered in current rates as they
are incurred. The impacts of bankruptcy recorded in 1995, including an increase
in franchise taxes as a result of emergence, also contributed to the decline in
operating income. Partially offsetting these decreases was a $2.8 million
improvement in operating income for Columbia LNG, reflecting its first full year
of commercial operations.
Operating income for 1995 increased $3.3 million over 1994 to $213 million, due
in part to lower operating expenses of $1.7 million. Operating expenses were
higher in 1994 due to approximately $19.1 million for Columbia Gulf's
environmental accruals and $8 million in severance and relocation expense.
25
<PAGE> 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION AND STORAGE OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1996 1995 1994
- - ---------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Transportation revenues $629.0 $612.7 $650.7
Storage revenues 159.5 139.3 141.7
Other revenues 22.3 8.3 (33.7)
- - ---------------------------------------------------------------------
Total Operating Revenues 810.8 760.3 758.7
- - ---------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 444.1 392.5 391.1
Depreciation 102.6 103.8 103.9
Other taxes 56.3 51.0 54.0
- - ---------------------------------------------------------------------
Total Operating Expenses 603.0 547.3 549.0
- - ---------------------------------------------------------------------
OPERATING INCOME $207.8 $213.0 $209.7
- - ---------------------------------------------------------------------
</TABLE>
TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- - -----------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 142.7 172.5 179.1 137.2 114.2
- - -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
THROUGHPUT (Bcf)
Transportation
Columbia Transmission
Market area 1,102.4 1,106.1 1,038.6 895.9 909.0
Columbia Gulf
Main-line 633.7 605.0 590.3 579.9 574.3
Short-haul 266.5 221.4 225.4 258.1 258.3
Intrasegment eliminations (624.5) (596.3) (583.2) (561.7) (563.3)
- - -----------------------------------------------------------------------------------------------
Total Transportation 1,378.1 1,336.2 1,271.1 1,172.2 1,178.3
Sales -- -- 0.9 183.7 196.0
- - -----------------------------------------------------------------------------------------------
Total Throughput 1,378.1 1,336.2 1,272.0 1,355.9 1,374.3
- - -----------------------------------------------------------------------------------------------
</TABLE>
26
<PAGE> 27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
DISTRIBUTION OPERATIONS
Market Conditions
Weather during 1996 in the market area served by Columbia's distribution
companies (Distribution) was the coldest of the decade and the fifth coldest in
Distribution's history. Weather was 5% colder than 1995 and 6% colder than
normal, resulting in a 16 Bcf improvement over 1995 in Distribution's
weather-sensitive deliveries. While the economy in Distribution's service
territory remained strong, deliveries to industrial customers were down 6.6 Bcf,
or 3% from 1995. This throughput decline reflects reduced deliveries of
approximately 13.5 Bcf to low margin electric power generation customers who
switched to alternate fuels because of higher gas prices. Also, the mild summer
weather reduced air conditioning requirements. A labor strike, shutting down
production of a major customer, caused a 3.4 Bcf decline. Distribution added
about 22,000 net residential and commercial customers during the year, a 1%
growth rate which tracks previous year's growth.
Competition
Distribution competes with investor-owned, municipal, and cooperative electric
utilities throughout its five-state service area. Competition is generally
strongest in the residential and commercial markets of Kentucky, southern Ohio
and southwestern Pennsylvania where electric rates are driven by low-cost
coal-fired generation. Areas such as northern Ohio and Pittsburgh, Pa. have less
competitive electric rates, due to the use of higher-cost nuclear-generated
power. Distribution continues to capture a major portion of the energy market
for newly built homes as a result of a strong customer preference for natural
gas.
Approximately 40 percent of Distribution's industrial and commercial throughput,
or 128 Bcf, is susceptible to bypass, because these customers are geographically
located close to multiple natural gas pipelines and local gas distribution
companies. With the use of innovative rate and capacity release strategies and
the negotiation of unique customer arrangements, substantial inroads by other
natural gas competitors have been avoided to date. As a result of these actions,
the current estimated throughput exposure has been reduced to approximately 43
Bcf, representing about $11 million in annual net revenue.
Regulatory Matters
Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) 1994 rate case settlement
provided for a review of the company's revenue requirements by a group
comprising diverse interested parties, also known as the Collaborative, for the
purpose of evaluating the need to adjust base rates on May 1, 1996. The review
process was completed in late 1996 and resulted in the filing of two significant
pleadings with the Public Utilities Commission of Ohio (PUCO).
On October 17, 1996, Columbia of Ohio filed an application for approval of a
"Customer Choice" transportation program for residential and small commercial
customers. The application was approved by the PUCO in January 1997. The initial
program design includes options of unbundled services, permitting customers to
purchase gas directly from participating marketers. This program also provides
for the full recovery of stranded upstream pipeline supplier costs. The
tentative start date is April 1, 1997. The target location is the Toledo market
area which includes approximately 159,000 residential customers and 11,200 small
commercial customers. If successful, Columbia of Ohio hopes to expand the
"Customer Choice" program statewide over the next few years. The PUCO approved
the initial program for a one-year period. After a year, the PUCO will review
the program before approving a more permanent program.
On October 28, 1996, Columbia of Ohio filed an unopposed settlement with the
PUCO to resolve its revenue requirement. This filing was approved by the PUCO in
December 1996. The filing permits Columbia of Ohio to retain up to $51 million
of revenues over the next three years subject to a sharing mechanism, under
which a portion of any earnings above an industry composite allowed return on
equity would be shared with customers. The revenues retained are primarily from
off-system sales transactions completed or agreed to prior to August 31, 1996.
As allowed under this settlement, revenues of $11.5 million were recorded in
1996 income, with $19.7 million of revenues eligible for retention in both 1997
and 1998. This revenue mechanism is in lieu of a base rate increase and does not
result in any base rate increase for customers. Additionally, the settlement
provides that Columbia of Ohio will not implement any increase in base rates
before January 1, 1999.
In May 1996, legislation was enacted in Ohio that revised state laws governing
natural gas to allow for more competition among suppliers and more choices for
customers. Key provisions of this legislation deregulate the commodity sales of
gas under certain conditions and authorize the PUCO to establish rates by
non-traditional methods, e.g., indexed adjustments, automatic adjustments and
price path. The PUCO is required to adopt final regulations implementing the new
law early in 1997.
27
<PAGE> 28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
In August 1996, Columbia Gas of Pennsylvania, Inc. (Columbia of Pennsylvania)
received Pennsylvania Public Utility Commission (PPUC) approval of a residential
transportation rate schedule and a two-year residential transportation pilot
program. Under the pilot program, Columbia of Pennsylvania has assigned a
portion of its upstream pipeline capacity to the transportation customers' third
party suppliers thereby avoiding stranded upstream pipeline costs and the
shifting of such costs to sales customers. This program, which began in November
1996, is one of the largest pilot programs currently underway in the United
States. Columbia of Pennsylvania has more than 36,000 customers in Washington
County and the Borough of Pleasant Hills, with nearly 5,500 electing to
participate in the pilot program. A similar pilot program enlisting 10,000 of
Columbia of Pennsylvania's customers in Allegheny County may take effect in
November 1997.
In May 1996, the PPUC approved Columbia of Pennsylvania's request for a capacity
release incentive program. This program supplements Columbia of Pennsylvania's
existing off-system sales and gas procurement incentive programs.
In Virginia, the Virginia State Corporation Commission (VSCC) approved
Commonwealth Gas Services, Inc.'s (Commonwealth Services) rate case settlement
that was reached in early 1996. In addition to new rates designed to generate
additional gross annual revenues of $6.3 million, the settlement provided for a
separate proceeding to consider gas supply and other incentive proposals. A
hearing on these issues was held in September 1996 and the Hearing Examiner's
recommendation is expected in early 1997.
Commonwealth Services anticipates filing a general rate case in April 1997 to
recover increases in operating costs including an aggressive capital program to
upgrade facilities. Commonwealth Services is experiencing a growth rate three
times higher than its affiliated distribution companies. Also, Commonwealth
Services is evaluating a residential/small commercial transportation pilot
program. The pilot program would be filed with the VSCC to commence during 1997
and continue for a period of two years.
Columbia Gas of Maryland, Inc. (Columbia of Maryland) initiated a new
transportation program for smaller commercial and industrial customers that went
into effect in June 1996 on a pilot basis. Columbia of Maryland also received
approval from the Maryland Public Service Commission (MPSC) for a residential
transportation service pilot program which began in November 1996. Under the
two-year pilot program, Columbia of Maryland has assigned a portion of its
upstream pipeline capacity to the transportation customers' third party
suppliers thereby avoiding stranded upstream pipeline costs and the shifting of
such costs to sales customers. Discussions have begun for the next steps of
Columbia of Maryland's pilot transportation programs which propose changes to
give customers more options in capacity assignment.
In February 1996, the MPSC approved Columbia of Maryland's two-year pilot
programs to implement an off-system sales, a capacity release and a gas
procurement incentive program.
Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) received approval from the
Kentucky Public Service Commission to implement an off-system sales and capacity
release incentive plan on a two-year pilot basis effective August 1, 1996. Also,
Columbia of Kentucky increased annual revenues by $1.5 million, effective
October 1, 1996, through the implementation of the final phase of a three-step
increase as provided in its 1994 general rate case settlement.
Restructuring Activities
As previously reported, Distribution has initiated a restructuring of its
general office and field organizations as part of its ongoing efforts to improve
customer service and streamline operations. The restructuring activities, which
are part of Project Phoenix, allow the five distribution companies to operate as
individual business units and create a Shared Services Center in Columbus, Ohio,
to provide agreed-upon services to these companies. The new organization became
fully operational at the beginning of 1997. In connection with the program,
Distribution recorded $21.4 million of costs representing severance and related
benefit costs related to the elimination of about 400 management, professional
and administrative/technical employees. Commonwealth Services has deferred $1.4
million of these costs pending recovery in future rate proceedings. Any
additional charges or adjustments resulting from this program are not expected
to be significant.
Capital Expenditure Program
In addition to maintaining and upgrading facilities to assure safe, reliable and
efficient operation, Distribution's 1996 capital expenditure program of
approximately $148 million (a decline of $4 million from 1995) included
expenditures of $59 million for extending service to new areas and $71 million
for replacement and betterment projects. The estimated
28
<PAGE> 29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
1997 capital expenditure program amounts to approximately $160 million,
including $66 million for new business and development and $77 million for
replacement and betterment projects.
Gas Supply
Distribution's gas supply portfolio, with its large storage component, has the
reliability and flexibility to accommodate the impact of weather variations on
traditional customer demand as well as provide opportunities to increase
revenues through the gas incentive programs discussed earlier. Approximately 50%
of winter season demand comes from storage, 49% from firm interstate
transportation capacity, and one percent from peaking services utilized on the
coldest days. This capacity portfolio allows Distribution to purchase up to 65%
of its annual supply requirements during the lower demand summer season.
Off-system sales are sales or other transactions conducted outside of
Distribution's traditional market. For 1996, Distribution had off-system sales
and exchange volumes of approximately 18.5 Bcf resulting in pre-tax income of
$3.8 million, an increase of 11.2 Bcf and $3.4 million, respectively, from 1995.
This excludes $10.7 million in 1996 from Columbia of Ohio's recent rate
agreement.
As mentioned earlier, weather for calendar year 1996 was 5% colder than 1995 and
6% colder than normal. Throughout 1996, Distribution maintained full service to
firm sales customers without interruption. This colder weather increased the
utilization of Distribution's firm capacity portfolio to serve increased sales
customer demand and therefore reduced the amount of unused capacity available
for release. Proceeds from the release of temporarily unused capacity totaled
$14.2 million during 1996, a decrease of $0.2 million from 1995. Where capacity
release incentive program benchmarks are established, a portion of the proceeds
generated in excess of the benchmark provides income for Distribution. All other
proceeds are recorded as a reduction to gas costs. In 1996, both Columbia of
Pennsylvania and Columbia of Maryland were able to retain a small amount of
capacity release proceeds.
Environmental Matters
Distribution's environmental issues primarily relate to former manufactured gas
plant sites. Distribution previously reported that it had identified 14 former
gas plant sites for which it may have some liability for clean up. Distribution
is currently working with the appropriate regulatory agencies to formulate plans
to further investigate these sites. During 1996, a fifteenth formerly owned
manufactured gas plant site was identified. At this time, it is not possible to
estimate the costs associated with this additional site.
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.
Volumes
Distribution's throughput of 565 Bcf in 1996 reflected an 18.4 Bcf increase over
1995 as residential and commercial tariff sales rose 19 Bcf primarily due to
colder weather. Also contributing to the increase in throughput were continued
customer growth and higher off-system sales. Transportation volumes decreased
7.1 Bcf reflecting reduced requirements for power generation, the effect of
increased pressure from competitive fuels due to higher natural gas prices and
the impact of a labor strike which halted production of a major customer.
However, the economy in Distribution's service territories remained strong,
especially in the steel and oil refinery sectors, largely offsetting these
declines.
Distribution's 1995 throughput of 546.6 Bcf reflected an increase of 33.6 Bcf
over 1994 due to higher transportation deliveries, off-system sales, continued
customer growth and colder weather. Transportation deliveries were 23.4 Bcf
higher in 1995 due to strong economic conditions in Distribution's service area.
The 7.2 Bcf increase over 1994 in off-system sales reflected recent changes in
natural gas industry regulations.
Net Revenues
Net revenues for 1996 of $906.7 million were up $85.2 million over 1995. Colder
weather contributed $26 million to the increase in net revenues, higher rates
produced $21.2 million and Columbia of Ohio's retention of certain off-system
sales revenue resulted in another $10.7 million. Transportation revenues were up
$9.3 million, in spite of the throughput decline, as deliveries to higher margin
customers increased. Most of the remaining increase was attributable to customer
growth and higher revenue surcharges that are offset in expense.
29
<PAGE> 30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Net revenues of $821.5 million in 1995 were up $86.7 million due to higher rates
which generated additional revenues of $56.3 million and improved transportation
deliveries that contributed $14.3 million.
Operating Income
Operating income for 1996 of $226 million for Distribution increased $62.4
million over 1995, as the increase in net revenues was only partially offset by
an increase of $22.8 million in operating expenses. Included in the higher
operating expenses were restructuring costs which increased $21.1 million. All
other operation and maintenance expense decreased due to efficiencies and
modernization efforts recently implemented. Plant additions contributed to the
$3.5 million increase in depreciation expense while lower property taxes
resulted in a $0.7 million decline in taxes other than income.
Operating income for 1995 increased $35.3 million over 1994 as higher net
revenues were partially offset by increased operating expenses. Operating
expenses for 1995 were up approximately $51.4 million primarily due to costs
associated with computer applications, labor, and marketing and customer service
activities.
30
<PAGE> 31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1996 1995 1994
- - ---------------------------------------------------------------------------
<S> <C> <C> <C>
NET REVENUES
Sales revenues $2,007.9 $1,677.8 $1,741.9
Less: Cost of gas sold 1,206.4 952.2 1,088.6
- - ---------------------------------------------------------------------------
Net Sales Revenues 801.5 725.6 653.3
- - ---------------------------------------------------------------------------
Transportation revenues 119.8 105.3 88.8
Less: Associated gas costs 14.6 9.4 7.3
- - ---------------------------------------------------------------------------
Net Transportation Revenues 105.2 95.9 81.5
- - ---------------------------------------------------------------------------
Net Revenues 906.7 821.5 734.8
- - ---------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 463.0 443.0 404.0
Depreciation 74.4 70.9 64.5
Other taxes 143.3 144.0 138.0
- - ---------------------------------------------------------------------------
Total Operating Expenses 680.7 657.9 606.5
- - ---------------------------------------------------------------------------
OPERATING INCOME $ 226.0 $ 163.6 $ 128.3
- - ---------------------------------------------------------------------------
</TABLE>
31
<PAGE> 32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- - --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
CAPITAL EXPENDITURES ($ in millions) 148.4 151.8 151.4 117.8 99.7
- - --------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
Residential 209.4 196.6 189.7 194.7 186.2
Commercial 85.7 79.5 80.8 83.4 81.8
Industrial and Other 10.3 7.1 9.7 14.2 15.0
- - --------------------------------------------------------------------------------------------------------------
Total Sales 305.4 283.2 280.2 292.3 283.0
Transportation 248.8 255.9 232.5 217.5 203.7
- - --------------------------------------------------------------------------------------------------------------
Total Throughput 554.2 539.1 512.7 509.8 486.7
Off-System Sales 10.8 7.5 0.3 - -
- - --------------------------------------------------------------------------------------------------------------
Total Sold and Transported 565.0 546.6 513.0 509.8 486.7
- - --------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
Spot market* 298.7 210.4 235.3 142.3 169.9
Producers 47.9 70.9 67.5 56.9 57.1
Pipelines - - - 118.4 84.0
Storage withdrawals (injections) (20.8) 23.6 (14.0) (6.7) (10.7)
Company use and other (9.6) (14.2) (8.3) (18.6) (17.3)
- - --------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 316.2 290.7 280.5 292.3 283.0
Gas received for delivery
to customers 248.8 255.9 232.5 217.5 203.7
- - --------------------------------------------------------------------------------------------------------------
Total Sources 565.0 546.6 513.0 509.8 486.7
- - --------------------------------------------------------------------------------------------------------------
CUSTOMERS
Residential 1,815,269 1,794,800 1,764,968 1,737,609 1,711,946
Commercial 173,689 172,114 167,067 164,037 161,937
Industrial and Other 2,285 2,265 2,312 2,302 2,382
- - --------------------------------------------------------------------------------------------------------------
Total 1,991,243 1,969,179 1,934,347 1,903,948 1,876,265
- - --------------------------------------------------------------------------------------------------------------
DEGREE DAYS 5,975 5,692 5,530 5,677 5,507
- - --------------------------------------------------------------------------------------------------------------
</TABLE>
*Reflects volumes under purchase contracts of less than one year.
32
<PAGE> 33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
EXPLORATION AND PRODUCTION OPERATIONS
Market Conditions
Gas prices fluctuated considerably in 1996 but were generally much higher than
in 1995. The high prices experienced in the first half of 1996 weakened in the
third quarter due to mild temperatures, but rebounded sharply in December. As a
result of the sale of Columbia Development, effective December 31, 1995,
Columbia Resources is the remaining subsidiary in the exploration and production
(E&P) segment. Columbia Resources' natural gas prices averaged $2.84 per Mcf in
1996, compared with $2.19 per Mcf in 1995.
Fluctuations in gas prices can cause significant variations in revenues for the
E&P segment. To diminish the impact of these price swings and help stabilize
revenues, the E&P segment uses gas commodity futures and options contracts as
well as swap agreements to hedge the price risk for a portion of its production.
Internal guidelines prohibit speculative trading.
Capital Expenditure Program
Columbia Resources participated in the drilling of 45 gross (27 net) development
wells in 1996, with a success rate of 76%. A portion of the drilling operations
scheduled for 1996 was deferred until 1997 to permit time for management to
implement new strategies for its drilling program. These new strategies will
result in tighter scheduling and more concerted development activities which are
designed to lower average finding and development costs. The deferral of
drilling activity in 1996 also permitted Columbia Resources' management to
establish new processes necessary to allow for more aggressive drilling efforts
in 1997. The capital expenditure program for 1997, which is primarily for
drilling activities, is approximately $39 million compared to $12 million in
1996.
Gathering Facilities
On April 29, 1996, Columbia Transmission filed a request with FERC for
abandonment and transfer of certain gathering facilities to Columbia Resources.
Columbia Resources also requested FERC to disclaim jurisdiction over these
assets. Interventions and protests were subsequently filed by producers and
other interested parties. Columbia Resources has reached an agreement in
principle with the Independent Oil & Gas Association of West Virginia and
various Kentucky producers regarding rates and retainage to be charged for
gathering services on the facilities. This agreement covers a four-year period
commencing with the effective date of the transfer. Columbia Resources also has
reached separate agreements with local distribution companies served by these
facilities. FERC approval for the abandonment and transfer of these assets by
Columbia Transmission to Columbia Resources is expected by mid-1997.
Sale of Columbia Development
On April 30, 1996, (effective December 31, 1995) Columbia sold Columbia
Development to a privately-held concern for approximately $200 million. Columbia
Development had approximately 196 billion cubic feet equivalent of proved
natural gas and oil reserves located in the Gulf of Mexico and on-shore
continental United States. An estimated loss of $54.8 million after-tax was
recorded in the fourth quarter of 1995 to reflect the sale of this subsidiary.
In the second quarter of 1996, an adjustment was recorded that reduced the loss
to $49.2 million.
Reserves
Net proved gas reserves for 1996 totaled approximately 645 Bcf, an increase of
45 Bcf over 1995. This increase reflects additional reserves that are available
to be produced under current market conditions. In 1995, net proved gas reserves
totaled approximately 600 Bcf compared with 684 Bcf the year earlier, due to the
sale of Columbia Development.
Proved reserves for oil, condensate and natural gas liquids decreased from 1.7
million barrels at the end of 1995 to 0.8 million barrels at the end of 1996.
Merger of Columbia Coal Gasification Corporation
In July 1996, Columbia Coal Gasification Corporation was merged into Columbia
Resources in order to increase administrative and operating efficiencies.
Columbia Resources has initiated an auction of the coal assets acquired in this
merger which is projected to result in a sale during 1997.
Volumes
Gas production decreased 49% to 33.6 Bcf in 1996 due to the sale of Columbia
Development. After adjusting for this sale, gas production was essentially
unchanged. From 1994 to 1995, production volumes decreased 1.9% to 65.4 Bcf due
to normal production declines from onshore wells in the Southwest while gas
production in the Appalachian area was essentially unchanged.
33
<PAGE> 34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
Oil and liquids production decreased by 2.6 million barrels in 1996 due to the
sale of Columbia Development. After adjusting for this sale, oil and liquids
production was essentially unchanged. In 1995, oil and liquids production
declined 21.1% to 2.8 million barrels from 1994 due to decreases in onshore well
production and gas processing.
Operating Revenues
In 1996, operating revenues were $104.5 million, a decrease of $76.1 million
from 1995, reflecting the sale of Columbia Development. Gas revenues for
Columbia Resources increased $22 million, as a result of higher average prices.
Operating revenues of $180.6 million in 1995 were down $24.7 million from 1994
primarily due to lower gas prices and significantly lower oil and liquids
production in the Southwest.
Operating Income
Operating income in 1996 increased $26.3 million to $30 million primarily
reflecting the improvement in average gas prices over the past year. Operating
expenses in 1996 were $102.4 million lower than 1995 due to the sale of Columbia
Development at year end 1995 as well as reengineering initiatives implemented by
Columbia Resources that resulted in a 40% reduction in its administrative and
professional workforce. From 1994 to 1995, operating income had declined $26.9
million to $3.7 million as the result of lower operating revenues.
34
<PAGE> 35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM EXPLORATION AND PRODUCTION OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1996 1995 1994
- - -------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Gas $ 99.1 $134.4 $150.7
Oil and liquids 5.4 46.2 54.6
- - -------------------------------------------------------------------
Total Operating Revenues 104.5 180.6 205.3
- - -------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 37.0 79.6 76.9
Depreciation and depletion 28.8 86.9 86.2
Other taxes 8.7 10.4 11.6
- - -------------------------------------------------------------------
Total Operating Expenses 74.5 176.9 174.7
- - -------------------------------------------------------------------
OPERATING INCOME $ 30.0 $ 3.7 $ 30.6
- - -------------------------------------------------------------------
</TABLE>
EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS*
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- - ------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
CAPITAL EXPENDITURES ($ in millions) 12.1 86.8 101.6 95.1 70.8
- - ------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf) 644.5 599.5 683.8 697.0 779.5
Oil and Liquids (000 barrels) 774 1,651 12,255 12,792 14,650
- - ------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf) 33.6 65.4 66.7 71.5 69.2
Oil and Liquids (000 barrels) 281 2,849 3,611 3,603 3,061
- - ------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf)** 2.84 1.96 2.18 2.28 2.02
Oil and Liquids ($ per barrel) 19.07 16.17 15.09 16.17 18.20
- - ------------------------------------------------------------------------------------
</TABLE>
* Years 1992 through 1995 include operating results from Columbia Development
that was sold effective December 31, 1995.
** Includes the effect of hedging activities.
35
<PAGE> 36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
MARKETING, PROPANE AND POWER GENERATION
Marketing Initiatives
Columbia Energy Services Corporation (Columbia Energy) is Columbia's
nonregulated natural gas marketing company. It provides gas supply, fuel
management and transportation-related services to a diverse customer base,
including cogenerators, local distribution companies, industrial plants,
commercial businesses, joint marketing partners and residences. In 1996,
Columbia Energy made its residential debut in an unbundling pilot program in
Washington County, Pennsylvania. This first-time effort resulted in
approximately 5,000 residential customers for Columbia Energy.
Columbia Energy formed a wholly-owned subsidiary, Columbia Service Partners,
Inc. (Columbia Service) to provide a variety of nonregulated products and
services to both homeowners and businesses. The new company's initial focus is
on the energy-related needs of Distribution's customers. In the second quarter
of 1996, Columbia Service introduced Appliance Partner, a service which offers
customers prompt appliance repair from qualified independent contractors for a
monthly premium. Another service provided by Columbia Service, similar to
Appliance Partner, is Gas Line Guarantee. This service provides for repairs and
replacement of customer-owned gas service lines running from the street to the
house. Columbia Service has also initiated a billing insurance program, Payment
Partner, for customers within certain areas of Distribution's service territory.
As of year-end 1996, Columbia Service had nearly 26,000 customers among the
three programs. In the future, Columbia Service expects to complement these
services with warranty and energy management services to commercial and
industrial customers. These new programs are part of Columbia's ongoing effort
to become a full service provider of energy and energy-related services.
Columbia Network Services
In late 1996, Columbia formed Columbia Network Services Corporation (Columbia
Network), a wholly-owned subsidiary, to provide telecommunications and
information services. Columbia Network's primary focus is to assist personal
communications service (PCS) and other microwave radio service licensees in
locating and constructing antenna facilities as well as maintaining and managing
PCS sites for the licensees. In October 1996, Columbia Network entered into an
agreement with SABRE Decision Technologies (SDT), a division of The SABRE Group,
Inc. to jointly develop an electronic energy information system. During the
initial phase, a standardized electronic bulletin board (EBB) will be designed
for use by the natural gas industry. The EBB will implement FERC-mandated
business standards for electronic gas transportation transactions and provide a
single centralized interface that customers can utilize to conduct business with
a multitude of gas transportation service providers (TSPs). This type of system
is expected to reduce the overall transaction costs of trading and transporting
gas, support the standardization of gas transactions for the natural gas
industry, and allow TSPs to concentrate on their core businesses. Columbia
Network also plans to offer energy management services relating to the
collection and management of customer energy usage information. In addition,
these services may provide opportunities for real-time interactive
communications with customers with respect to a wide variety of information,
products, and services not exclusively energy-related.
Propane
The propane companies serve approximately 79,650 customers in parts of 10
eastern states and the District of Columbia. To increase profitability, the
propane operations continually seek opportunities to improve competitiveness and
expand services which may include acquisitions. During 1996, propane sales by
Columbia Propane Corporation and Commonwealth Propane, Inc. (Commonwealth
Propane) totaled 75.9 million gallons, an increase of 7 million gallons over
1995.
Cogeneration
Columbia is part owner in three 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 approximately 250 megawatts. A fourth project, the Binghamton Cogeneration
Partnership, terminated operations and the power agreement was sold in early
1997. TriStar's primary focus has been the development, ownership and operation
of natural gas-fueled cogeneration power plants selling electric power to local
electric utilities under long-term contract.
TriStar's strategic objective is to develop and/or acquire efficient, natural
gas-fired merchant generating capacity throughout and close to Columbia's
service territories. This will allow TriStar to maximize the synergism afforded
by the System's fuel supply capabilities of Columbia's subsidiaries. Management
believes ownership of these
36
<PAGE> 37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
generating assets will add value by complementing Columbia's growth as an
integrated energy supply company by ensuring Columbia's customers access to
reliable, low cost electric energy.
Commodity Hedging
Columbia Energy and Commonwealth Propane use commodity futures to hedge prices
on commitments for natural gas purchases and sales and propane inventories.
Internal guidelines prohibit speculative trading.
Columbia Energy uses commodity futures contracts and basis swaps to assure
acceptable margins on the purchase and resale of natural gas in future months.
When Columbia Energy 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.
Net Revenues
Net revenues for 1996 increased $9.6 million over 1995 primarily reflecting the
favorable effect of colder weather on the various energy-related operations. Net
revenues from gas marketing activities increased $9.4 million due largely to
sales volumes that almost doubled. Propane operations also experienced an
increase of 10% in volumes sold in 1996 which led to the $2.8 million increase
in net revenues. Net revenues in 1996 from power generation activities were
essentially unchanged from 1995.
There was no change in net revenues between 1995 and 1994 as a small increase in
gas marketing was offset by lower propane and other revenues.
Operating Income
Operating income in 1996 increased a modest $0.3 million over the prior year.
The impact on net revenues of increased gas marketing sales was partially offset
by higher operating expenses due to the startup of Columbia Service and costs
associated with business expansion. The increase in net revenues resulting from
higher gas marketing and propane sales was also tempered by restructuring
expenses and incentive awards.
The $2.6 million decrease in operating income in 1995 to $12.2 million reflected
higher operating expenses for propane operations. Operating income for gas
marketing services was relatively unchanged from the previous year.
37
<PAGE> 38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM MARKETING, PROPANE
AND POWER GENERATION (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1996 1995 1994
- - ------------------------------------------------------------------
<S> <C> <C> <C>
NET REVENUES
Gas marketing revenues $728.0 $237.9 $232.1
Less: Products purchased 711.5 230.8 225.3
- - ------------------------------------------------------------------
Net Gas Marketing Revenues 16.5 7.1 6.8
- - ------------------------------------------------------------------
Propane revenues 80.7 65.1 63.2
Less: Products purchased 48.3 35.5 33.4
- - ------------------------------------------------------------------
Net Propane Revenues 32.4 29.6 29.8
- - ------------------------------------------------------------------
Other revenues 7.7 10.3 10.4
- - ------------------------------------------------------------------
Net Revenues 56.6 47.0 47.0
- - ------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 38.8 29.7 27.3
Depreciation and depletion 3.1 2.6 2.3
Other taxes 2.2 2.5 2.6
- - ------------------------------------------------------------------
Total Operating Expenses 44.1 34.8 32.2
- - ------------------------------------------------------------------
OPERATING INCOME $ 12.5 $ 12.2 $ 14.8
- - ------------------------------------------------------------------
</TABLE>
MARKETING, PROPANE AND POWER GENERATION OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- - --------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
CAPITAL EXPENDITURES ($ in millions) 6.3 6.6 4.7 9.7 8.7
- - --------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions) 75.9 68.9 68.5 58.1 63.3
Customers 79,650 74,308 68,218 67,895 65,899
- - --------------------------------------------------------------------------------------
</TABLE>
38
<PAGE> 39
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 Gas
Transmission Corporation (Columbia Transmission), emerged from Chapter 11
protection of the Federal Bankruptcy Code under the jurisdiction of the United
States Bankruptcy Court for the District of Delaware (Bankruptcy Court). Both
Columbia and Columbia Transmission had operated under Chapter 11 protection
since July 31, 1991. Certain unresolved bankruptcy-related matters are still
within the jurisdiction of the Bankruptcy Court.
Unsettled Producer Claims
Columbia Transmission's approved plan of reorganization (Plan) provided that
producers who rejected settlement offers contained in the Plan may continue to
litigate their claims under the Bankruptcy Court approved claims estimation
procedures discussed below. If and when these claims are ultimately allowed, the
producers will receive the same percentage payout on their allowed claims that
other settling producers have received. Under the terms of the Plan, the actual
distribution percentage for all producer allowed claims over $25,000 will not be
less than 68.875% or greater than 72.5%. The exact distribution percentage will
depend on the level of aggregate allowed producer claims. Until the total amount
of contested producer claims is established, 5% of the maximum 72.5% payout to
be distributed to producer claimants for allowed claims and to Columbia for its
unsecured debt claim will be withheld. Additional distributions, if any, will be
made once the total amount of allowed producer claims has been determined.
Producer Claims Estimation Process
In 1992, the Bankruptcy Court approved both the appointment of a claims
mediator, and the implementation of a claims estimation procedure for the
quantification of claims arising from Columbia Transmission's rejection of
above-market gas purchase contracts and other claims by producers related to gas
purchase contracts. In late 1994 and early 1995, the claims mediator issued
Initial and Supplemental Reports on Generic Issues for Natural Gas Contract
Claims and directed producer claimants to submit recalculated claims
incorporating the recommendations and instructions. The recommendations and
instructions set out in the reports have not been considered by the Bankruptcy
Court. In mid-1995 most producers, with which Columbia Transmission had not yet
negotiated settlements, submitted recalculated claims to the claims mediator
amounting to over $2 billion in aggregate. Since mid-1995, additional producers
have settled their claims or resolved them by means of litigation within the
claims estimation process and virtually all of these claims have been allowed by
the Bankruptcy Court at their litigated or settled level. As of the end of
February 1997, approximately $156 million in recalculated claims remain to be
settled.
The claims estimation procedures remain in place for use in the
post-confirmation liquidation of unresolved producer claims. The claims mediator
is holding evidentiary hearings with respect to individual producer claims,
including claim-specific issues not addressed by the reports. Recommendations
made by the claims mediator are subject to review by the Bankruptcy Court, and
all parties have rights of appellate review. When claims are allowed by the
Bankruptcy Court and the allowances become final, Columbia Transmission will
make distributions with respect to those claims pursuant to the Plan. The timing
of this on-going litigation process is impossible to predict. Any distributions
on producer claims ultimately liquidated in an aggregate amount in excess of
those proposed by the Plan will be funded, to the extent necessary, by the 5%
holdback from resolved producers and a matching contribution by the reorganized
Columbia Transmission. If the holdback and matching contributions are exhausted,
any further distribution would be funded entirely by Columbia Transmission.
Columbia has guaranteed the payments to producers in cash or in Columbia common
stock if the holdback amounts are exhausted. Based on the information received
and evaluated to date, Columbia Transmission believes adequate reserves have
been established for resolution of the remaining producer claims and the payment
of any amounts which may ultimately become due to producers with respect to the
5% holdback.
39
<PAGE> 40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
- - -----------------------------------------------------------
Index Page
- - -----------------------------------------------------------
<S> <C>
Report of Independent Public Accountants.............. 41
Statements of Consolidated Income..................... 42
Consolidated Balance Sheets........................... 43
Statements of Consolidated Cash Flows................. 45
Statements of Consolidated Common Stock Equity........ 46
Notes to Consolidated Financial Statements............ 47
Schedule II - Valuation and Qualifying Accounts....... 74
- - -----------------------------------------------------------
</TABLE>
40
<PAGE> 41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
As discussed in Note 6B, 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
January 27, 1997
41
<PAGE> 42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31 (in millions except per share amounts) 1996 1995* 1994*
- - ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Gas sales $ 2,679.4 $ 1,929.0 $ 2,031.3
Transportation 491.3 487.7 505.7
Other 183.3 218.5 210.1
- - ----------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,354.0 2,635.2 2,747.1
OPERATING EXPENSES
Products purchased 1,481.1 820.6 984.2
Operation 854.5 826.7 774.4
Maintenance 111.4 116.6 133.7
Depreciation and depletion 215.2 270.0 261.7
Other taxes 213.6 211.1 209.0
- - ----------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,875.8 2,245.0 2,363.0
Operating Income 478.2 390.2 384.1
- - ----------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
Interest income and other, net (Note 15) 26.1 (58.2) 35.2
Interest expense and related charges** (Note 16 ) (166.8) (988.4) (14.8)
Reorganization items, net (Note 2C) -- 13.4 (12.3)
- - ----------------------------------------------------------------------------------------------------------
Total Other Income (Deductions) (140.7) (1,033.2) 8.1
- - ----------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES, EXTRAORDINARY
ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE
337.5 (643.0) 392.2
Income taxes (Note 7) 115.9 (210.7) 146.0
- - ----------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 221.6 (432.3) 246.2
Extraordinary item (Note 6A) -- 71.6 --
Cumulative effect of change in accounting for
postemployment benefits (Note 6B) -- -- (5.6)
- - ----------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 221.6 $ (360.7) $ 240.6
- - ----------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
(based on average shares outstanding)
Before extraordinary item and accounting change $ 4.12 $ (8.57) $ 4.87
Extraordinary item -- 1.42 --
Change in accounting for postemployment benefits -- -- (0.11)
- - ----------------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock $ 4.12 $ (7.15) $ 4.76
- - ----------------------------------------------------------------------------------------------------------
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.60 $ -- $ --
- - ----------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS) 53,782 50,468 50,560
- - ----------------------------------------------------------------------------------------------------------
</TABLE>
* Reference is made to Note 2 of Notes to Consolidated Financial Statements.
** Due to the bankruptcy filings, interest expense of approximately $230
million was not recorded in 1994 (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.
42
<PAGE> 43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Assets as of December 31 (in millions) 1996 1995*
- - -----------------------------------------------------------------------------------------
<S> <C> <C>
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant, at original cost $6,994.4 $6,903.2
Accumulated depreciation and depletion (3,344.5) (3,322.0)
- - -----------------------------------------------------------------------------------------
Net Gas Utility and Other Plant 3,649.9 3,581.2
- - -----------------------------------------------------------------------------------------
Gas and oil producing properties, full cost method 502.8 516.3
Accumulated depletion (146.4) (141.1)
- - -----------------------------------------------------------------------------------------
Net Gas and Oil Producing Properties 356.4 375.2
- - -----------------------------------------------------------------------------------------
Net Property, Plant and Equipment 4,006.3 3,956.4
- - -----------------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
Accounts receivable - noncurrent 6.3 91.2
Unconsolidated affiliates 69.0 78.2
Assets held for sale 12.1 182.8
Other 15.9 2.4
- - -----------------------------------------------------------------------------------------
Total Investments and Other Assets 103.3 354.6
- - -----------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 49.8 8.0
Accounts receivable
Customers (less allowance for doubtful accounts of $16.2
and $12.3, respectively) 562.2 429.2
Other 35.4 81.8
Income tax refund -- 271.5
Gas inventory 237.8 172.3
Other inventories - at average cost 45.1 41.5
Prepayments 73.8 56.9
Regulatory assets 63.4 76.5
Underrecovered gas costs 104.7 0.2
Prepaid property tax 81.1 77.1
Exchange gas receivable 114.6 20.6
Other 68.0 40.3
- - -----------------------------------------------------------------------------------------
Total Current Assets 1,435.9 1,275.9
- - -----------------------------------------------------------------------------------------
REGULATORY ASSETS 410.1 422.0
DEFERRED CHARGES 49.0 48.1
- - -----------------------------------------------------------------------------------------
TOTAL ASSETS $6,004.6 $6,057.0
- - -----------------------------------------------------------------------------------------
</TABLE>
*Reference is made to Note 2 of Notes to Consolidated Financial Statements.
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
43
<PAGE> 44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
Capitalization and Liabilities as of December 31 (in millions) 1996 1995*
- - ---------------------------------------------------------------------------------------
<S> <C> <C>
COMMON STOCK EQUITY
Common stock, par value $10 per share - issued 55,263,659
and 50,620,180 shares, respectively $ 552.6 $ 506.2
Additional paid in capital 743.2 595.8
Retained earnings 259.3 69.8
Unearned employee compensation (1.5) --
Cost of treasury stock (1,416,155 shares) -- (57.8)
- - ---------------------------------------------------------------------------------------
Total Common Stock Equity 1,553.6 1,114.0
PREFERRED STOCK (Note 10) -- 399.9
LONG-TERM DEBT (Note 11) 2,003.8 2,004.5
- - ---------------------------------------------------------------------------------------
Total Capitalization 3,557.4 3,518.4
- - ---------------------------------------------------------------------------------------
CURRENT LIABILITIES
Short-term debt (Note 12) 250.0 338.9
Accounts and drafts payable 348.6 215.7
Accrued taxes 142.6 271.3
Accrued interest 14.8 94.3
Estimated rate refunds 114.0 96.1
Estimated supplier obligations 115.1 178.3
Overrecovered gas costs -- 41.7
Transportation and exchange gas payable 95.4 46.7
Other 371.1 295.6
- - ---------------------------------------------------------------------------------------
Total Current Liabilities 1,451.6 1,578.6
- - ---------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Deferred income taxes - noncurrent 557.7 468.6
Investment tax credits 37.1 38.6
Postretirement benefits other than pensions 172.3 208.2
Regulatory liabilities 44.5 44.9
Other 184.0 199.7
- - ---------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits 995.6 960.0
- - ---------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2, 3 and 14) -- --
- - ---------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $6,004.6 $6,057.0
- - ---------------------------------------------------------------------------------------
</TABLE>
44
<PAGE> 45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1996 1995* 1994*
- - -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income (loss) $ 221.6 $ (360.7) $ 240.6
Adjustments for items not requiring (providing) cash:
Depreciation and depletion 215.2 270.0 261.7
Deferred income taxes 78.1 66.1 72.2
Reapplication of SFAS 71 -- (71.6) --
Loss on sale of Columbia Gas Development Corp. -- 77.8 --
Interest expense settled at emergence -- 702.9 --
Payment of Chapter 11 liabilities -- (1,169.1) --
Other - net** (10.8) (94.0) (19.4)
Changes in components of working capital:
Accounts receivable (64.3) 99.7 135.9
Income tax refunds 271.5 -- --
Gas inventory (65.6) 58.0 (32.5)
Prepayments (16.3) 12.3 (8.0)
Accounts payable 160.8 38.3 (35.5)
Accrued taxes (85.5) (314.9) 45.7
Accrued interest (71.5) (56.5) --
Estimated rate refunds 17.8 (56.6) (133.3)
Estimated supplier obligations (63.2) (44.0) (49.7)
Under/Overrecovered gas costs (146.3) (18.0) 106.7
Exchange gas payable 46.9 10.4 (31.7)
Other working capital (25.7) 42.5 20.1
- - -----------------------------------------------------------------------------------------------------------
Net Cash From Operations 462.7 (807.4) 572.8
- - -----------------------------------------------------------------------------------------------------------
Investment Activities
Capital expenditures (316.4) (411.0) (433.6)
Proceeds received on the sale of Columbia Gas Development Corp. 187.8 -- --
Sale of partnership interest 2.7 10.9 --
Other investments - net 14.3 25.2 (1.3)
- - -----------------------------------------------------------------------------------------------------------
Net Investment Activities (111.6) (374.9) (434.9)
- - -----------------------------------------------------------------------------------------------------------
Financing Activities
Retirement of prepetition debt obligations -- (637.3) --
Retirement of preferred stock (400.0) -- --
Dividends paid (32.2) -- --
Issuance of common stock 250.8 1.8 --
Net increase (decrease) in short-term debt (88.9) 338.9 --
Other financing activities (39.0) 5.1 3.5
- - -----------------------------------------------------------------------------------------------------------
Net Financing Activities (309.3) (291.5) 3.5
- - -----------------------------------------------------------------------------------------------------------
Increase (Decrease) in cash and temporary cash investments 41.8 (1,473.8) 141.4
Cash and temporary cash investments at beginning of year 8.0 1,481.8 1,340.4
- - -----------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 49.8 $ 8.0 $1,481.8
- - -----------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid for interest 80.8 284.9 0.8
Cash paid for income taxes (net of refunds) (93.4) 42.3 37.4
- - -----------------------------------------------------------------------------------------------------------
</TABLE>
* 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) million in 1995 and $61.1 million in 1994. The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
45
<PAGE> 46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
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
- - -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
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
Net Income 221.6 221.6
Cash Dividends:
Common Stock (32.1) (32.1)
Common stock issued:
Public Offering 5,750 43.3 57.8 137.5 238.6
Long-Term Incentive Plan 310 3.1 9.9 (1.5) 11.5
- - -------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1996 55,264 $ 552.6 $ -- $ 743.2 $ 259.3 $ (1.5) $1,553.6
- - -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
*100 million shares authorized at December 31, 1996, 1995, 1994 and 1993 - $10
par value. The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
46
<PAGE> 47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Notes To Consolidated Financial Statements
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
the accounts of The Columbia Gas System, Inc. (Columbia) and all
subsidiaries. All intercompany accounts and transactions have been
eliminated. Certain reclassifications have been made to the 1995 and 1994
financial statements to conform to the 1996 presentation.
B. CASH AND CASH EQUIVALENTS. Columbia considers all highly liquid short-term
debt instruments to be cash equivalents.
To settle its Chapter 11 prepetition obligations in 1995, Columbia
distributed approximately $3.6 billion to its creditors. This settlement
distribution included $2.3 billion for Columbia's prepetition debt and
approximately $1 billion for interest on that debt. It was funded by $2
billion in new long-term debt securities, $1 billion in cash, which
included cash on hand, $0.4 billion of new bank debt, and $0.2 billion in
Redeemable Preferred Stock, Series A (Series A - Preferred Stock) and $0.2
billion in Convertible Preferred Stock, Series B (Series B-DECS). The
issuance of these securities represented non-cash financing activities. In
February 1996, Columbia redeemed the Series A-Preferred Stock and Series
B-DECS as allowed under the terms of Columbia's approved plan of
reorganization.
C. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS No. 71), provides that rate-regulated
public utilities account for and report assets and liabilities consistent
with the economic effect of the way in which regulators establish rates,
if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it
reasonable to assume that such rates can be charged and collected. As more
fully discussed in Note 6A, Columbia's transmission subsidiaries reapplied
the provisions of SFAS No. 71 during 1995, concurrent with the emergence
from Chapter 11 protection. Columbia's gas distribution subsidiaries have
been following and continue to follow the accounting and reporting
requirements of SFAS No. 71.
Certain expenses and credits subject to utility regulation or rate
determination normally reflected in income are deferred on the balance
sheet and are recognized in income as the related amounts are included in
service rates and recovered from or refunded to customers. Condensed
information for assets and liabilities subject to utility regulation and
rate determination are as follows:
<TABLE>
<CAPTION>
Transmission Distribution
Subsidiaries Subsidiaries
At December 31 ($ in millions) 1996 1995 1996 1995
- - ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
ASSETS
Environmental costs 123.6 132.5 7.1 8.2
Postemployment and postretirement benefits 69.4 76.4 129.9 138.0
Percent of income plan receivables -- -- 17.9 16.5
Retirement income plan costs 21.4 14.6 20.2 17.8
Regulatory effects of accounting for income taxes -- -- 49.0 50.9
Post in-service carrying charges -- -- 18.9 24.4
Underrecovered gas costs -- -- 104.7 --
Other 9.9 9.3 6.3 9.9
- - ----------------------------------------------------------------------------------------------------------------------
Total regulatory assets 224.3 232.8 354.0 265.7
- - ----------------------------------------------------------------------------------------------------------------------
LIABILITIES
Rate refunds and reserves 95.5 36.0 18.4 60.1
Overrecovered gas costs -- -- -- 41.7
Regulatory effects of accounting for income taxes 21.5 23.4 25.2 25.5
Other 6.8 5.2 -- --
- - ----------------------------------------------------------------------------------------------------------------------
Total regulatory liabilities 123.8 64.6 43.6 127.3
- - ----------------------------------------------------------------------------------------------------------------------
</TABLE>
47
<PAGE> 48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
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 subsidiaries
includes an allowance for funds used during construction (AFUDC).
Property, plant and equipment of other subsidiaries includes interest
during construction (IDC). The 1996 before-tax rates for AFUDC and IDC
were 6.15 percent and 6.9 percent, respectively. The 1995 and 1994
before-tax rates for AFUDC and IDC were 8 percent and 9.6 percent,
respectively.
Improvements and replacements of retirement units are capitalized at cost.
When units of property are retired, the accumulated provision for
depreciation is charged with the cost of the units and the cost of
removal, net of salvage. Maintenance, repairs and minor replacements of
property are charged to expense. Columbia's subsidiaries provide for
annual depreciation on a composite straight-line basis.
The average annual depreciation rate for the transmission subsidiaries'
property was 2.5 percent in 1996, 2.6 percent in 1995 and 2.7 percent in
1994. The average annual depreciation rate for the distribution
subsidiaries' property was 3.4 percent in 1996 and 3.3 percent in 1995 and
1994.
E. GAS AND OIL PRODUCING PROPERTIES. Columbia's subsidiaries engaged in
exploring for and developing gas and oil reserves follow the full cost
method of accounting. Under this method of accounting, all productive and
nonproductive costs directly identified with acquisition, exploration and
development activities including certain payroll and other internal costs
are capitalized. Depletion for those subsidiaries is based upon the ratio
of current-year revenues to expected total revenues, utilizing current
prices, over the life of production. If costs exceed the sum of the
estimated present value of the net future gas and oil revenues and the
lower of cost or estimated value of unproved properties, an amount
equivalent to the excess is charged to current depletion expense. Gains or
losses on the sale or other disposition of gas and oil properties are
normally recorded as adjustments to capitalized costs, except in the case
of a sale of a significant amount of properties, which could be reflected
in the income statement.
On April 30, 1996, Columbia sold Columbia Gas Development Corporation
(Columbia Development) effective December 31, 1995, to a privately held
exploration and development firm for approximately $200 million. The sale
included approximately 196 billion cubic feet equivalent of proved gas and
oil reserves, located in the Gulf of Mexico and on-shore continental
United States. An after-tax loss of $54.8 million was recorded in the
fourth quarter of 1995. An adjustment to the loss of $5.6 million
after-tax was recorded during 1996.
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 subsidiaries' gas inventory is carried at
cost on a last-in, first-out (LIFO) basis. The excess of replacement cost
of gas inventory at December 31, 1996, over the carrying value is
approximately $157 million. Liquidation of LIFO layers related to gas
delivered by the distribution subsidiaries does not affect income since
the effect is passed through to customers as part of purchased gas
adjustment tariffs.
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
48
<PAGE> 49
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
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.
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 that 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. Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation," (SFAS No. 123), effective
in 1996, encourages, but does not require, entities to adopt the fair
value method of accounting for stock based compensation plans. This
statement requires the value of the option at the date of grant be
amortized over the vesting period of the option. Columbia continues to
apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees" (APB Opinion No. 25).
For stock appreciation rights, compensation expense is recognized on the
aggregate difference between the market price of Columbia's stock and the
option price. Compensation expense related to contingent stock awards is
recognized over the vesting period. Columbia sets the grant price of the
options at the market price of the stock on the grant date. In accordance
with APB Opinion No. 25, expense related to stock options is measured by
the difference between the grant price and Columbia's stock price on the
measurement date (grant date). Since the difference between the grant
price and Columbia's stock price on the measurement date is de minimus, no
compensation expense is recognized. When stock options are exercised,
common stock is credited for the par value of shares issued and additional
paid in capital is credited with the consideration in excess of par.
2. 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.
49
<PAGE> 50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
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 (subsequently
redeemed in February 1996).
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.
Columbia Transmission's Plan is guaranteed financially by Columbia, and
provided a total distribution of approximately $3.9 billion to its
creditors of which approximately $1.2 billion represented producer claims.
Columbia Transmission's Plan provided that producers who rejected
settlement offers contained in Columbia Transmission's Plan may continue
to litigate their claims under the Bankruptcy Court-approved claims
estimation procedures, described below, and receive the same percentage
payout on their allowed claims, when and if ultimately allowed, as
received by the settling producers. Columbia Transmission's Plan further
provided that the actual distribution percentage for all producer claims,
which would not be less than 68.875% or greater than 72.5%, could not be
determined until the total amount of contested producer claims is
established, and until such time, 5% of the maximum amount (based on a
72.5% payout) to be distributed to producer claimants for allowed claims
and to Columbia for unsecured debt will be withheld. Additional
distributions, if any, will be made when the total amount of allowed
producer claims has been determined.
B. 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 Initial and
Supplemental Reports On Generic Issues for Natural Gas Contract Claims and
directed producer claimants to submit recalculated claims. The
recommendations and instructions set out in the reports have not been
considered by the Bankruptcy Court. In mid-1995, most producers with which
Columbia Transmission had not yet negotiated settlements submitted
recalculated claims to the claims mediator. Those recalculated claims
amounted to over $2 billion. Since mid-1995, numerous additional producers
have settled their claims or resolved them by means of litigation within
the claims estimation process and virtually all of these claims have been
allowed by the Bankruptcy Court at their litigated or settled level.
The claims estimation procedures remain in place for use in the
post-confirmation liquidation of those producer claims that remain
unresolved. The claims mediator is holding evidentiary hearings with
respect to individual producer claims, including claim-specific issues not
addressed by the reports. Recommendations made by the claims mediator are
subject to review by the Bankruptcy Court and all parties have rights of
appellate review. When claims are allowed by the Bankruptcy Court and the
allowances become final, Columbia Transmission will make distributions
with respect to those claims pursuant to the Plan. The timing of this
litigation process is impossible to predict. Based on the information
received and evaluated to date, Columbia believes adequate reserves have
been established for resolution of the remaining producer claims and the
payment of any amounts which may ultimately become due to producers with
respect to the 5% holdback.
C. REORGANIZATION ITEMS. During 1995 and 1994, 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 $40 million for adjustments to reserves for producer claim levels based
on the Claims Mediator's Report.
50
<PAGE> 51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Listed below is a summary of Reorganization Items included in the income
statements.
<TABLE>
<CAPTION>
($ in millions) 1996 1995 1994
- - -------------------------------------------------------------------
<S> <C> <C> <C>
Interest income on accumulated cash -- 93.5 63.4
Professional fees and related expenses -- (28.2) (35.4)
Other reorganization items, net -- (51.9) (40.3)
- - -------------------------------------------------------------------
Reorganization Items, Net -- 13.4 (12.3)
- - -------------------------------------------------------------------
</TABLE>
3. REGULATORY MATTERS
A. In August 1995, Columbia Transmission filed with the Federal Energy
Regulatory Commission (FERC) its first general rate case since 1991,
requesting an increase in annual revenue of approximately $147
million. Columbia Transmission also proposed to recover its net
investment in gathering and certain gas processing facilities over a
period of five years. The FERC authorized the new rates to be
implemented on February 1, 1996, subject to refund. However, in an
effort to reach a timely resolution of the issues included in the
filing, Columbia Transmission agreed to collect only 75% of the
requested rate increase for an interim period.
In January 1997, the FERC administrative law judge presiding over
the rate case certified to FERC a settlement filed on November 22,
1996 by Columbia Transmission. The settlement, which is supported by
all of Columbia Transmission's firm service customers, resolves
rate, cost of service, unbundling and certain other issues in the
case. It resolves issues in related filings as well, including the
transfer of certain gathering facilities to Columbia Transmission's
affiliate Columbia Natural Resources, Inc. The settlement also
incorporates a revised version of a partial settlement filed by
Columbia Transmission on August 30, 1996. That element of the
settlement provides for the continued use of system-wide rates,
commonly known as postage-stamp rates, in lieu of zone rates. Under
the settlement, Columbia Transmission will not place a new rate case
into effect prior to February 1, 2000. The issue relating to
recovery of environmental costs has been scheduled for a second
phase in the rate case proceeding and was not addressed in this
settlement. Approval of the proposed settlement will not have a
significant effect on the consolidated financial statements.
B. In its September 1993 Order on Columbia Transmission's and Columbia
Gulf's FERC Order No. 636 (Order 636) compliance filings, the FERC
initiated a proceeding concerning Columbia Gulf's transportation
service to Columbia Transmission. It directed Columbia Gulf to show
cause as to why it had not filed for FERC's abandonment
authorization to reduce capacity on its mainline facilities. In a
response to the FERC in late 1993, Columbia Gulf asserted that no
abandonment authorization 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.
C. On March 1, 1995, Columbia Transmission filed with the FERC to
recover $69 million of annual projected transportation costs and $39
million of unrecovered transportation costs that were billed to
Columbia Transmission by Columbia Gulf. Various parties protested
Columbia Transmission's filing, and challenged among other things
Columbia Transmission's ability to recover costs attributable to
Columbia Gulf.
In an April 2, 1996 Order, the FERC ruled that Columbia Gulf was
entitled to bill its prudently incurred costs, under its
cost-of-service tariff, to Columbia Transmission, and that Columbia
Transmission was entitled to flow such amounts through to its
customers. The FERC ruled that approximately $19 million of the
Columbia Gulf charges, which were attributable to operation and
maintenance costs, were recoverable, subject to a general FERC
audit. With respect to the remaining $20 million of costs, that were
associated with environmental issues, the FERC established hearing
procedures to determine if any portion of these costs were not
prudently incurred by Columbia Gulf and therefore would not be
recoverable. A hearing on this issue is scheduled for the first
quarter of 1997. FERC has denied requests for rehearing of the April
1996 Order.
51
<PAGE> 52
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
While the outcome of the hearing is uncertain, management believes
Columbia Transmission has a valid basis for recovering these costs.
It is not expected that the outcome will have a material adverse
impact on the company's financial statements.
D. In response to numerous petitions for review of Order 636, the D.C.
Circuit Court of Appeals issued a decision in July 1996. The court
generally upheld the FERC's actions, but remanded to the FERC
certain aspects of Order 636. Motions for reconsideration of the
court's order have been filed and responses made by the FERC and
certain distribution companies. As a result of these proceedings,
Order 636 may be modified or reversed in whole or in part; however,
at this time it is impossible to predict the outcome. Columbia
Transmission does not believe that the order will have a significant
impact on its operations. A customer settlement approved by the FERC
in 1995 provides that any relief granted as a result of the court
decision will be implemented prospectively on Columbia
Transmission's system, and that Columbia Transmission will have no
refund obligation or other financial liability as a result of the
decision.
E. On October 31, 1996, Columbia Gulf filed a general rate case with
the FERC. The proposed rates would result in approximately $9.6
million of additional annual revenue compared to the revenues
generated by Columbia Gulf's current rates. The filed rates have
been suspended by the FERC until May 1, 1997, when they may be
placed into effect, subject to refund and conditions, pending the
outcome of a hearing.
F. Columbia Gas of Ohio's (Columbia of Ohio) 1994 rate case settlement
provided for a review of the company's revenue requirements by a
collaborative group composed of diverse interested parties
(Collaborative), for the purpose of evaluating the need to adjust
base rates at May 1, 1996. The review process was completed and in
October 1996, Columbia of Ohio filed an unopposed settlement with
the Public Utilities Commission of Ohio (PUCO) to resolve its
revenue requirement. This filing was approved by the PUCO in
December 1996. The filing permits Columbia of Ohio to retain up to
$51 million of revenues over the next three years subject to a
sharing mechanism, under which a portion of any earnings above an
industry composite allowed return on equity would be shared with
customers. The revenues retained are primarily from historic
off-system sales transactions completed or agreed to prior to August
31, 1996. As allowed under this settlement, revenues of
approximately $11.5 million were recorded in 1996 income with
revenues eligible for retention in each of the following two years
of approximately $19.7 million. This revenue mechanism is in lieu of
a base rate increase and does not result in any base rate increase
for customers. Additionally, the settlement provides that Columbia
of Ohio will not implement any increase in base rates before January
1, 1999.
4. RESTRUCTURING ACTIVITIES
The transmission subsidiaries began a reengineering project to assess the
way the companies operate. These efforts are expected to streamline the
business functions, improve the organizational structure and reduce staff
levels. The project is focusing on all processes within the transmission
subsidiaries. Additional expense is expected to be incurred in 1997.
The distribution segment has initiated a restructuring of its
headquarters' operation as part of its ongoing efforts to provide enhanced
customer service and to achieve greater operating efficiencies. In
addition, "Project Customer" initiatives which are designed to streamline
and enhance customer service are continuing. Additional studies are
underway in all of the distribution segment's service territories that may
affect the field organizations in functions other than customer service
and may result in additional positions being eliminated which will result
in additional expense being recorded.
The exploration and production segment reengineered its administrative
operations to reduce overhead.
In the third quarter of 1996, Columbia Gas System Service Corporation,
Columbia LNG Corporation and TriStar Ventures Corporation implemented a
reengineering program as well as moved their corporate headquarters from
Wilmington, Delaware to Reston, Virginia.
As a result of these restructuring programs, it is estimated that 1,105
management, professional, administrative and technical positions will be
eliminated. In 1996, Columbia recorded a pre-tax charge of $60.9 million
in operating expense representing severance and related benefit costs,
relocation costs, the establishment of the
52
<PAGE> 53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
new corporate center and costs related to the sale of the
headquarters building. This charge included $52.7 million of
estimated termination benefits. Partially offsetting these charges
is a $6 million pre-tax gain on the sale of the headquarters
building. As of December 31, 1996, approximately 530 employees have
been terminated as a result of these programs. The remaining accrual
associated with the restructuring activities totaled $38.6 million
at December 31, 1996.
5. COMMODITY HEDGING ACTIVITIES
Subsidiaries in Columbia's production, marketing and propane
operations engage in commodity hedging activities to minimize the
risk of market fluctuations associated with the price of natural gas
and crude oil 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.
Columbia's exploration and production company utilizes 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, 1996, there were 1,490 open contracts representing a
notional quantity amounting to 14.9 Bcf of natural gas production
through October of 1997, at an average price of $2.32 per Mcf. A
total of $1.2 million of unrealized gains have been deferred on the
consolidated balance sheet with respect to these open contracts. At
December 31, 1995, there were 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
were deferred on the consolidated balance sheet with respect to
those open contracts at December 31, 1995.
During the year ended December 31, 1996, $3.7 million of losses were
realized on the settlement of natural gas option and swap contracts
entered into to hedge the value of gas production. During the year
ended December 31, 1995, $6.8 million of gains were realized on the
settlement of these contracts. These gains and losses are offset
when the production is sold in the cash market.
At December 31, 1996, there were 5,173 open contracts through
October of 1998, representing a notional quantity amounting to 51.7
Bcf of natural gas. A total of $0.8 million of realized gains have
been deferred on the consolidated balance sheet with respect to
these open contracts. At December 31, 1995, there were 482 open
contracts through January 1997, representing a notional quantity
amounting to 4.8 Bcf of natural gas. A total of $0.8 million of
unrealized losses were deferred on the consolidated balance sheet
with respect to these open contracts at December 31, 1995. These
unrealized losses are offset by gains which are realized when the
products are sold.
Columbia's 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. During the years ended December
31, 1996 and 1995, losses of $6.3 million and $4.9 million,
respectively, 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 or their affiliates.
53
<PAGE> 54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
6. 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 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 resulted 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 rate making 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.
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 1994 net income by $5.6
million.
C. On January 1, 1996, Columbia adopted the Financial Accounting
Standards Board's Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS No. 121). This statement
establishes accounting standards for the impairment of long-lived
assets, certain identifiable intangibles, and goodwill related to
those assets to be held and used and for long-lived assets and
certain identifiable intangibles to be disposed of. SFAS No. 121
requires these assets be reviewed for possible impairment whenever
events or changes in circumstances indicate that the carrying amount
may not be recoverable. The adoption of SFAS No. 121 did not have a
material impact on Columbia's financial statements.
54
<PAGE> 55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
7. INCOME TAXES
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1996 1995 1994
----- ------ -----
<S> <C> <C> <C>
INCOME TAXES
Current
Federal 30.4 (284.8) 63.8
State 7.5 8.1 10.0
----- ------ -----
Total Current 37.9 (276.7) 73.8
----- ------ -----
Deferred
Federal 64.6 69.7 78.9
State 14.9 (2.2) (5.3)
----- ------ -----
Total Deferred 79.5 67.5 73.6
----- ------ -----
Deferred Investment Credits (1.5) (1.5) (1.4)
----- ------ -----
Income taxes included in income before extraordinary
item and cumulative effect of accounting change 115.9 (210.7) 146.0
Deferred taxes related to extraordinary item and
cumulative effect of accounting change - 36.9 (3.3)
----- ------ -----
TOTAL INCOME TAXES 115.9 (173.8) 142.7
----- ------ -----
</TABLE>
Total income taxes are different from the amount that would be computed by
applying the statutory Federal income tax rate to book income before income tax.
The major reasons for this difference are as follows:
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1996 1995 1994
----- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Book income (loss) before income taxes,
extraordinary item and cumulative effect of
accounting change 337.5 (643.0) 392.2
Tax expense (benefit) at statutory
Federal income tax rate 118.1 35.0% (225.0) 35.0% 137.3 35.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal
income tax benefit 16.7 4.9 4.7 (0.7) 2.6 0.6
Estimated non-deductible expenses 0.9 0.3 9.0 (1.4) 6.4 1.6
Effect of change in deferred taxes
previously provided (4.0) (1.2) - - - -
Adjustment to prior years' tax provision due
to pending settlement (11.3) (3.4) - - - -
Other (4.5) (1.3) 0.6 (0.1) (0.3) -
----- ---- ------ ---- ----- ----
INCOME TAXES BEFORE EXTRAORDINARY
ITEM AND CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 115.9 34.3% (210.7) 32.8% 146.0 37.2%
===== ==== ====== ==== ===== ====
</TABLE>
55
<PAGE> 56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
Deferred tax balances are as follows:
At December 31 ($ in millions) 1996 1995
----- -----
<S> <C> <C>
Net current liabilities (assets)
Federal (53.8) (30.9)
State 1.0 (6.2)
----- -----
Total (52.8) (37.1)
----- -----
Net noncurrent liabilities
Federal 481.9 401.6
State 75.8 67.0
----- -----
Total 557.7 468.6
----- -----
TOTAL DEFERRED INCOME TAXES 504.9 431.5
----- -----
</TABLE>
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:
<TABLE>
<CAPTION>
At December 31 ($ in millions) 1996* 1995
----- -----
<S> <C> <C>
Property basis differences 584.0 610.5
Gas purchase costs 94.4 15.1
Transportation costs - 2.0
Partnership deferrals 23.9 26.0
Deferred revenue (5.5) (0.9)
Estimated supplier obligations (60.8) (59.6)
Estimated rate refunds (25.0) (13.1)
Postretirement benefits (16.5) (17.0)
Environmental liabilities 2.1 (17.2)
Capitalized inventory overheads (24.3) (25.5)
Unbilled utility revenue (23.9) (12.5)
Net operating loss carryforward - (19.9)
Alternative minimum tax (46.9) (91.0)
Debt forgiveness 47.5 50.7
Restructuring costs (18.5) (5.2)
Other (25.6) (10.9)
----- -----
TOTAL DEFERRED INCOME TAXES 504.9 431.5
----- -----
</TABLE>
* At December 31, 1996, Columbia had state income tax net operating loss
carryforwards (net of federal taxes) of approximately $40,100,000. The
realization of such state income tax carryforwards is dependent upon
generating sufficient taxable income prior to their expiration. Management
believes that there is a risk that certain of these carryforwards may expire
unused and, therefore, an asset has not been recorded for such future
benefits. The expiration of the state tax loss carryforward benefits, net of
federal taxes, in 1997 is $0.4 million, in 1988 is $0.5 million, in 1999 is
$2.8 million, in 2000 is $1.6 million, in 2001 is $0.6 million, and beyond is
$34.2 million.
56
<PAGE> 57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
8. PENSION AND OTHER POSTRETIREMENT BENEFITS
A. PENSION PLANS. Columbia has a noncontributory, qualified defined
benefit pension plan covering essentially all employees. Benefits are
based primarily on years of credited service and employees' highest
three-year average annual compensation in the final five years of
service. Columbia's funding policy complies with Federal law and tax
regulations.
Columbia also has a nonqualified pension plan that provides benefits to
some employees in excess of the qualified plan's Federal tax limits.
Effective 1996, Columbia is reflecting the information presented below
as of September 30, rather than December 31. The effect of this change
is not material.
The following table shows the components of net pension expense for the
qualified and nonqualified plans and the annual contributions for each
of the three years:
<TABLE>
<CAPTION>
PENSION COSTS ($ in millions) 1996 1995 1994
----- ------ -----
<S> <C> <C> <C>
Service cost 35.0 26.7 34.2
Interest cost 70.7 69.9 68.8
Actual return on assets (81.9) (202.5) (11.3)
Net amortization (deferral) (5.1) 124.8 (66.1)
----- ------ -----
NET PENSION EXPENSE 18.7 18.9 25.6
----- ------ -----
CONTRIBUTIONS 0.0 1.2 7.0
----- ------ -----
</TABLE>
The following table provides a reconciliation of the plans' funded status and
amounts reflected in columbia's balance sheet at December 31:
<TABLE>
<CAPTION>
PLAN ASSETS AND OBLIGATIONS ($ in millions) 1996 1995
------- -------
<S> <C> <C>
Plan assets at fair value 1,033.9 1,034.6
------- -------
Actuarial present value of benefit obligations:
Vested benefits 660.6 760.2
Nonvested benefits 48.7 56.1
------- -------
Accumulated benefit obligation 709.3 816.3
Effect of projected future salary increases 160.6 190.8
------- -------
PROJECTED BENEFIT OBLIGATION 869.9 1,007.1
------- -------
Plan assets in excess of projected benefit obligation 164.0 27.5
Unrecognized net gain (281.5) (131.8)
Unrecognized prior service cost 52.6 56.5
Unrecognized transition obligation 7.0 8.1
------- -------
ACCRUED PENSION COST (57.9) (39.7)
------- -------
DISCOUNT RATE ASSUMPTION 8.0% 7.0%
------- -------
COMPENSATION GROWTH RATE ASSUMPTION 5.0% 5.0%
------- -------
ASSET EARNINGS RATE ASSUMPTION 9.0% 9.0%
------- -------
</TABLE>
Plan assets consist of primarily equity (international and domestic) and fixed
income securities.
As of December 31, 1996, the discount rate assumption was revised upward to
8.0%. The net effect of this change was to decrease the accumulated benefit
obligation and the projected benefit obligation by $88.3 million and $127.5
million, respectively.
57
<PAGE> 58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
B. OTHER POSTRETIREMENT BENEFITS. Columbia also provides medical
coverage and life insurance to retirees. Essentially all active
employees are eligible for these benefits upon retirement after
completing ten consecutive years of service after age 45. Normally,
spouses and dependents of retirees are also eligible for medical
benefits.
Effective 1996, Columbia is reflecting the information presented below
as of September 30 rather than December 31. The effect of this change is
not material.
The following table shows components of other postretirement costs for
each of the three years:
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT COSTS ($ in millions) 1996 1995 1994
----- ----- ----
<S> <C> <C> <C>
Service cost 13.8 11.3 15.3
Interest cost 22.4 24.1 24.6
Actual return on assets (12.5) (30.0) (2.1)
Other, net amortization (deferral) (5.4) 16.0 (4.9)
----- ----- ----
OTHER POSTRETIREMENT COSTS, NET 18.3 21.4 32.9
----- ----- ----
CONTRIBUTIONS 36.2 41.8 20.7
----- ----- ----
</TABLE>
The following table provides a reconciliation of other postretirement plans'
funded status and amounts reflected on Columbia's balance sheet at December 31:
<TABLE>
<CAPTION>
PLAN ASSETS AND OBLIGATIONS ($ in millions) 1996 1995
------ -------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees 151.0 172.1
Fully eligible active plan participants 54.5 60.5
Other participants 81.7 83.2
------ -------
Total accumulated postretirement benefit obligation 287.2 315.8
Plan assets at fair value (179.6) (149.1)
------ -------
Accumulated postretirement benefit obligation
in excess of plan assets 107.6 166.7
Unrecognized actuarial net gain 117.5 72.8
Less: Fourth quarter contributions 6.6 -
------ -------
ACCRUED POSTRETIREMENT BENEFIT COST 218.5 239.5
------ -------
DISCOUNT RATE ASSUMPTION 8.0% 7.0%
------ -------
MEDICAL COST TREND 5.5% 8.0-5.5%
------ -------
COMPENSATION GROWTH RATE ASSUMPTION 5.0% 5.0%
------ -------
ASSET EARNINGS RATE ASSUMPTION* 9.0% 9.0%
------ -------
</TABLE>
*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. The assets are held in three trust accounts and one
401(h) account.
As of December 31, 1996, the discount rate assumption was revised upward to 8.0%
from 7.0%. The medical cost trend rate at December 31, 1996 was 5.5%, a change
from the December 31, 1995 rate which started at 8.0% and decreased to 5.5%
after six years. The net effect of these changes was a $50.9 million decrease in
the accumulated postretirement benefit obligation. A one percent increase in
medical inflation trend rates for each future year would have increased the
accumulated postretirement benefit obligation by another $16.2 million and other
postretirement costs by $3.0 million in 1996.
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 $3.3
million, and $3.8 million were made to the retiree life insurance VEBA trust in
1996 and 1995, respectively.
58
<PAGE> 59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
9. LONG-TERM INCENTIVE PLAN
On April 26, 1996, shareholders approved a new Long-Term Incentive Plan
(New LTIP). The New LTIP which is effective for ten years, beginning
February 21, 1996, provides for the granting of nonqualified stock
options and incentive stock options, contingent stock awards, stock
appreciation rights and restricted stock awards to officers and key
employees. The New LTIP also provides for the granting of nonqualified
stock options to outside directors. A total of 3,000,000 shares of
Columbia's authorized common stock is available under the New LTIP's
provisions.
On April 26, 1996, shareholders approved an incentive compensation plan
for outside directors under which they may receive benefits in lieu of a
retirement plan and defer current compensation in the form of phantom
stock units, which equates the amounts granted to the directors with the
performance of Columbia's stock.
Columbia's Long-Term Incentive Plan (LTIP), in effect from 1985 through
1995, provided for the granting of nonqualified stock options, stock
appreciation rights and contingent stock awards as determined by the
Compensation Committee of the Board of Directors. That committee also
had the right to modify any outstanding award. A total of 1,500,000
shares of Columbia's authorized common stock was initially reserved for
issuance under the LTIP's provisions.
Stock appreciation rights, which were granted in connection with certain
nonqualified stock options, entitle the holders to receive stock, cash
or a combination thereof equal to the excess market value over the grant
price. Stock options and related stock appreciation rights granted under
the LTIP generally have a maximum term of ten years and vest over two to
four years.
Transactions for the three years ended December 31, 1996, are as
follows:
<TABLE>
<CAPTION>
Options
---------------------------
Without Stock With Stock Option
Appreciation Appreciation Price
Rights Rights Range
-------- ------- ---------------
<S> <C> <C> <C>
Outstanding 12/31/93 505,620 156,150 $ 34.30-$46.68
-------- ------- ---------------
1994
Cancelled (20,655) - $ 34.30-$46.68
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
Outstanding 12/31/95 524,320 150,050 $ 28.99-$46.68
-------- ------- ---------------
1996
Granted 100,000 - $ 48.6875
Exercised (209,625) (66,860) $ 28.99-$46.68
Forfeited (9,020) (7,260) $ 34.30-$46.68
-------- ------- ---------------
OUTSTANDING 12/31/96 405,675 75,930 $28.99-$48.6875
-------- ------- ---------------
EXERCISABLE 12/31/96 355,675 75,930 $28.99-$48.6875
-------- ------- ---------------
</TABLE>
59
<PAGE> 60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The following table shows the weighted average option exercise price information
for the two years ended December 31:
<TABLE>
<CAPTION>
1996 1995
------- -------
<S> <C> <C>
Outstanding at January 1 $ 41.31 $ 42.69
Granted during the year 48.69 29.10
Exercised during the year 41.07 35.36
Forfeited during the year 44.15 -
Cancelled during the year - 40.61
OUTSTANDING AT DECEMBER 31 42.88 41.31
EXERCISABLE AT DECEMBER 31 42.21 41.31
------- -------
</TABLE>
In addition to the options, contingent stock awards totaling 27,500
shares were issued to two key executives in 1995. As of December 31,
1996, the equivalent of 22,500 of these shares have vested, 20,160
shares have been issued (net of amounts withheld to pay taxes), and
5,000 shares remain outstanding. During 1996, contingent stock awards
totaling 1,500 shares were issued to one key executive. As of December
31, 1996, all 1,500 shares have vested and been issued. Restricted stock
awards totaling 29,785 shares were issued to one key executive in 1996.
As of December 31, 1996, all 29,785 shares remain outstanding.
During 1996 and 1995, $1.5 million and $1.1 million were expensed for
the Long-Term Incentive Plan, respectively. There were de minimus
amounts expensed for the Long-Term Incentive Plan in 1994.
Had compensation cost been determined consistent with the provisions of
the SFAS No. 123 fair value method (See Note 1N), the effect on
Columbia's net income and earnings per share for both 1996 and 1995
would have been immaterial. Regarding the stock options issued in 1995,
100% of such options vested in 1995. Regarding the stock options issued
in 1996, 50% of such options vested in 1996 and the other 50% will vest
in 1997. The fair value of each option grant is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted assumptions used for grants in 1995 and 1996: dividend yield of
1.18%; expected volatility of 20.12%; risk free interest rate of 6.39%
and 5.93% for 1995 and 6.58% for 1996; and expected lives of seven
years.
10. PREFERRED STOCK
Columbia has authorized 40,000,000 shares of preferred stock with a par
value of $10 per share. As of December 31, 1995, Columbia had
outstanding 7,999,494 shares of 7.89% Series A-Preferred Stock and
4,898,946 shares of 5.22% Series B-DECS. The Series A - Preferred Stock
was issued at $25 per share and with an aggregate liquidation value of
$199,987,350. The Series B - DECS was issued at $40.82 per share with an
aggregate liquidation value of $199,974,975.
On February 26, 1996, Columbia redeemed all outstanding shares of its
two series of preferred stock at the liquidating value. As a result, no
dividends were paid on preferred stock during 1996.
60
<PAGE> 61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
11. LONG-TERM DEBT
The long-term debt (exclusive of current maturities) of Columbia and its
subsidiaries is as follows:
<TABLE>
<CAPTION>
At December 31 ($ in millions) 1996 1995
------- -------
<S> <C> <C>
The Columbia Gas System, Inc.
Debentures
6.39% Series A due November 28, 2000 311.0 311.0
6.61% Series B due November 28, 2002 281.5 281.5
6.80% Series C due November 28, 2005 281.5 281.5
7.05% Series D due November 28, 2007 281.5 281.5
7.32% Series E due November 28, 2010 281.5 281.5
7.42% Series F due November 28, 2015 281.5 281.5
7.62% Series G due November 28, 2025 281.5 281.5
------- -------
Total Debentures 2,000.0 2,000.0
Subsidiary Debt:
Capitalized lease obligations 2.5 2.9
Other 1.3 1.6
------- -------
TOTAL LONG-TERM DEBT 2,003.8 2,004.5
------- -------
</TABLE>
The aggregate maturities of long-term debt and capitalized lease obligations
during the next five years are as follows:
<TABLE>
<CAPTION>
($ in millions)
<C> <C>
1997 0.9
1998 0.5
1999 0.5
2000 311.4
2001 0.6
</TABLE>
12. SHORT-TERM DEBT AND CREDIT FACILITIES
Effective November 1995, Columbia entered into an unsecured bank
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 borrowings 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, 1996 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. At December 31, 1996, Columbia had
outstanding $250 million under the Credit Facility at an average rate of
6.44%. At December 31, 1995, Columbia had outstanding $338.9 million
under the Credit Facility at an average rate of 6.46%. The maximum
indebtedness outstanding during the year occurred on March 5, 1996 in
the amount of $652.1 million at an interest rate of 5.88%.
The Credit Facility provides for the issuance of up to $100 million of
standby letters of credit. In addition, at the option of Columbia, an
additional $50 million of the credit facility can be utilized for
letters of credit or borrowings. As of December 31, 1996, Columbia had
$86.8 million of letters of credit outstanding under the
61
<PAGE> 62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
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 0.125% to the issuing bank. At December 31, 1996, fees for letters of
credit issued in connection with certain financial obligations were at a
rate of 0.2775%.
13. 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:
Long-term investments
Long-term investments include loans receivable ($4.0 million for 1996
and $3.9 million for 1995) whose estimated fair values are based on the
present value of estimated future cash flows using an estimated rate for
similar loans. Also, included in 1995 was an income tax refund
receivable with associated interest of $80.1 million whose carrying
amount approximated fair value. The financial instruments included in
long-term investments are primarily reflected in Investments and Other
Assets in the consolidated balance sheets.
Long-term debt
The estimated fair value of Columbia's debentures, including accrued
interest, is based on estimates provided by brokers.
<TABLE>
<CAPTION>
1996 1995
------------------ ------------------
CARRYING FAIR CARRYING FAIR
AT DECEMBER 31 ($ IN MILLIONS) AMOUNT VALUE AMOUNT VALUE
------- ------- ------- -------
<S> <C> <C> <C> <C>
LONG-TERM INVESTMENTS FOR WHICH IT IS:
PRACTICABLE TO ESTIMATE FAIR VALUE 4.0 3.6 84.0 83.6
NOT PRACTICABLE TO ESTIMATE FAIR VALUE 4.2 - 6.6 -
LONG-TERM DEBT 2,012.9 1,948.1 2,012.9 2,044.7
------- ------- ------- -------
</TABLE>
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.
14. OTHER COMMITMENTS AND CONTINGENCIES
A. CAPITAL EXPENDITURES. Capital expenditures for 1997 are currently
estimated at $490 million. Of this amount, $267 million is for
transmission and storage operations, $160 million for distribution
operations, $39 million for exploration and production operations,
$10 million for marketing, propane and power generation operations
and $14 million for Corporate.
B. 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.
62
<PAGE> 63
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
C. 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 monies 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, 1996,
amounted to $29.1 million.
D. INTERNAL REVENUE SERVICE (IRS) AUDIT. A review by the IRS of
Columbia's 1991 through 1994 federal income tax returns has been
concluded. The major unresolved issues are included in the Revenue
Agents Report, the resolution of which is currently being pursued
with the Appeals Division of the IRS. Management believes that these
same items will also be issues in the 1995 tax return. Based on the
facts known at this time, management believes adequate reserves have
been established for these issues.
E. OPERATING LEASES. Payments made in connection with operating leases
are charged to operation and maintenance expense as incurred. Such
amounts were $60.9 million in 1996, $61.6 million in 1995 and $56.6
million in 1994.
Future minimum rental payments required under operating leases that
have initial or remaining noncancellable lease terms in excess of
one year are:
<TABLE>
<CAPTION>
($ in millions)
<S> <C>
1997 26.3
1998 25.7
1999 24.8
2000 19.2
2001 17.4
After 208.5
</TABLE>
F. 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.
A subsidiary has 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 have implemented programs to
continually review compliance with existing environmental standards.
In addition, Columbia Transmission continues to review past
operational activities and to formulate remediation programs where
necessary. Columbia Transmission is currently conducting assessment,
characterization and remediation activity of specific sites under a
1995 EPA Administrative Order by Consent (AOC).
In 1995, Columbia Transmission estimated that the cost of its
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
63
<PAGE> 64
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
appropriate remediation levels and the technology to be utilized;
and the frequency with which groundwater contamination might be
discovered at sites requiring remediation. The estimate did not
include previously identified costs for certain specific activities,
aggregating approximately $50 million, for which Columbia
Transmission already had reasonable estimates.
Following an extensive review of assumptions utilized in arriving at
the estimate, 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 estimate 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 time frame and
potential costs of all site screening, characterization and
remediation. As Columbia Transmission continues its program pursuant
to the AOC and additional costs become probable and reasonably
estimable, the associated reserves will be adjusted as appropriate.
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, SFAS No. 5
and American Institute of Certified Public Accountants Statement of
Position 96-1.
Activities under the AOC in 1996 were focused on obtaining EPA
approval to begin the assessment and characterization of certain
major facilities, some select liquid removal points, and other
select mercury measurement stations. In 1996, the EPA authorized
Columbia Transmission to begin characterization of twelve major
facilities. Columbia Transmission expects EPA approval to begin
characterization of an additional 60 major facilities in 1997.
Columbia Transmission also continued to conduct assessment and
remediation of impacted soils at locations prior to normal
construction and maintenance activities under its EPA approved
Construction and Operation Work Plan (COWP). In 1996, Columbia
Transmission conducted assessments at 216 sites and based on these
assessment results, performed remedial activities in varying degrees
at approximately 100 locations.
As a result of these 1996 activities, Columbia Transmission recorded
an additional liability of $3.3 million in the fourth quarter of
this year and $2.5 million in the second quarter of this year.
Actual expenditures of approximately $17 million during 1996 charged
to the liability plus additions of nearly $6 million mentioned above
resulted in a remaining overall liability of $126 million. Columbia
Transmission's environmental cash expenditures are expected to be
approximately $18 million in 1997 and continue annually at that
level for the foreseeable future. These expenditures will be charged
against Columbia Transmission's previously recorded liability.
Management does not believe that Columbia Transmission's
environmental expenditures will have a material adverse effect on
its operations, liquidity or financial position, based on known
facts and existing laws and regulations and the long period over
which expenditures will be made. In addition, as a result of
reapplying SFAS No. 71 in 1995, a regulatory asset has been recorded
to the extent environmental expenditures are expected to be
recovered through rates. Columbia Transmission is also currently
involved in pursuing recovery of environmental expenditures from its
insurance carriers. At this time, management is unable to determine
the extent, if any, of recovery.
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. From its investigations, 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 15 former manufactured gas plant sites.
Investigations or remedial activities are currently underway at six
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
64
<PAGE> 65
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
appropriate liabilities have been recorded. Regulatory assets have
also been recorded for a majority of these identified liabilities 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 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 on
information currently available which resulted in a total recorded
net liability of approximately $129 million for Columbia at December
31, 1996. As new issues are identified, additional liabilities will
be recorded.
It is management's continued intent to address environmental issues
in cooperation with regulatory authorities in such a manner as to
achieve mutually acceptable compliance plans. However, there can be
no assurance that fines and penalties will not be incurred.
Management expects most environmental assessment and remediation
costs to be recoverable through rates.
15. INTEREST INCOME AND OTHER, NET
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1996 1995 1994
---- ----- ----
<S> <C> <C> <C>
Interest income 13.4 22.8 31.8
Sale of Columbia Development 6.9 (77.8) -
Miscellaneous 5.8 (3.2) 3.4
---- ----- ----
TOTAL 26.1 (58.2) 35.2
---- ----- ----
</TABLE>
65
<PAGE> 66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
16. INTEREST EXPENSE AND RELATED CHARGES
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1996 1995 1994
----- ----- ----
<S> <C> <C> <C>
Interest on emergence, including amortization of
discounts on long-term debt - 982.9 -
Interest on long-term debt 140.4 - -
Interest on short-term debt 11.7 15.1 0.2
Interest on rate refunds 3.9 17.7 9.0
Interest on prior years' taxes 8.3 17.6 (8.8)
Allowance for borrowed funds used and interest
during construction 2.5 (52.4) -
Other interest charges - 7.5 14.4
----- ----- ----
TOTAL 166.8 988.4 14.8
----- ----- ----
</TABLE>
17. BUSINESS SEGMENT INFORMATION
Columbia is a registered holding company under the Public Utility
Holding Company Act of 1935, as amended and derives substantially all of
its revenues and earnings from the operating results of its 18 direct
subsidiaries. Columbia's subsidiaries are divided into four primary
business segments. The transmission and storage segment offers
transportation, storage and gas peaking 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 for
service for residential, commercial and industrial customers in Ohio,
Pennsylvania, Virginia, Kentucky and Maryland. The exploration and
production segment explores for, develops, produces, and markets gas and
oil in the United States. The marketing, propane and power generation
segment includes the sale of propane at wholesale and retail to
customers in eight states, participation in natural gas fueled
cogeneration projects and the marketing of natural gas and services to
distribution companies, independent power producers and other large end
users.
The following tables provide information concerning Columbia's major
business segments. Revenues include intersegment sales to affiliated
subsidiaries, which are eliminated when consolidated. Affiliated sales
are recognized on the basis of prevailing market or regulated prices.
Operating income is derived from revenues and expenses directly
associated with each segment. Identifiable assets include only those
attributable to the operations of each segment.
66
<PAGE> 67
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
($ in millions) 1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
REVENUES
Transmission and Storage - Unaffiliated 456.2 436.0 475.9
- Intersegment 354.6 324.3 282.8
------- ------- -------
TOTAL 810.8 760.3 758.7
------- ------- -------
Distribution - Unaffiliated 2,120.4 1,780.6 1,830.7
- Intersegment 7.3 2.5 -
------- ------- -------
TOTAL 2,127.7 1,783.1 1,830.7
------- ------- -------
Exploration and Production - Unaffiliated 45.5 111.5 121.7
- Intersegment 59.0 69.1 83.6
------- ------- -------
TOTAL 104.5 180.6 205.3
------- ------- -------
Marketing, Propane - Unaffiliated 731.5 307.1 304.1
and Power Generation - Intersegment 84.9 6.2 1.6
------- ------- -------
TOTAL 816.4 313.3 305.7
------- ------- -------
Adjustments - Unaffiliated 0.4 - 14.7
and eliminations - Intersegment (505.8) (402.1) (368.0)
------- ------- -------
TOTAL (505.4) (402.1) (353.3)
------- ------- -------
CONSOLIDATED 3,354.0 2,635.2 2,747.1
------- ------- -------
</TABLE>
67
<PAGE> 68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
($ in millions) 1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
OPERATING INCOME (LOSS)
Transmission and Storage 207.8 213.0 209.7
Distribution 226.0 163.6 128.3
Exploration and Production 30.0 3.7 30.6
Marketing, Propane and Power Generation 12.5 12.2 14.8
Corporate 1.9 (2.3) 0.7
------- ------- -------
CONSOLIDATED 478.2 390.2 384.1
------- ------- -------
DEPRECIATION & DEPLETION
Transmission and Storage 102.6 103.8 103.9
Distribution 74.4 70.9 64.5
Exploration and Production 28.8 86.9 86.2
Marketing, Propane and Power Generation 3.1 2.6 2.3
Adjustments and eliminations 6.3 5.8 4.8
------- ------- -------
CONSOLIDATED 215.2 270.0 261.7
------- ------- -------
IDENTIFIABLE ASSETS
Transmission and Storage 2,761.2 2,978.9 4,150.0
Distribution 2,648.3 2,295.7 2,168.9
Exploration and Production 421.7 412.4 746.4
Marketing, Propane and Power Generation 289.0 125.8 97.5
Adjustments and eliminations (620.2) (360.4) (441.3)
Corporate and unallocated 504.6 604.6 443.4
------- ------- -------
CONSOLIDATED 6,004.6 6,057.0 7,164.9
------- ------- -------
CAPITAL EXPENDITURES
Transmission and Storage 142.7 172.5 179.1
Distribution 148.4 151.8 151.4
Exploration and Production 12.1 86.8 101.6
Marketing, Propane and Power Generation 6.3 6.6 4.7
Corporate 5.3 4.1 10.4
------- ------- -------
CONSOLIDATED 314.8 421.8 447.2
------- ------- -------
</TABLE>
68
<PAGE> 69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
18. 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.
<TABLE>
<CAPTION>
First Second Third Fourth
($ in millions except per share data) Quarter Quarter Quarter Quarter
------- ----- ----- -----
<S> <C> <C> <C> <C>
1996
Operating Revenues 1,203.0 582.4 450.8 1,117.8
Operating Income 278.2 36.0 20.9 143.1
Net Income (Loss) 151.3 8.2(a) (6.1)(b) 68.2(c)
Per Share Amounts
Earnings (Loss) on Common Stock 2.99 0.15 (0.11) 1.24
------- ----- ----- -----
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(d) 30.9(e) 19.3(f) (539.7)(g)
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)
------- ----- ----- -----
</TABLE>
(a) Includes a decrease in net income of $18.6 million to reflect severance and
benefit costs associated with ongoing reengineering activities, partially
offset by an increase in net income of $5.6 million for an adjustment to the
loss on the sale of Columbia Development.
(b) Includes a decrease in net income of $2.5 million to reflect severance and
benefit costs associated with ongoing reengineering activities.
(c) Includes a decrease in net income of $11.1 million to reflect severance and
benefit costs associated with ongoing reengineering activities.
(d) 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.
(e) 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.
(f) 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.
(g) Includes a decrease for the impact of emergence from bankruptcy and customer
settlement of $649.4 million, the estimated loss on the proposed sale of
Columbia Development of $54.8 million and an improvement of $71.6 million
for the reapplication of SFAS No. 71.
19. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
INTRODUCTION. On April 30, 1996, Columbia sold Columbia Development, its
wholly-owned Southwest exploration and production subsidiary, effective
December 31, 1995. The information contained in the following tables
includes amounts attributable to the operations and reserves of Columbia
Development for 1995 and 1994.
Reserve information contained in the following tables for the U.S.
properties is management's estimate, which was reviewed by the
independent consulting firm of Ryder Scott Company Petroleum Engineers.
Reserves are reported as net working interest. Gross revenues are
reported after deduction of royalty interest payments.
69
<PAGE> 70
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
CAPITALIZED COSTS ($ in millions) 1996 1995 1994
- - --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CAPITALIZED COSTS AT YEAR END
Proved properties 475.4 486.2 1,185.8
Unproved properties(a) 27.4 30.1 76.1
------ ----- -------
Total capitalized costs 502.8 516.3 1,261.9
Accumulated depletion (146.4) (141.1) (637.6)
------ ------ -------
NET CAPITALIZED COSTS 356.4 375.2 624.3
------ ------ -------
COSTS CAPITALIZED DURING YEAR(b)
Acquisition - Unproved properties 0.7 1.1 7.5
Exploration 2.7 4.3 24.3
Development 8.7 15.5 69.0
------ ------ -------
COSTS CAPITALIZED 12.1 20.9(c) 100.8
------ ------ -------
</TABLE>
(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 $0.9 million in
1996, $1.7 million in 1995 and $6.4 million in 1994.
(c) Excludes capital expenditures for properties held for sale.
<TABLE>
<CAPTION>
HISTORICAL RESULTS
OF OPERATIONS APPALACHIA SOUTHWEST TOTAL
- - ------------------------ ---------------------- --------------------- ------------------------
($ in millions) 1996 1995 1994 1996 1995 1994 1996 1995 1994
- - ------------------------ ---- ---- ---- ---- ---- ---- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gross revenues
Unaffiliated 43.1 46.6 56.6 - 60.1 74.3 43.1 106.7 130.9
Affiliated 58.8 32.8 29.5 - 35.9 39.2 58.8 68.7 68.7
Production costs 21.7 21.2 23.0 - 26.7 29.0 21.7 47.9 52.0
Depletion 28.8 39.5 37.4 - 47.0 48.4 28.8 86.5 85.8
Income tax expense 15.1 6.5 9.0 - 7.8 12.6 15.1 14.3 21.6
---- ---- ---- ---- ---- ---- ---- ----- -----
RESULTS OF OPERATIONS 36.3 12.2 16.7 - 14.5 23.5 36.3 26.7 40.2
---- ---- ---- ---- ---- ---- ---- ----- -----
</TABLE>
Results of operations for exploration and production activities exclude
administrative and general costs, corporate overhead and interest expense.
Income tax expense is expressed at statutory rates less Section 29 credits.
70
<PAGE> 71
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
OTHER EXPLORATION AND PRODUCTION DATA 1996 1995 1994
- - ---------------------------------------------------------------- ----- ----- -----
<S> <C> <C> <C>
AVERAGE SALES PRICE PER MCF OF GAS ($)* 2.84 1.96 2.18
AVERAGE SALES PRICE PER BARREL OF OIL AND OTHER LIQUIDS ($) 19.07 16.17 15.09
PRODUCTION (LIFTING) COST PER DOLLAR OF GROSS REVENUE ($) 0.22 0.27 0.26
DEPLETION RATE PER DOLLAR OF GROSS REVENUE ($) 0.29 0.49 0.43
----- ----- -----
</TABLE>
*INCLUDES THE EFFECT OF HEDGING ACTIVITIES
<TABLE>
<CAPTION>
RESERVE QUANTITY INFORMATION
- - -----------------------------------------------------------------------------------------------------
Oil and Other
Gas Liquids
Proved Reserves (Bcf) (000 Bbls)
--------------- ----- ----------
<S> <C> <C>
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(a) (144.9) (9,901)
- - ----------------------------------------------------------------------------- ------- -------
Reserves as of December 31, 1995 599.5 1,651
Revisions of previous estimate 78.9 (169)
Extensions, discoveries and other additions 5.5 161
Production (33.6) (281)
Sale of reserves-in-place (5.8) (588)
- - ----------------------------------------------------------------------------- ------- -------
RESERVES AS OF DECEMBER 31, 1996 644.5 774
- - ----------------------------------------------------------------------------- ------- -------
Proved developed reserves as of December 31,
1994 543.3 11,504
1995 471.6 1,608
1996 518.3 730
- - ----------------------------------------------------------------------------- ------- ------
</TABLE>
(a) Includes the sale of Columbia Development
71
<PAGE> 72
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
- - ---------------------------------------------------------------------------------------------------------------------
APPALACHIA SOUTHWEST TOTAL
- - ------------------------------------------------------- ---------------------------- ------------------------------
($ in millions) 1996 1995 1994 1996 1995 1994 1996 1995 1994
- - --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Future cash inflows 2,389.1 1,793.8 1,274.8 - - 392.5 2,389.1 1,793.8 1,667.3
Future production costs (715.5) (606.7) (380.9) - - (111.1) (715.5) (606.7) (492.0)
Future development costs (165.8) (166.3) (124.5) - - (43.5) (165.8) (166.3) (168.0)
Future income tax expense (499.7) (327.1) (233.8) - - (46.8) (499.7) (327.1) (280.6)
- - --------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,008.1 693.7 535.6 - - 191.1 1,008.1 693.7 726.7
Less 10% discount 574.4 377.7 285.4 - - 35.0 574.4 377.7 320.4
- - --------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF
DISCOUNTED FUTURE
NET CASH FLOW 433.7 316.0 250.2 - - 156.1 433.7 316.0 406.3
- - --------------------------------------------------------------------------------------------------------------------
</TABLE>
Future cash inflows are computed by applying year-end prices to estimated
future production of proved gas and oil reserves. Future expenditures (based
on year-end costs) represent those costs to be incurred in developing and
producing the reserves. Discounted future net cash flows are derived by
applying a 10 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 gas and oil producing
properties or the true present value of estimated future cash flows since
many arbitrary assumptions are used. The data does provide a means of
comparison among companies through the use of standardized measurement
techniques.
72
<PAGE> 73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
A reconciliation of the components resulting in changes in the
standardized measure of discounted cash flows attributable to proved gas
and oil reserves for the three years ending December 31 follows:
<TABLE>
<CAPTION>
- - -------------------------------------------------------------------------------
($ in millions) 1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Beginning of year 316.0 406.3 551.4
------ ------ ------
Gas and oil sales,
net of production
costs (80.2) (124.3) (147.6)
Net changes in prices
and production costs 170.4 132.7 (236.5)
Change in future
development costs 0.5 (49.7) 4.1
Extensions, discoveries
and other additions,
net of related costs 9.4 106.5 68.2
Revisions of previous
estimates, net of
related costs 90.1 72.5 (17.3)
Sales of reserves-in-place (18.4) (195.6) (0.5)
Purchases of reserves-in-place - - 1.0
Accretion of discount 46.0 55.2 77.8
Net change in income taxes (65.3) (64.9) 80.8
Timing of production
and other changes (34.8) (22.7) 24.9
----- ------ -----
END OF YEAR 433.7 316.0 406.3
----- ------ -----
</TABLE>
The estimated discounted future net cash flows increased during 1996
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.
73
<PAGE> 74
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)
<TABLE>
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
1996 12.3 25.6 17.7 39.4 16.2
1995 11.6 31.6 11.3 42.2 12.3
1994 11.8 21.5 15.8 37.5 11.6
</TABLE>
(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.
74
<PAGE> 75
ITEM 9.
CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE There has not been a change of accountants nor any disagreements
concerning accounting and financial disclosure within the past two years.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Certain information required by this item is contained in Columbia's Proxy
Statement related to the 1996 Annual Meeting of Stockholders, to be filed
pursuant to Section 14 of the Securities Exchange Act of 1934 and is
incorporated herein by reference.
Information regarding Columbia's current executive officers, is as follows:
OLIVER G. RICHARD III, 44, 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, 50, Senior Vice President and Chief Legal Officer of
Columbia and Columbia Gas System Service Corporation since August 1995.
Senior Vice President of Columbia and the Columbia Gas System 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, 52, 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.
CATHERINE GOOD ABBOTT, 46, 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.
STEPHEN J. HARVEY, 36, Vice President of Columbia since January 1996.
Principal with Gem Energy Consulting, Inc., from 1995 to January 1996.
President of NJR Energy, a subsidiary of New Jersey Resources, from 1993 to
1995.
Information regarding Columbia's former executive officers is as follows:
C. RONALD TILLEY, 61, former Chairman and Chief Executive Officer of Columbia
Distribution Companies from January 1987 to January 1996.
JAMES P. HOLLAND, 48, former Chairman and Chief Executive Officer of Columbia
Transmission and Columbia Gulf from September 1990 to January 1996.
75
<PAGE> 76
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in Columbia's Proxy Statement
related to the 1997 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein
by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is contained in Columbia's Proxy Statement
related to the 1997 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein
by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is contained in Columbia's Proxy Statement
related to the 1997 Annual Meeting of Stockholders, to be 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 78 through 80 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 January 28, 1997, containing a Press
Release published on January 27, 1997, regarding the financial and operating
results for the year ended December 31, 1996.
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.
33-03869 (filed May 16, 1996) 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.
76
<PAGE> 77
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: March 14, 1997
By: /s/ Oliver G. Richard III
-------------------------------
(Oliver G. Richard III)
Director (Principal
Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<S> <C> <C> <C>
Mar. 14, 1997 /s/Oliver G. Richard III Mar. 14, 1997 /s/Jeffrey W. Grossman
----------------------------- -----------------------
Director (Principal Vice President & Controller
Executive Officer) (Principal Accounting Officer)
Mar. 14, 1997 /s/Richard F. Albosta Mar. 14, 1997 /s/Robert H. Beeby
----------------------------- -----------------------
Richard F. Albosta Robert H. Beeby
Director Director
Mar. 14, 1997 /s/Wilson K. Cadman Mar. 14, 1997 /s/Malcolm T. Hopkins
----------------------------- -----------------------
Wilson K. Cadman Malcolm T. Hopkins
Director Director
Mar. 14, 1997 Mar. 14, 1997 /s/William E. Lavery
----------------------------- -----------------------
James Heffernan William E. Lavery
Director Director
Mar. 14, 1997 /s/Donald P. Hodel Mar. 14, 1997 /s/Michael W. O'Donnell
----------------------------- -----------------------
Donald P. Hodel Michael W. O'Donnell
Director Senior Vice President
(Chief Financial Officer)
Mar. 14, 1997 /s/Malcolm Jozoff Mar. 14, 1997 /s/Douglas E. Olesen
----------------------------- -----------------------
Malcolm Jozoff Douglas E. Olesen
Director Director
Mar. 14, 1997 /s/Gerald E. Mayo Mar. 14, 1997 /s/James R. Thomas, II
----------------------------- -----------------------
Gerald E. Mayo James R. Thomas, II
Director Director
Mar. 14, 1997 /s/Ernesta G. Procope Mar. 14, 1997 /s/William R. Wilson
----------------------------- -----------------------
Ernesta G. Procope William R. Wilson
Director Director
Mar. 14, 1997
-----------------------------
J. Bennett Johnston
Director
</TABLE>
77
<PAGE> 78
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.
<TABLE>
<CAPTION>
Reference
---------------------
File No. Exhibit
--------- -------
<S> <C> <C>
3-A - Restated Certificate of Incorporation of The Columbia 1-1098 3-A
Gas System, Inc., dated as of November 28, 1995.
3-B - By-Laws of The Columbia Gas System, Inc., as amended dated 1-1098 3-B
November 18, 1987.
4-A - Indenture between The Columbia Gas System, Inc. 33-64555 4-S
and Marine Midland Bank, N.A. Trustee, dated as of
November 28, 1995.
4-B - First Supplemental Indenture, between The Columbia Gas 33-64555 4-T
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-C - Second Supplemental Indenture, between The Columbia Gas 33-64555 4-U
System, Inc., and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-D - Third Supplemental Indenture, between The Columbia Gas 33-64555 4-V
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-E - Fourth Supplemental Indenture, between The Columbia Gas 33-64555 4-W
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-F - Fifth Supplemental Indenture, between The Columbia Gas 33-64555 4-X
System, Inc. and Marine Midland Bank, N.A. Trustee,
dated as of November 28, 1995.
4-G - Sixth Supplemental Indenture, between The Columbia Gas 33-64555 4-Y
System, Inc. and Marine Midland Bank, N.A. Trustee, dated
as of November 28, 1995.
4-H - Seventh Supplemental Indenture, between The Columbia 33-64555 4-Z
Gas System, Inc. and Marine Midland Bank, N.A., Trustee,
dated as of November 28, 1995.
10-P(a) - Pension Restoration Plan of The Columbia Gas 1-1098 10-P
System, Inc., amended October 9, 1991.
10-Q(a) - Thrift Restoration Plan of The Columbia Gas 1-1098 10-Q
System, Inc. dated January 1, 1989.
10-T - Agreement and Bridge Agreement dated 1-1098 10-T
December 1, 1993, between Columbia Gas
Transmission Corporation and Consol
Pennsylvania Coal Company.
10-AE - U.S. Environmental Protection Agency Administrative 1-1098 10-AE
Order by Consent for Removal Actions for Columbia Gas
Transmission Corporation dated September 22,1994.
10-AF - Amended and Restated Indenture of Mortgage and 1-1098 10-AF
Deed of Trust by Columbia Gas Transmission
Corporation to Wilmington Trust Company,
dated as of November 28, 1995
</TABLE>
- - ----------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
78
<PAGE> 79
ITEM 14. EXHIBIT INDEX (Continued)
<TABLE>
<CAPTION>
Reference
---------------------
File No. Exhibit
---------------------
<S> <C> <C>
10-BB(a) - Annual Incentive Compensation Plan of The Columbia Gas 1-1098 10-BB
System, Inc., dated November 16, 1988.
10-BC(a) - Employment Agreement between Oliver G. Richard III 1-1098 10-BC
and The Columbia Gas System, Inc., dated March 15, 1995.
10-BE(a) - Employment Agreement between Peter M. Schwolsky 1-1098 10-BE
and The Columbia Gas System, Inc., dated May 30, 1995.
10-BF(a) - Employment Agreement between Catherine Good Abbott
and The Columbia Gas System, Inc., dated January 17, 1996.
10-BU - Share Sale and Purchase Agreement between The 1-1098 10-BU
Columbia Gas System, Inc. and Anderson Exploration
Ltd. dated November 25, 1991.
10-BV - Security Agreement dated as of January 15, 1992, 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 1-1098 10-CB
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 1-1098 10-CC
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 21, 1997, and the written
consent to the filing and use of information contained in
such letter report, Reports and Registration Statements
filed during 1997, of Ryder Scott Company Petroleum
Engineers, independent petroleum and natural gas
consultants.
</TABLE>
- - ----------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
* Filed herewith.
79
<PAGE> 80
ITEM 14. EXHIBIT INDEX (Continued)
<TABLE>
<CAPTION>
Reference
---------------------
File No. Exhibit
-------- -------
<S> <C> <C>
23-B* - Written consent of Arthur Andersen LLP,
independent public accountants, to the
incorporation by reference of their report
included in the 1996 Annual Report on Form
10-K of The Columbia Gas System, Inc. and
their report included in The Columbia Gas
System, Inc.'s 1996 Annual Report to Shareholders
in the registration statements on Form S-8
(File No. 33-03869), and Form S-8
(File No. 33-42776).
27* - Financial Data Schedule for the period ended
December 31, 1996.
</TABLE>
- - ----------
*Filed herewith.
80
<PAGE> 1
EXHIBIT 11
THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES
Statements Re Computation of Per Share Earnings
Year Ended December 31,
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Computation for Statements of Consolidated
- - ------------------------------------------
Income ($ in millions)
- - ----------------------
Income (Loss) before extraordinary item and
cumulative effect of accounting change.................................... 221.6 (432.3) 246.2
Extraordinary item ........................................................ - 71.6 -
Change in accounting for postemployment benefits - - (5.6)
- - --------------------------------------------------------------------------------------------------------------------------------
Net income (loss).......................................................... 221.6 (360.7) 240.6
- - --------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) per share of common stock (based
on average shares outstanding) ($)
Before extraordinary item and accounting change 4.12 (8.57) 4.87
Extraordinary item ........................................................ - 1.42 -
Change in accounting for postemployment benefits - - (0.11)
- - --------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) on common stock ........................................... 4.12 (7.15) 4.76
================================================================================================================================
Additional computation of average common
shares outstanding (thousands) NOTE
- - --------------------------------------------------------------------------------------------------------------------------------
Average shares of common stock outstanding 53,782 50,468 50,560
Incremental common shares applicable to
common stock based on the common stock
daily average market price:
Applicable to contingent stock awards.................................... 5 - 3
Applicable to contingent stock options................................... 97 - -
- - --------------------------------------------------------------------------------------------------------------------------------
Average common shares as adjusted ......................................... 53,884 50,468 50,563
================================================================================================================================
Average shares of common stock outstanding 53,782 50,468 50,560
Incremental common shares applicable to
common stock based on the more dilutive
of the common stock ending or daily average
market price during the year:
Applicable to contingent stock awards.................................... 5 - 3
Applicable to contingent stock options................................... 159 - -
- - --------------------------------------------------------------------------------------------------------------------------------
Average common shares assuming full dilution 53,946 50,468 50,563
================================================================================================================================
Earnings (Loss) per share of common stock as adjusted:
Before extraordinary item and accounting change 4.11 (8.57) 4.87
Extraordinary item ........................................................ - 1.42 -
Change in accounting for postemployment benefits - - (0.11)
- - --------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) on common stock as adjusted ($) 4.11 (7.15) 4.76
================================================================================================================================
Earnings (Loss) per common shares assuming full dilution:
Before extraordinary item and accounting change 4.11 (8.57) 4.87
Extraordinary item ........................................................ - 1.42 -
Change in accounting for postemployment benefits - - (0.11)
- - --------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) on common stock assuming full
dilution ($).............................................................. 4.11 (7.15) 4.76
================================================================================================================================
</TABLE>
NOTE These caculations are submitted in accordance with the Securities
Exchange Act of 1934 Release No. 9083 although not required by
footnote 2 to paragraph 14 of Accounting Principles Opinion No. 15
because they result in dilution of less than 3%.
<PAGE> 1
Exhibit 12
THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES
Statements of Ratio of Earnings to Fixed Charges
($ in millions)
<TABLE>
<CAPTION>
Twelve Months
Ended December 31,
----------------------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Consolidated Income (Loss) from Continuing Operations
before Income Taxes, Extraordinary Item and Cumulative
Effect of Accounting Change................................ 337.5 (643.0) 392.2 288.1 161.4
Adjustments:
Interest during construction ............................. (1.1) (20.2) - - -
Distributed (Undistributed) equity income................. 1.5 (7.9) (0.9) (0.1) (0.1)
Fixed charges ............................................ 164.3 1,040.8 14.8 101.5 13.7
-------- -------- -------- -------- --------
Earnings Available...................................... 502.2 369.7 406.1 389.5 175.0
-------- -------- -------- -------- --------
Fixed Charges:
Interest on long-term and short-term debt................. 150.8 987.2 0.7 3.1 4.9
Other interest ........................................... 13.5 53.6 14.1 98.4 8.8
Portion of rentals representing interest.................. 20.3 20.5 18.9 18.5 19.3
-------- -------- -------- -------- --------
Total Fixed Charges*,**................................. 184.6 1,061.3 33.7 120.0 33.0
-------- -------- -------- -------- --------
Ratio of Earnings Before Taxes to Fixed Charges............. 2.72 N/A(a) 12.05 3.25 5.30
======== ======== ======== ======== ========
</TABLE>
(a) To achieve a one-to-one coverage, the Corporation would need an additional
$691.6 million of earnings in 1995.
* This amount excludes approximately $230 million, $210 million and $204
million of interest expenses not recorded for the twelve months ended
1994, 1993 and 1992, respectively. Includes interest expense of $982.9
including write-off of unamortized discounts on debentures recorded in
1995. Reference is made to the Statements of Consolidated Income for the
twelve months ended December 31, 1995, as reported on Form 10-K and to
Note 2 of Notes to Consolidated Financial Statements of the Corporation's
Annual Report on Form 10-K for the year ended December 31, 1995.
** This amount excludes $8.6 million of interest expense not recorded with
respect to the registrant's guarantee of LESOP Trust's debentures for the
twelve months ended December 31, 1994, 1993 and 1992.
<PAGE> 1
EXIBIT 21
SUBSIDIARIES OF THE COLUMBIA GAS SYSTEM, INC.
as of December 31, 1996
<TABLE>
<CAPTION>
State of
Segment / Subsidiary Incorporation
- - ----------------------------------------- -------------
<S> <C>
Transmission and Staorage Operations
- - ------------------------------------
Columbia Gas Transmission Corporation Delaware
Columbia Gulf Transmission Company Delaware
Columbia LNG Corporation Delaware
Distribution Operations
- - -----------------------
Columbia Gas of Kentucky, Inc. Kentucky
Columbia Gas of Maryland, Inc. Delaware
Columbia Gas of Ohio, Inc. Ohio
Columbia Gas of Pennsylvania, Inc. Pennsylvania
Commonwealth Gas Services, Inc. Virginia
Exploration and Production Operations
- - -------------------------------------
Columbia Natural Resources, Inc. Texas
Marketing, Propane and Power Generation
- - ---------------------------------------
Columbia Atlantic Trading Corporation Delaware
Columbia Network Services Corporation Delaware
Columbia Energy Services Corporation Kentucky
Columbia Propane Corporation Delaware
Commonwealth Propane, Inc. Virginia
TriStar Ventures Corporation Delaware
TriStar Capital Corporation Delaware
Corporate
- - ---------
Columbia Gas System Service Corporation Delaware
Columbia Insurance Corporation, LTD Delaware
</TABLE>
<PAGE> 1
EXHIBIT 23-A
CONSENT
As independent petroleum and natural gas consultants, we
hereby consent to the filing of this Letter Report dated January 21, 1997 in its
entirety as an Exhibit to the 1996 Annual Report of The Columbia Gas System,
Inc., to the Securities and Exchange Commission on Form 10-K, and any
Registration Statement of The Columbia Gas System, Inc., relating to the issue
of securities to the public during 1997; to the quotation or summarization of
portions of this Letter Report, subject to our approval of the related page(s)
of the document(s), in the 10-K, the Prospectus included in said Registration
Statement(s) or the 1996 Annual Report to Stockholders; and, subject to approval
of the related page(s) of the document(s), to the use of our name and the
reliance upon our authority as experts in said Annual Report to Stockholders,
Form 10-K and Prospectus(es) and in Part II of said Registration Statement(s).
We have no interest of a substantial or material nature in The Columbia Gas
System, Inc., or in any affiliate, nor are we to receive any such interest as
payment for the preparation of this Letter Report; we have not been employed for
such preparation on a contingent fee basis; and we are not connected with The
Columbia Gas System, Inc., or any affiliate as a promoter, underwriter, voting
trustee, director, officer, employee, or affiliate.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
January 21, 1997
<PAGE> 2
January 21, 1997
The Columbia Gas System, Inc.
Suite 300, Sunrise Plaza
12355 Sunrise Valley Drive
Reston, Virginia 20191-3420
Attention: Mr. Jeffrey W. Grossman, Vice President and Controller
Arthur Andersen LLP
1345 Avenue of the Americas
New York, New York 10105
Attention: Mr. Dave Gorin
Gentlemen:
The estimated reserve volumes and future income amounts
presented in this report are related to hydrocarbon prices. December 1996
hydrocarbon prices were used in the preparation of this report as required by
Securities and Exchange Commission (SEC) and Financial Accounting Standards
Bulletin No. 69 (FASB 69) guidelines; however, actual future prices may vary
significantly from December 1996 prices. Therefore, volumes of reserves actually
recovered and amounts of income actually received may differ significantly from
the estimated quantities presented in this report.
Our estimates of the net proved reserves attributable to the
interests of The Columbia Gas System, Inc. (referred to herein as the Company)
as of December 31, 1996 are presented below. Table 1 is a tabulation of the oil,
gas, and natural gas liquid reserves. The Company's reserves are located in the
states of Kentucky, Maryland, Michigan, New York, Ohio, Pennsylvania, Virginia
and West Virginia.
<TABLE>
<CAPTION>
Proved Net Reserves
As of December 31, 1996
---------------------------------------------------------
Liquid, Barrels Gas, MMCF
-------------------------- --------------------------
<S> <C> <C>
Developed and Undeveloped 774,073 644,450
Developed 730,323 518,317
</TABLE>
The "Liquid" reserves shown above are comprised of crude oil
and condensate. All hydrocarbon liquid reserves are expressed in standard 42
gallon barrels. All gas volumes are sales gas
<PAGE> 3
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 3
expressed in MMCF at the pressure and temperature bases of the area where the
gas reserves are located.
In accordance with the requirements of FASB 69, our estimates
of the Company's net proved reserves as of December 31, 1993, 1994, 1995, and
1996, as contained in this report and our previous reports, are presented in
attached Table No. 2 together with a tabulation of the components of the
differences in the estimates as of such dates.
<PAGE> 4
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 4
The proved reserves presented in this report comply with the
SEC's Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent
Commission Staff Accounting Bulletins, and are based on the following
definitions and criteria:
Proved reserves of crude oil, condensate, natural gas, and
natural gas liquids are estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in the future from known reservoirs under existing
conditions. Reservoirs are considered proved if economic producibility
is supported by actual production or formation tests. In certain
instances, proved reserves are assigned on the basis of a combination
of core analysis and electrical and other type logs which indicate the
reservoirs are analogous to reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation
test. The area of a reservoir considered proved includes (1) that
portion delineated by drilling and defined by fluid contacts, if any,
and (2) the adjoining portions not yet drilled that can be reasonably
judged as economically productive on the basis of available geological
and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir. Proved reserves are estimates of
hydrocarbons to be recovered from a given date forward. They may be
revised as hydrocarbons are produced and additional data become
available. Proved natural gas reserves are comprised of non-associated,
associated, and dissolved gas. An appropriate reduction in gas reserves
has been made for the expected removal of natural gas liquids, for
lease and plant fuel, and the exclusion of non-hydrocarbon gases if
they occur in significant quantities and are removed prior to sale.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification
when these qualifications are met: (1) successful testing by a pilot
project or the operation of an installed program in the reservoir
provides support for the engineering analysis on which the project or
program was based, and (2) it is reasonably certain the project will
proceed. Improved recovery includes all methods for supplementing
natural reservoir forces and energy, or otherwise increasing ultimate
recovery from a reservoir, including (1) pressure maintenance, (2)
cycling, and (3) secondary recovery in its original sense. Improved
recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement
fluids. Estimates of proved reserves do not include crude oil, natural
gas, or natural gas liquids being held in underground storage.
Depending on the status of development, these proved reserves are
further subdivided into:
(i) "developed reserves" which are those proved reserves
reasonably expected to be recovered through existing wells with
existing equipment and operating methods, including (a)
"developed producing reserves" which are those proved developed
reserves reasonably expected to be produced from existing
completion intervals now open for production in existing wells4
and (b) "developed non-producing reserves" which are those
proved developed reserves which exist behind the casing of
existing wells which are reasonably expected to be produced
through these wells in the predictable future where the cost of
making such hydrocarbons available for production should be
relatively small compared to the cost of a new well; and
<PAGE> 5
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 5
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on undrilled
acreage, from existing wells where a relatively large
expenditure is required, and from acreage for which an
application of fluid injection or other improved recovery
technique is contemplated where the technique has been proved
effective by actual tests in the area in the same reservoir.
Reserves from undrilled acreage
<PAGE> 6
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 6
are limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units are included only where it
can be demonstrated with reasonable certainty that there is
continuity of production from the existing productive formation.
Because of the direct relationship between volumes of proved
undeveloped reserves and development plans, we include in the proved undeveloped
category only reserves assigned to undeveloped locations that we have been
assured will definitely be drilled and reserves assigned to the undeveloped
portions of secondary or tertiary projects which we have been assured will
definitely be developed.
The Company has interests in certain tracts which have
substantial additional hydrocarbon quantities which cannot be classified as
proved and consequently are not included herein. The Company has active
exploratory and development drilling programs which may result in the
reclassification of significant additional volumes to the proved category.
In accordance with the requirements of FASB 69, our estimates
of future cash inflows, future costs, and future net cash inflows before income
tax as of December 31, 1996 from this report and as of December 31, 1995 from
our previous report are presented below.
<TABLE>
<CAPTION>
As of December 31
($000)
-----------------------------------------------
1996 1995
--------------------- ------------------
<S> <C> <C>
Future Cash Inflows $2,389,131 $2,256,591
Future Costs
Production $ 715,535 $ 711,564
Development 165,759 217,685
---------- ----------
Total Costs $ 881,294 $ 929,249
Future Net Cash Inflows
Before Income Tax $1,507,837 $1,327,342
Present Value at 10%
Before Income Tax $ 639,932 $ 706,832
</TABLE>
The future cash inflows are gross revenues before any
deductions. The production costs were based on current data and include
production taxes, ad valorem taxes, and certain other items such as
transportation costs in addition to the operating costs directly applicable to
the individual leases or wells.
<PAGE> 7
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 7
The development costs were based on current data and include certain
dismantlement and abandonment costs net of salvage. Table 3 presents a
tabulation showing future cash inflow data by subsidiary.
The Company furnished us with gas prices in effect at
December 31, 1996 and with its forecasts of future gas prices which take into
account SEC guidelines, current market prices, contract prices, and fixed and
determinable price escalations where applicable. In accordance with SEC
guidelines, the future gas prices used in this report make no allowances for
future gas price increases which may occur as a result of inflation nor do they
account for seasonal variations in gas prices which may cause future yearly
average gas prices to be somewhat lower than December gas prices. For gas sold
under contract, the contract gas price including fixed and determinable
escalations
<PAGE> 8
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 8
exclusive of inflation adjustments, was used until the contract expires and then
was adjusted to the current market price for the area and held at this adjusted
price to depletion of the reserves.
The Company furnished us with liquid prices in effect at
December 31, 1996 and these prices were held constant to depletion of the
properties. In accordance with SEC guidelines, changes in liquid prices
subsequent to December 31, 1996 were not considered in this report.
Operating costs for the leases and wells in this report are
based on the operating expense reports of the Company and include only those
costs directly applicable to the leases or wells. When applicable, the operating
costs include a portion of general and administrative costs allocated directly
to the leases and wells under terms of operating agreements. Development costs
were furnished to us by the Company and are based on authorizations for
expenditure for the proposed work or actual costs for similar projects. The
current operating and development costs were held constant throughout the life
of the properties. The estimates of net abandonment costs furnished by the
Company were accepted without independent verification.
No deduction was made for indirect costs such as general
administration and overhead expenses, loan repayments, interest expenses, and
exploration and development prepayments. No attempt has been made to quantify or
otherwise account for any accumulated gas production imbalances that may exist.
No consideration was given in this report to potential environmental liabilities
which may exist nor were any costs included for potential inability to restore
and clean up damages, if any, caused by past operating practices. The Company
informed us that it has furnished us all of the accounts, records, geological
and engineering data and reports and other data required for our investigation
The ownership interests, prices and other factual data were accepted as
represented. Moreover, to facilitate timely issuance of this report, production
data used in this report includes estimated production for the last few months
of 1996.
The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may not be
actually recovered, and if recovered, the revenues therefrom and the actual
costs related thereto could be more or less than the estimated amounts.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells were then projected to decline at
their decreasing delivery capacity rate. Our general policy on estimates of
future gas production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases. The future production rates from wells now
on production may be more or less than estimated because of changes in market
demand or allowables set by regulatory bodies. Wells or locations which are not
currently producing may start producing earlier or later than anticipated in our
estimates of their future production rates.
<PAGE> 9
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 9
While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and other costs
relating to such production may also increase or decrease from existing levels,
such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation.
<PAGE> 10
The Columbia Gas System, Inc.
Arthur Andersen LLP
January 21, 1997
Page 10
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future cash inflows
for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Harry J. Gaston, Jr., P.E.
President
HJG/sw
<PAGE> 1
EXHIBIT 23-B
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated January 27, 1997, included in The Columbia Gas System, Inc.'s 1996
Annual Report on Form 10-K, into the following previously filed registration
statements:
1. Form S-8 of The Columbia Gas System, Inc. (File No. 33-03869)
2. Form S-8 of The Columbia Gas System, Inc. (File No. 33-42776)
New York, New York
March 10, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000022099
<NAME> THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES
<SUBSIDIARY>
<NUMBER> 1
<NAME> CGS
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,649,900
<OTHER-PROPERTY-AND-INVEST> 459,700
<TOTAL-CURRENT-ASSETS> 1,435,900
<TOTAL-DEFERRED-CHARGES> 49,000
<OTHER-ASSETS> 610,100
<TOTAL-ASSETS> 6,004,600
<COMMON> 552,600
<CAPITAL-SURPLUS-PAID-IN> 763,200
<RETAINED-EARNINGS> 259,300
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,553,600
0
0
<LONG-TERM-DEBT-NET> 2,003,800
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 900
0
<CAPITAL-LEASE-OBLIGATIONS> 2,400
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,447,200
<TOT-CAPITALIZATION-AND-LIAB> 6,004,600
<GROSS-OPERATING-REVENUE> 3,356,000
<INCOME-TAX-EXPENSE> 115,900
<OTHER-OPERATING-EXPENSES> 2,875,800
<TOTAL-OPERATING-EXPENSES> 2,875,800
<OPERATING-INCOME-LOSS> 478,200
<OTHER-INCOME-NET> 26,100
<INCOME-BEFORE-INTEREST-EXPEN> 504,300
<TOTAL-INTEREST-EXPENSE> 166,800
<NET-INCOME> 221,600
0
<EARNINGS-AVAILABLE-FOR-COMM> 221,600
<COMMON-STOCK-DIVIDENDS> 060
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 462,700
<EPS-PRIMARY> 4.12
<EPS-DILUTED> 4.11
</TABLE>
