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Commission File No. 1-1098
As filed with the Securities and Exchange Commission on March 6, 1995.
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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, 1994
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)
Delaware 13-1594808
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(State or other Jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
20 Montchanin Road, Wilmington, Delaware 19807-0020
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (302) 429-5000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common Stock, $10 Par Value . . . . . . . . . . . . . New York Stock Exchange
Debentures
9% Series due August 1993 7-1/2% Series due March 1997
9% Series due October 1994 7-1/2% Series due June 1997
8-3/4% Series due April 1995 7-1/2% Series due October 1997
9-1/8% Series due October 1995 7-1/2% Series due May 1998
10-1/8% Series due November 1995 10-1/4% Series due May 1999 New York Stock Exchange
8-3/8% Series due March 1996 9-7/8% Series due June 1999
9-1/8% Series due May 1996 10-1/4% Series due August 2011
8-1/4% Series due September 1996 10-1/2% Series due June 2012
Securities registered pursuant to Section 12(g) of the Act: None
SINCE JULY 31, 1991, THE COLUMBIA GAS SYSTEM, INC. AND ITS WHOLLY-OWNED
SUBSIDIARY COLUMBIA GAS TRANSMISSION CORPORATION HAVE BEEN OPERATING UNDER
BANKRUPTCY COURT PROTECTION PURSUANT TO CHAPTER 11 OF THE FEDERAL BANKRUPTCY
CODE.
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 February 28, 1995, was $1,313,328,900. For
purposes of the foregoing calculation, all directors and/or officers have been
deemed to be affiliates, but the registrant disclaims that any of such
directors and/or officers is an affiliate.
The number of shares outstanding of each class of common stock as of February
28, 1995, was : Common Stock $10 Par Value: 50,563,335 shares outstanding.
Documents Incorporated by Reference
Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the 1995 Annual Meeting of Stockholders.
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CONTENTS
Page
Part I No.
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Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . 17
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 17
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . 18
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations . . . . . . . . . . . . . . . . . . . . . 19
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . 50
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . 95
Part III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . 95
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . 96
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . 96
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . 96
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . 96
Undertaking made in Connection with 1933 Act Compliance on Form S-8 . . . . . . . . . . 97
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
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PART I
ITEM 1. BUSINESS
General
The Columbia Gas System, Inc. (the Corporation) 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. On July 31, 1991, the Corporation and its
wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia
Transmission), filed separate petitions for protection under Chapter 11 of the
Federal Bankruptcy Code. Both the Corporation and Columbia Transmission are
debtors-in-possession under the Bankruptcy Code and continue to operate their
businesses in the normal course subject to the jurisdiction of the United
States Bankruptcy Court for the District of Delaware. The Corporation owns all
of the securities of its subsidiaries except for approximately 8 percent of the
stock in Columbia LNG Corporation. The Corporation's subsidiaries are engaged
in natural gas transmission, natural gas distribution, exploration for and
production of oil and natural gas, and other energy operations. The
Corporation and its subsidiaries are sometimes referred to herein as the
System.
Transmission Operations
The Corporation's two interstate pipeline transmission companies, Columbia
Transmission and Columbia Gulf Transmission Company (Columbia Gulf), operate a
23,300-mile pipeline network that extends from offshore in the Gulf of Mexico
to New York State and the eastern seaboard. In addition, Columbia Transmission
operates one of the nation's largest underground storage systems.
Historically, Columbia Transmission offered both a wholesale sales service and
a transportation service to local distribution companies. However, when a new
federally mandated business restructuring of the industry took effect in late
1993, Columbia Transmission expanded its transportation and storage services
for local distribution companies and industrial and commercial customers and
now provides only a minimal sales service. Columbia Gulf's pipeline system,
which extends from offshore Louisiana to West Virginia, carries 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 Gulf
owns interests in the Overthrust, Ozark and Trailblazer pipelines, which extend
into major midcontinent and western gas-producing areas. Combined, Columbia
Transmission and Columbia Gulf serve customers in 15 northeastern, middle
Atlantic, midwestern, and southern states and the District of Columbia.
Distribution Operations
The Corporation's five distribution subsidiaries provide natural gas service to
more than 1.9 million residential, commercial and industrial customers in Ohio,
Pennsylvania, Virginia, Kentucky, and Maryland. These subsidiaries purchase
gas supplies to serve their high-priority customers and transport gas for
industrial and commercial customers who purchase gas from other sources. More
than 29,700 miles of distribution pipelines serve such major markets as
Columbus, Lorain, Parma, Springfield, and Toledo in Ohio; Gettysburg, York and
a part of Pittsburgh in Pennsylvania; Lynchburg, Staunton, Portsmouth and
Richmond suburbs in Virginia; Ashland, Frankfort and Lexington in Kentucky; and
Cumberland and Hagerstown in Maryland.
Oil and Gas Operations
The Corporation's oil and gas subsidiaries, Columbia Gas Development
Corporation and Columbia Natural Resources, Inc., explore for, develop,
produce, and market oil and natural gas in the United States. These companies
hold interests in more than two million net acres of gas and oil leases and
have proved oil and gas reserves in excess of 757 billion cubic feet of gas
equivalent.
Operations are focused in the Appalachian, Arkoma, Michigan, Permian, Powder
River and Williston basins; both onshore and offshore in the Gulf Coast areas
of Texas and Louisiana, and in Utah and California.
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ITEM 1. BUSINESS (Continued)
Offshore holdings include interests in federal blocks, most of which are
located in the West Cameron, Vermilion, Eugene Island, and Ship Shoal areas of
the Gulf of Mexico.
Other Energy Operations
The Corporation's TriStar Ventures Corporation participates in natural
gas-fueled cogeneration projects that produce both electricity and useful
thermal energy.
Columbia Propane Corporation and Commonwealth Propane, Inc., sell propane at
wholesale and retail to approximately 68,200 customers in eight states.
Columbia Coal Gasification Corporation owns over 500 million tons of coal
reserves in the Appalachian area, much of which contains less than one percent
sulfur. Approximately 50 percent of the total reserves are leased to other
companies for development.
Columbia LNG Corporation is a participant in a partnership that has received
the necessary regulatory approvals and anticipates having a gas peaking service
operational by the end of 1995 from the Cove Point LNG facility.
Columbia Energy Services oversees the System's nonregulated natural gas
marketing efforts and provides an array of supply and fuel management services
to distribution companies, independent power producers and other large end
users both on and off the transmission and distribution subsidiaries' pipeline
systems.
Columbia Gas System Service Corporation provides centralized, cost-efficient
data processing, financial, accounting, legal, and other services for the
Corporation and other subsidiaries.
For additional discussion of the System's business segments, including
financial information for the last three fiscal years, see Item 7, page 19
through 49 and Note 14 on page 87 of Item 8.
Other Relevant Business Information
The System's customer base is broadly diversified, with no single customer
accounting for a significant portion of revenues.
The Corporation's operating subsidiaries are subject to competitive pressures
from other pipeline systems and producers that sell and/or transport natural
gas as well as from competition from alternative fuels, primarily oil and
electricity. The transmission subsidiaries compete in the highly competitive
northeast and midwest energy markets. The distribution subsidiaries compete
with alternative fuels and to a limited extent with other gas companies. The
oil and gas subsidiaries compete in the marketplace for sales of their oil and
gas production through a combination of long-term contracts and spot sales.
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 1994 Annual
Report to Shareholders.
At January 31, 1995, the System had 9,935 full-time employees of which 2,086
are subject to collective bargaining agreements.
Information relating to environmental matters is detailed in Item 7 pages 32
through 33, page 40 and page 48 and in Item 8, Note 11G on pages 83 through 85.
For a listing of the subsidiaries of the Corporation and their lines of
business refer to Exhibit 21.
Public Utility Holding Company Act of 1935
The Corporation and its subsidiaries are subject, in certain matters, to the
jurisdiction of the Securities and Exchange Commission (SEC) under the 1935
Act. In 1944, the SEC held that the major portions of the System complied with
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ITEM 1. BUSINESS (Continued)
the requirements of Section 11 of the 1935 Act relating to a "single integrated
public-utility system" and businesses reasonably incidental thereto, but the
SEC reserved jurisdiction over the retainability of certain subsidiaries.
Included were two companies owning pipelines in West Virginia and Northern
Virginia extending into Maryland and New York (the reserved pipelines are now
part of Columbia Transmission) and Virginia Gas Distribution Corporation (now a
part of Commonwealth Gas Services, Inc.). Since that time, the reservation of
jurisdiction has been expanded to include the subsequently acquired properties
of Blue Ridge Gas Company (a Virginia retail company which is now part of
Commonwealth Gas Services, Inc.), Commonwealth Gas Pipeline Corporation (now a
part of Columbia Transmission) and a retail subsidiary (Commonwealth Gas
Services, Inc.) acquired as a result of the merger of the Corporation with
Commonwealth Natural Resources, Inc. and Lynchburg Gas Company, (now a part of
Commonwealth Gas Services, Inc.).
The Corporation filed a motion with the SEC in June 1955 requesting the
termination of such reserved jurisdiction. After hearings, no further action
has been taken and the Corporation is unable to predict whether or when the SEC
will finally dispose of the Corporation's 1955 motion and resolve the
retainability issue.
The Gas Related Activities Act (GRAA), enacted in 1990, provides that gas
transmission is deemed to be reasonably incidental or economically necessary or
appropriate to the operation of the gas utility system under Section 11 of the
1935 Act. Since the basis for questioning the retainability of the gas
transmission pipelines was compliance with this Section 11 criteria, the
passage of the GRAA supports, and should resolve, the retainability of the gas
transmission pipelines.
If however, any of these properties were ultimately to be held not retainable,
management believes that the SEC would permit the Corporation to adopt a plan
for orderly disposition which would permit full realization of their intrinsic
values.
ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed on pages
6 through 7 herein and pages 90 through 93 of Item 8 under Note 16. The System
also owns coal interests in the Appalachian area. Assets under lien and other
guarantees are described on page 82 in Note 11D of Item 8.
Neither the Corporation nor any subsidiary knows of material defects in the
title to any real properties of the subsidiaries of the Corporation or of any
material adverse claim of any right, title, or interest therein, pending or
contemplated except the Official Committee of Unsecured Creditors of Columbia
Transmission has filed a complaint which challenges the 1990 property transfer
from Columbia Transmission to Columbia Natural Resources, Inc. as an alleged
fraudulent transfer. Substantially all of Columbia Transmission's property has
been pledged to the Corporation as security for First Mortgage Bonds issued by
Columbia Transmission to the Corporation which has also been challenged by the
Official Committee of Unsecured Creditors of Columbia Transmission.
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ITEM 2. PROPERTIES (Continued)
OIL AND GAS DATA
Acreage - At December 31, 1994
Developed Acreage Undeveloped Acreage
---------------------------- -------------------------------
Gross Net Gross Net
--------- ------- ---------- -------
Appalachian . . . . . . . . . . . 1,630,698 1,562,512 827,019 667,917
Southwest - Onshore . . . . . . . 66,729 26,818 126,071 67,095
Southwest - Offshore . . . . . . 167,925 52,719 52,481 17,701
Rocky Mountain . . . . . . . . . 21,476 10,591 195,153 122,919
Other Areas . . . . . . . . . . . 1,034 168 2,914 352
----------- ---------- ----------- -----------
Total . . . . . . . . . . . 1,887,862 1,652,808 1,203,638 875,984
=========== ========== =========== ===========
Net Wells Completed - 12 Months Ended December 31
Exploratory Development Total
----------------------------- ------------------------------ -----------------------
Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- -----
1994 . . . . 3 9 78 14 81(a) 23
1993 . . . . 2 10 91 18 93(a) 28
1992 . . . . 9 14 37 7 46(a) 21
Productive and Drilling Wells - At December 31, 1994
Production Wells
---------------------------------------------
Gross(b) Net Wells Drilling
-------------- ------------------ ---------------
Gas Oil Gas Oil Gross Net
------ ----- --- --- ----- ---
6,512 662 5,836 361 25 11
(a) Includes 17 net horizontal wells in 1994, 17 net horizontal wells in 1993
and 13 net horizontal wells in 1992.
(b) Includes 807 multiple completion gas wells and 16 multiple completion oil
wells, all of which are included as single wells in the table. Also
includes 42 gross productive horizontal wells.
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GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1994
Miles of Pipeline Compressor Stations
Underground ------------------------------- -------------------
Storage Gathering Installed
--------------- and Trans- Distri- Capacity
Subsidiaries State Acreage Wells Storage mission mission Number (hp)
- -------------------------------------------- ----- ------- ----- --------- ------- ------- ------ ---------
Columbia Gas of Kentucky, Inc. . . . . . . KY - - - - 2,204 - -
Columbia Gas of Maryland, Inc. . . . . . . MD - - - - 573 - -
Columbia Gas of Ohio, Inc. . . . . . . . . OH - - - - 16,911 - -
Columbia Gas of Pennsylvania, Inc. . . . . PA 3,364 8 4 - 6,627 1 825
Commonwealth Gas Services, Inc. . . . . . . VA - - - - 3,416 - -
Columbia Gas Transmission Corporation . . . DE - - - 3 - - -
KY - - 939 766 - 4 16,220
MD 945 - 23 182 - 1 12,000
NJ - - - 78 - - -
NY 25,818 143 67 507 - 4 8,670
NC - - - 1 - 1 1,400
OH 483,200 2,459 2,764 4,123 - 33 101,145
PA 63,736 270 627 2,096 - 28 70,264
VA - - 128 1,104 - 10 55,806
WV 291,058 813 3,028 2,626 - 47 306,091
Columbia Gulf Transmission Company . . . . AR - - - 8 - - -
KY - - - 716 - 2 70,290
LA - - - 2,076 - 6 201,200
MS - - - 659 - 3 118,800
TN - - - 556 - 2 83,000
TX - - - 202 - - -
WY - - - 10 - - -
Columbia Natural Resources, Inc. . . . . . KY - - 423 - - - -
MI - - 6 - - - -
NY - - 2 - - - -
OH - - 78 - - - -
PA - - 8 - - - -
VA - - 23 - - - -
WV - - 166 - - - -
-------- ------- --------- --------- ---------- -------- ---------
Total . . . . . . . . . . . . . . . . . . . 868,121 3,693 8,286 15,713 29,731 142 1,045,711
======== ======= ========= ========= ========= ======= =========
NOTE: This table excludes minor gas properties and all construction work in
progress. The titles to the real properties of the subsidiaries of the
Corporation have not been examined for the purpose of this document.
Neither the Corporation nor any subsidiary knows of material defects in
the title to any of the real properties of the subsidiaries of the
Corporation or of any material adverse claim of any right, title, or
interest therein, pending or contemplated except the Official Committee
of Unsecured Creditors of Columbia Transmission has filed a complaint
which challenges the 1990 property transfer from Columbia Transmission
to Columbia Natural Resources, Inc. as an alleged fraudulent transfer.
Substantially all of Columbia Transmission's property has been pledged
to the Corporation as security for First Mortgage Bonds issued by
Columbia Transmission to the Corporation which has also been challenged
by the Official Committee of Unsecured Creditors of Columbia
Transmission
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ITEM 3. LEGAL PROCEEDINGS
I. Shareholder Class Actions and Derivative Suits (Unless otherwise noted,
all matters are stayed pursuant to Section 362 of the Bankruptcy Code)
After the June 19, 1991 announcement of the Corporation's proposed
charge to second quarter earnings and suspension of its dividend, seventeen
complaints including suits purporting to be class actions, or alleging claims
common to the purported class actions, were filed in the U.S. District Court
for the District of Delaware. These actions have been consolidated under the
style In re Columbia Gas Securities Litigation, Consol. C.A. No. 91-357. The
complaints named as defendants, the Corporation, members of the Corporation's
Board of Directors as of June 1991, certain officers, the Corporation's
independent public accountants, and the Corporation's underwriters for its 1990
common stock offering (the Defendants).
The complaints alleged violations of Sections 11, 12(2) and 15 of the
Securities Act of 1933, Sections 10(b), 20(a) and Rule 10b-5 of the Securities
Exchange Act of 1934, negligent misrepresentations, and common law fraud and
deceit. They generally asserted that the Defendants publicly made material
misleading statements during the relevant class periods (from February 28, 1990
to June 19, 1991) concerning the Corporation's financial condition, and failed
to disclose material facts which rendered other statements misleading, thereby
artificially inflating the market price of the Corporation's common stock and
publicly traded debt securities, causing the various plaintiffs and other class
members to purchase such publicly-traded securities at artificially inflated
prices.
On October 31, 1994, the class action plaintiffs filed an amended and
consolidated complaint against the non-debtor defendants in the District Court
alleging the same causes of action as the previously filed complaints. On
October 31, 1994, plaintiffs filed motions with both the District Court and the
Bankruptcy Court for certification of classes and for withdrawal of reference
to the U. S. District Court of the actions against individual defendants.
On November 1, 1994, the Corporation filed a motion in the U.S.
Bankruptcy Court for the District of Delaware seeking to require individual
class action plaintiffs to file information to supplement the class proofs of
claim filed in this litigation. If this procedure is approved, those
plaintiffs failing to respond will be barred from asserting their claims. The
motions filed by plaintiffs on October 31, 1994 and by the Corporation on
November 1, 1994 have been stayed by order of the U. S. District Court until
further order of the Court. On February 13, 1995, the Corporation, in order to
promptly address the securities claims in its plan of reorganization, requested
the District Court to modify the stay order to allow the District Court to
consider the Corporation's motion to supplement class proofs of claims. It
also advised the District Court that it was prepared to consent to a withdrawal
of the reference requested by the plaintiffs. The plaintiffs have objected to
a modification of the stay order which would limit the District Court's hearing
to the proofs of claim motion.
Also in 1991, three derivative actions were filed in the Court of
Chancery in and for New Castle County (Delaware) alleging that the
Corporation's directors breached their fiduciary duties at that time. These
suits have been stayed by either the Bankruptcy Court filing or by stipulation
of the parties.
While the Corporation and its officers and directors believe that they
have meritorious defenses to these actions, the outcome is uncertain at this
time.
II. Bankruptcy Matters
A. Matters in the United States Bankruptcy Court for the District of
Delaware
1. Motion to Fix Procedures to Establish Columbia Transmission's
Liability to Third Party Beneficiary Investor Complaints. On February 17,
1993, movants, who are investors in production companies and claim to be third
party beneficiaries of the contracts between Columbia Transmission and the
production companies, filed a motion seeking to have their status as third
party beneficiaries recognized and seeking to have their claims against
Columbia Transmission liquidated separate from the Estimation Procedure
established to deal with producer claims. By order dated April 5, 1993, the
Bankruptcy Court lifted the stay in order to allow the New Jersey State Court
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ITEM 3. LEGAL PROCEEDINGS (Continued)
to determine whether plaintiffs enjoyed third party beneficiary status in the
pending State Court action. However, the Bankruptcy Court held that movants'
claim would be subject to the estimation procedure. Oral argument was held
September 16, 1994. On November 9, 1994, the New Jersey State Court denied
cross-motions for summary judgment on the question of third party beneficiary
liability. On February 7, 1995, an order was entered finding that the
plaintiffs were not entitled to third party beneficiary status and dismissing
all claims with prejudice.
2. First National Bank of Boston, Trustee v. The Columbia Gas
System, Inc. On March 2, 1993, the Trustee for the Indenture under which
debentures were issued by the Employees' Thrift Plan of Columbia Gas System
(Plan) filed a complaint against the Corporation alleging tortious interference
with contract and breach of duty. The Indenture Trustee alleges that the
Corporation is not acting in accordance with the Plan when it directs the Plan
Trustee to use sums paid by participating employers to match employee
contributions and not to pay debt service on the outstanding debentures. The
Corporation's answer to the complaint alleging tortious interference with
contract for failure to pay installments due holders of debentures issued by
the Leveraged Employee Stock Ownership Plan Trust was filed on April 2, 1993.
The Indenture Trustee filed an amended adversary complaint on June 30, 1993.
On May 14, 1993, the Corporation filed a motion for summary judgment
challenging the Indenture Trustee's standing to bring the action. This motion
was denied by the Bankruptcy Court on March 24, 1994. Columbia filed a motion
for leave to appeal and a notice of appeal on April 22, 1994. On May 4, 1994,
the Indenture Trustee filed a motion for preliminary injunction which was
denied. The right to appeal was granted and oral argument before the U.S.
District Court for the District of Delaware was held on October 27, 1994.
B. Appeals to or actions in the United States District Court for the
District of Delaware
1. Columbia Gas System v. First National Bank of Boston, C.A. No.
94-230. See Item II.A.2 above.
2. Columbia Gas Transmission Corporation v. The Columbia Gas
System, Inc. and Columbia Natural Resources, Inc., C.A. No. 92-453. The
Official Committee of Unsecured Creditors of Columbia Transmission filed a
complaint (the Intercompany Complaint) challenging among other things the
status of approximately $1.7 billion of debt owed by Columbia Transmission to
the Corporation and the transfer of natural resource properties representing
450 billion cubic feet of natural gas reserves and one million barrels of oil
reserves to Columbia Natural Resources, Inc. (Columbia Natural Resources) as
well as other intercompany transactions. Trial began September 12, 1994 and
concluded on October 25, 1994. Post trial briefing concluded on December 20,
1994 and a decision is expected in the first quarter of 1995.
C. Appeals to the United States Court of Appeals for the Third Circuit
1. Enterprise Energy Corporation, et al., v. United States of
America, on behalf of its Internal Revenue Service, No. 93-7409. On June 18,
1991, the U.S. District Court for the Southern District of Ohio approved a
settlement of this class action suit by Appalachian oil and gas producers. The
settlement required Columbia Transmission to make two $15 million payments into
escrow, for distribution to class members as formal contract amendments were
finalized. The first $15 million was paid into escrow in March 1991.
Columbia Transmission filed an application with the Bankruptcy
Court which would permit it to honor the settlement (including authority to
make the second $15 million payment into escrow in March 1992) but to reject
the amended contracts. On December 12, 1991, the Bankruptcy Court ruled that
distribution from escrow of the first $15 million payment could be effected
pursuant to the settlement; however, the Bankruptcy Court denied Columbia
Transmission's request for approval to make the second $15 million payment
scheduled to be made in March 1992. Further, the Bankruptcy Court granted the
motion to reject the contracts, as amended, pursuant to the Enterprise
settlement.
On October 6, 1992, the District Court affirmed the Bankruptcy
Court's order denying Columbia Transmission's motion to assume the executory
settlement contract. Enterprise Energy Corp.'s request for
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ITEM 3. LEGAL PROCEEDINGS (Continued)
rehearing, reargument and reconsideration of the order denying Columbia
Transmission's motion to assume the executory settlement contract was denied on
April 27, 1993. On May 25, 1993, Enterprise Energy filed a notice of appeal to
the United States Court of Appeals for the Third Circuit from the Bankruptcy
Court order denying Columbia Transmission's motion to require assumption or
rejection of the executory settlement contract. Briefing is complete. Oral
argument was held January 18, 1994. A report regarding the status of the
Bankruptcy proceedings was filed December 1, 1994.
2. In re The Columbia Gas System, Inc. et al.; West Virginia Tax
and Revenue v. U.S., Nos. 93-7531 and 93-7532. This is the appeal of the
District Court's Memorandum Opinion and Order affirming the Bankruptcy Court's
ruling that the property taxes centrally assessed by West Virginia as public
service business taxes for the "1992 tax year" were incurred by Columbia
Transmission prepetition and denying Columbia Transmission's motion for
authorization to pay the taxes. Briefing has been completed and oral argument
was heard on March 2, 1994, before the U.S. Court of Appeals for the Third
Circuit. An order affirming the District Court's order was issued on October
5, 1994. West Virginia Tax and Revenue filed a petition for rehearing in banc
on October 18, 1994. On October 28, 1994 rehearing was denied. The West
Virginia State Department of Taxation filed a Writ of Certiorari with the
United States Supreme Court on January 25, 1995.
3. The Columbia Gas System, Inc. and Columbia Gas Transmission v.
U.S. Trustee, No. 93-7609. On August 30, 1993, the Corporation and Columbia
Transmission filed an Appeal of the District Court's order adopting the
Magistrate's Report and Recommendation and granting the U.S. Trustee's appeal
of the Bankruptcy Court's July 31, 1993 order approving certain investment
guidelines and the Bankruptcy Court's order denying the U.S. Trustee's Motion
for Reconsideration of the Bankruptcy Court's July 31, 1993 order. On August
29, 1994, the U.S. Court of Appeals for the Third Circuit affirmed in part, and
remanded for further proceedings. The Third Circuit's decision limits
investments of cash by the debtors to securities issued or backed by the U.S.
Government in strict compliance with Section 345(b) of the U.S. Bankruptcy
Code.
III. Purchase and Production Matters (Unless otherwise noted, all matters are
stayed pursuant to Section 362 of the Bankruptcy Code)
A. Appalachian Producer Litigation
1. Enterprise Energy Corp. et al. v. Columbia Gas Transmission
Corp., C. A. No. C2-85-1209, (U. S. Dist. Ct., S. D. Ohio, filed July 26,
1985). See II.C.1. below
2. Phillips Production Co. v. Columbia Gas Transmission Corp., C.A.
No. 89-0269, (U.S. Dist. Ct., W.D. Pa. filed February 7, 1989). The complaint
as filed contained six separate counts involving ten gas purchase contracts
with Columbia Transmission. All claims except those relating to Columbia
Transmission's invocation of the cost recovery clause were settled and
dismissed December 18, 1989, pursuant to agreement of the parties. Phillips
cost recovery claim was stayed by Columbia Transmission's bankruptcy filing.
3. Columbia Gas Transmission Corp. v. Alamco, Inc. et al., C.A. No.
88-C-38-2 (Harrison (W.Va) Cir. Ct. filed January 15, 1988). Under a 1983
release agreement, Columbia Transmission filed suit against Alamco, Inc.
(Alamco) contending that Alamco was obligated to sell gas to Columbia
Transmission at prices and under terms and conditions being generally offered
by Columbia Transmission at the time purchases were resumed as opposed to the
conditions of the original contract. Trial of the state court action was
interrupted and stayed by Columbia Transmission's Bankruptcy petition filed
July 31, 1991. A parallel suit was filed by Alamco, naming the Corporation,
Columbia Transmission, Columbia Gas System Service Corporation and Commonwealth
Gas Pipeline Corporation, alleging antitrust violations. In the opinion of
counsel, the antitrust claim was barred by the statute of limitations; however
on March 13, 1991, Columbia Transmission's and Commonwealth Gas Pipeline's
motions to dismiss were denied without prejudice to Columbia Transmission's
right to assert, by summary judgment or otherwise, that Alamco's claims are
time barred, or that Alamco cannot prove the allegations in its complaint.
10
11
ITEM 3. LEGAL PROCEEDINGS (Continued)
In late May 1992, a settlement agreement in principle was reached
which was approved by the Bankruptcy Court on July 28, 1992. As a result,
after the order becomes final, these actions will be dismissed upon the earlier
of confirmation of a Columbia Transmission plan of reorganization or closing of
the Columbia Transmission bankruptcy proceeding.
B. Southwest Producer Litigation (Suits naming Columbia Transmission
are stayed as to Columbia Transmission; indemnification agreements will be
effective if the contract providing indemnification is not rejected)
1. Royalty Owners Litigation: The agreements between Columbia
Transmission and certain southwest producers effective in 1985 which reformed
gas purchase contracts have resulted in a number of lawsuits against the
producers. Under the agreements, Columbia Transmission has a qualified
obligation to indemnify the producers in certain instances against claims by
their royalty owners.
Certain suits were pending against Amoco Production Company (Amoco)
for which it was seeking indemnification from Columbia Transmission as of the
commencement of Columbia Transmission's proceeding in bankruptcy. In November
1993, Columbia Transmission and Amoco entered an agreement, terminating the
contracts and providing that Amoco shall have an allowed unsecured claim for
$4.1 million for all royalty indemnification and excess royalty claims. On
November 7, 1994, the Bankruptcy court approved the Amoco agreement.
2. New Ulm and Fox v. Mobil Oil Corporation, Columbia Gas
Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655
(155th Judicial Dist. Ct. of Austin County, TX). New Ulm alleged Columbia
Transmission incorrectly paid for gas on the basis of Columbia Transmission's
market-out price rather than the higher price New Ulm claimed was available to
it under the contracts.
After the Bankruptcy Court entered an order modifying the automatic
stay provisions of the Bankruptcy Code, jury trial began on June 22, 1992, and
concluded with a verdict against Columbia Transmission on July 2, 1992, in the
amount of approximately $5.6 million, including interest. On July 30, 1992,
the Court denied Columbia Transmission's motion for judgment notwithstanding
the jury's verdict and entered judgment against Columbia Transmission in such
amount for actual damages, prejudgment interest and attorneys' fees. Columbia
Transmission's motion for new trial was denied on October 12, 1992. Columbia
Transmission has perfected an appeal to the First Court of Appeals at Houston,
Texas. Briefing is complete and oral argument was held on December 7, 1993.
On July 28, 1994, the Court of Appeals reversed the lower court's judgment and
remanded the matter to the trial court for proceedings not inconsistent with
the Court of Appeals opinion. Motion for rehearing by Columbia Transmission
and New Ulm motions were denied in October, 1994. On December 5, 1994, both
parties filed applications for writ of error with the Supreme Court of Texas.
3. Wagner & Brown v. Columbia Gas Transmission Corp., C.A. No.
83-15091 (Orleans Parish (La.) Civ. Dist. Ct.). This suit involves Columbia
Transmission's alleged breach of a gas purchase and sales agreement. The
claims of Wagner & Brown have been settled, and the case was dismissed as to
Wagner & Brown on March 6, 1986. The claims of El Paso Exploration Co. (now
Meridian Oil Production, Inc. (Meridian)), which intervened as a plaintiff and
asserted all the claims and allegations made by Wagner & Brown, including
take-or-pay, price differential and specific performance, have not been
settled. In September 1990, Meridian served a Second Amended Petition in which
it alleged damages in excess of $60 million (and an additional $40 million of
interest) as a result of Columbia Transmission's failure to meet its
take-or-pay and minimum take obligations. The issue of price differential has
been settled. A status conference was held May 28, 1991, and a hearing on the
plaintiff's motion for partial summary judgment on Columbia Transmission's
legal defenses was held June 14, 1991.
A motion by Meridian for a Bankruptcy Court order lifting the
automatic stay so as to permit it to prosecute its claims against Columbia
Transmission was denied.
4. Koch Industries Inc. v. Columbia Gas Transmission Corp. C.A. No.
89-2156 (U.S. Dist. Ct., E.D. La., filed May 12, 1989). On January 11, 1991,
Columbia Transmission filed an action, Columbia Gas
11
12
ITEM 3. LEGAL PROCEEDINGS (Continued)
Transmission Corp. v. Koch Industries, Inc., C.A. No. 91-0174, (U.S. Dist. Ct.,
E.D. La). This lawsuit was related to the settlement of an earlier lawsuit
between the parties. Columbia Transmission sought an order declaring that it
is under no obligation to increase its purchase nominations under the contracts
because of Koch Industries, Inc. (Koch) unasserted right to correct imbalances
between it and other working interests owners in the acreage dedicated under
the contract. Koch filed a complaint seeking a contrary determination. Koch
Industries, Inc. v. Columbia Gas Transmission Corp., C.A. No. 91-0177 (U.S.
Dist. Ct. E.D. La). The two cases were consolidated. Judgment in favor of
Koch Industries, Inc. and against Columbia Transmission was issued on April 29,
1991. Columbia Transmission's motion to alter or amend the judgment was denied
on June 5, 1991. On June 19, 1991, Columbia Transmission filed a Notice of
Appeal to the Fifth Circuit. On August 20, 1991, the Clerk of the Court
advised Columbia Transmission that the case was stayed during the Chapter 11
Bankruptcy proceedings.
5. Energy Development Corp. v. Columbia Gas Transmission Corp.,
C.A. No. CV91-0960, (U.S. Dist. Ct., W. D., La., division Lafayette/Opelousas,
filed May 13, 1991). Energy Development Corporation alleges that Columbia
Transmission breached the take-or-pay, minimum daily quantity and inequitable
withdrawal provisions of the gas purchase contract between Energy Development
Corporation and Columbia Transmission.
IV. Regulatory Matters
A. Take-or-Pay and Contract Reformation Costs Billed by Pipeline
Suppliers
1. Columbia Gas Transmission Corp., FERC Dkt. No. RP91-41, reversed
and remanded Baltimore Gas & Electric Co. v. FERC, 26 F.3d 1129 (D.C. Cir
1994). On June 24, 1994, the Court of Appeals reversed the Federal Energy
Regulatory Commission's (FERC) finding that the 1985 PGA Settlement did not bar
Columbia Transmission's recovery of any of the upstream pipeline Order Nos.
500/528 costs. The case was remanded to the FERC for a determination of
whether any of such charges relate to Columbia Transmission's purchasing
decisions prior to April 1, 1987. On September 16, 1994, Columbia Transmission
filed with the FERC a motion for an order governing proceedings on remand.
On October 11, 1994, the Joint Intervenors filed a response to the
September 16, 1994 motion and moved for entry of an order requiring immediate
refund of all the disputed amounts and for summary disposition of the issues
remanded by the Court of Appeals. On October 26, 1994, Columbia Transmission
filed its response to the Joint Intervenors.
On December 1, 1994, the FERC denied the Joint Intervenors' motion
for summary disposition and immediate refunds. The FERC established procedures
for Columbia Transmission to make a prima facie factual submission within 60
days of the order identifying amounts it is entitled to recover.
On December 23, 1994, Columbia Transmission filed a motion requesting
a 45-day extension of the procedural dates for the prima facie submission and
responses. By notice issued January 11, 1995, the FERC extended Columbia
Transmission's submission deadline to March 16, 1995.
On January 26, 1995, FERC denied rehearing of its December 1, 1994,
order.
On February 16, 1995, Columbia Transmission filed a motion for an
additional 60-day extension of the procedural dates.
B. Direct Billing of Past Period Production and Production-Related
Costs
1. Columbia Gas Transmission Corp. v. FERC., C.A. No. 88-1701 (U.S.
Ct. of App., D.C. Circuit). On February 9, 1990, the Court issued its opinion
finding that the FERC's orders authorizing five of Columbia Transmission's
upstream pipeline suppliers to directly bill past period production related
costs (Order Nos. 94 and 473) to customers allocated based upon past period
purchases violates the filed rate doctrine and the rule against
12
13
ITEM 3. LEGAL PROCEEDINGS (Continued)
retroactive ratemaking. Therefore, the Court struck the orders authorizing
direct billing and remanded the issue to the FERC for further proceedings. On
October 9, 1990, the U.S. Supreme Court denied certiorari.
Columbia Transmission agreed to settlements with four of its pipeline
suppliers, which were initially approved by FERC orders issued February 11,
1993. However, by orders issued January 12, 1994, the FERC granted requests
for rehearing by Columbia Transmission's customers and rejected the settlements
because they provided for rate recovery of the settlement payments to its
pipeline suppliers. The FERC held that such rate recovery was barred by
Columbia Transmission's 1985 PGA Settlement. The same orders directed the
pipeline suppliers to refund all principal Order Nos. 94/473 direct billed
amounts collected from Columbia Transmission, but provided that no interest
would be required on such refunds.
Columbia Transmission and its four pipeline suppliers filed requests
for rehearing of such orders. On October 18, 1994, the FERC for the most part
denied rehearing, although it did require interest on refunds from February 11,
1994. Columbia Transmission and its pipeline suppliers filed petitions for
review of the FERC's orders with the United States Court of Appeals for the
District of Columbia Circuit.
Agreements have been reached with Panhandle Eastern Pipe Line Company
(Panhandle), Trunkline Gas Company (Trunkline), Texas Eastern Pipe Line
Corporation and Texas Gas Transmission Corp. to postpone refunds to Columbia
Transmission until after the appeals are resolved. In the interim, refunds
would accrue interest at FERC rates. The pipeline suppliers or Columbia
Transmission may move for accelerated payment of refunds. Columbia
Transmission is not repaying Panhandle the amounts they have already refunded.
In the interim, on October 28, 1993, Transcontinental Gas Pipe Line
Corporation (Transco) and Columbia Transmission filed a letter with the FERC
indicating that the remaining issues had been resolved, and that they agreed on
a refund to Columbia Transmission of $1.4 million. The FERC treated this as a
settlement offer subject to its approval.
By order issued on February 13, 1995, the FERC rejected Transco's
offer of settlement on Order No. 94 costs with Columbia Transmission. Transco
was ordered to refund the Order 94 costs collected from Columbia Transmission,
without interest. This result is the same the FERC reached with respect to
Panhandle and Trunkline. The order has not yet been issued.
On February 7, 1995, Columbia Transmission filed a motion for
clarification with the FERC regarding whether the pipelines must also refund
carrying charges paid by Columbia Transmission.
C. Pipeline Exit Fees
1. Columbia Gas Transmission Corporation, et al., Docket No.
RP94-113. On June 30, 1994, FERC approved an agreement between Columbia
Transmission and Tennessee Gas Pipeline Company (Tennessee) which provided for
a reduction and early termination of contracts in consideration for Columbia
Transmission's payment of an exit fee of approximately $40 million. FERC
rejected objections of several customers and permitted Columbia Transmission
full recovery of the exit fee from its customers. The Bankruptcy Court had
approved this settlement on November 15, 1993.
On September 28, 1994, FERC denied requests for rehearing of its June
30 order. Several parties have filed petitions for review of these orders with
the United States Court of Appeals for the District of Columbia Circuit.
2. Columbia Gas Transmission Corporation, Docket Nos. RP94-315,
316, 317 and 318. In these dockets, Columbia Transmission filed petitions to
approve exit fee settlements terminating contracts with certain pipelines that
are no longer needed by Columbia Transmission and to resolve outstanding
bankruptcy issues by, inter alia, the payment by Columbia Transmission of exit
fees to Wyoming Interstate Company Ltd. (WIC), Trailblazer Pipeline Company
(Trailblazer), Natural Gas Pipeline Co. of America (NGPL) and Transcontinental
Gas Pipe Line
13
14
ITEM 3. LEGAL PROCEEDINGS (Continued)
Corporation (Transco), and to collect such exit fee payments through its
Account No. 858 cost tracker. All four settlements have been approved by the
Bankruptcy Court. On January 27, 1995, the FERC issued an order approving the
exit fee settlement between Columbia Transmission and Transco. On February 10,
1995, the FERC approved the separate exit fee settlements between WIC,
Trailblazer and NGPL to terminate the contracts with those pipelines. Both
orders permit recovery of the exit fees.
3. Columbia Gas Transmission Corporation, Docket No. RP95-98. On
December 30, 1994, Columbia Transmission filed its exit fee settlement with
Ozark Gas Pipeline. Comments were filed on January 30, 1995, opposing the
settlement and reply comments were filed on February 9, 1995. The settlement
is pending before the FERC.
V. Other
A. Canada Southern Petroleum Ltd. v. Columbia Gas Development of
Canada Ltd. et al., (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.
The judge granted the application of Allied Signal, Inc., Home Oil
Company and Kern County Land Company to relieve them of the requirement to
participate in the proceedings. An appeal of the order by Amoco is pending.
In early 1993, Canada Southern filed a motion to amend its statement
of claim to seek an accounting of the amount of operation costs properly
recoverable by the working interest holders including Columbia Canada.
Columbia has not consented to the amendment and contends that any amounts
accrued since the initial statement of claim in 1988 should be barred and more
basically, that litigation is inappropriate prior to an audit.
Examination for discovery is still proceeding in the referenced
actions. None of the defendants has yet conducted any discovery of Canada
Southern Petroleum, Ltd. (Canada Southern) nor of one another. On the present
schedule, it is likely that this discovery process will continue well into
1995. A six month trial is scheduled to commence in September 1996 by the
Court of Queens Bench.
Note: Columbia Canada was sold to Anderson Exploration Ltd.
effective December 31, 1991, and the company name subsequently changed to
Anderson Oil & Gas, Inc. Pursuant to an Indemnification Agreement re
Kotaneelee Litigation, Columbia agreed to indemnify and hold Anderson harmless
from losses due to this litigation. An escrow account in the amount of
approximately $30,000,000 (Cdn) was established as partial security for the
indemnification obligation. Upon emerging from bankruptcy, an additional
deposit to the Escrow Account of $25,000,000 (Cdn) will be required in cash or
by letter of credit.
VI. Environmental
A. Commonwealth of Kentucky Natural Resources and Environmental
Protection Cabinet, Department for Environmental Protection. On January 22,
1992, Columbia Transmission received Notices of Violation (NOV) from the
Commonwealth of Kentucky, Natural Resources and Environmental Protection
Cabinet, Department for Environmental Protection (KYDEP), apparently to
establish the Cabinet's prepetition claims against Columbia Transmission, with
respect to ten compressor station sites in the Commonwealth of Kentucky. These
notices generally cite the release or disposal of waste materials or hazardous
substances, including but not limited to polychlorinated biphenyls (PCBs).
14
15
ITEM 3. LEGAL PROCEEDINGS (Continued)
On October 24, 1994, Columbia Transmission entered into two agreed
orders with KYDEP. Under one order, Columbia Transmission agreed to pay a
civil penalty of $50,000 to resolve all outstanding NOVs issued by KYDEP.
Under a second order, Columbia Transmission agreed to continue the ongoing
remediation program which Columbia Transmission began in Kentucky in the late
1980. Both orders were approved by the Bankruptcy Court on November 16, 1994
and are now effective.
B. In the Matter of Columbia Gas Transmission Corp., [United States
Environmental Protection Agency Region III (EPA Region III)]. On January 20,
1992, Columbia Transmission received a Subpoena under the Toxic Substance
Control Act (TSCA) and Information Requests under both the Comprehensive
Environmental Response Compensation and Liability Act of 1980 (CERCLA) and the
Resource Conservation and Recovery Act (RCRA). The Subpoena and Information
Requests sought information relating to Columbia Transmission's compliance
with TSCA, CERCLA and RCRA at and around the facilities it owns, operates,
leases or otherwise used in its pipeline business.
On September 22, 1994, Columbia Transmission entered into Consent
Orders with the EPA Region III resolving the issues covered by the Subpoena and
Information Requests. Under the Administrative Order by Consent under Section
106 of CERCLA, Columbia Transmission agreed to continue its ongoing remediation
program with the EPA Region III oversight. Under the TSCA Order, Columbia
Transmission agreed to pay a civil penalty of approximately $4.9 million to
resolve EPA Region III allegations of violations regarding the use and disposal
of PCBs. Although Columbia Transmission believes it had meritorious defenses
to EPA Region III's allegations, Columbia Transmission determined that the cost
was reasonable when compared to the litigation costs involved in contesting
EPA's factual claims. Bankruptcy Court approval of the Consent Orders was
obtained on November 16, 1994, and no appeals were filed within the appeal
period. The Order became effective on February 23, 1995.
C. Portsmouth Redevelopment and Housing Authority and Commonwealth
Gas Services, Inc. (Commonwealth) v. BMI Apartment Associates, C.A. No.
2:93CV242, (U.S. Dist. Ct. E.D. Va., filed March 25, 1993.) A gas
manufacturing plant had been operated in Portsmouth, Virginia by Portsmouth Gas
Co. on a site that was subsequently sold by Portsmouth Gas Co. to the
Portsmouth Redevelopment and Housing Authority (PRHA), which removed equipment
and sold the property to developers of apartment complexes and single-family
homes. Portsmouth Gas Co. was later acquired by Commonwealth. On July 22,
1994, a settlement among Commonwealth, the PRHA and the present and former
landowners of the site resolving all previously filed litigation was approved
by the District Court. The settlement allows Commonwealth and PRHA to perform
remedial work at the site. Commonwealth and PRHA have an agreement whereby
costs are shared. In addition, Commonwealth has met with the owners of an
adjacent property, Gates Apartments, to obtain access to that property for
environmental assessment and remediation purposes. Commonwealth is working
with the Virginia Department of Environmental Quality (VADEQ) to develop
remedial plans for the site.
D. Commonwealth Gas Services/Virginia Department of Environmental
Quality (Petersburg, VA. Service Center). On February 9, 1993, Commonwealth
reported to the VADEQ State Water Control Board that an oily substance was
seeping through a retaining wall at a former manufactured gas plant site at
Petersburg, Virginia. A site assessment submitted to the VADEQ on July 20,
1993 recommended the removal of contents of a tank behind the retaining wall
and disclosed an additional seep of materials from another source into the
creek. In July 1993, VADEQ accepted Commonwealth's recommendations and the
tank was subsequently emptied and secured. A supplemental report identifying
the source of the additional seep was sent to VADEQ in November which noted
fairly widespread groundwater and soil contamination. Commonwealth's
consultants are developing a work plan to address the contamination noted in
the supplemental report and are in the process of negotiating a Memorandum of
Agreement delineating the voluntary remediation of the site to be undertaken.
Once that agreement is completed and approved by the VADEQ remediation can
begin.
E. In re Columbia Gas Transmission [United States Environmental
Protection Agency Region V] (EPA Region V). On January 28, 1994, Columbia
Transmission received from the EPA Region V an Information Request pursuant to
the RCRA. It has requested that Columbia Transmission submit information and
knowledge
15
16
ITEM 3. LEGAL PROCEEDINGS (Continued)
relating to its generation and management of natural gas pipeline condensate,
used engine oil and similar liquids in the state of Ohio since the early
1980's. Columbia Transmission submitted a written response to the request to
the EPA Region V on May 24, 1994.
F. Columbia Gas Transmission Corp. v. Aetna Casualty & Surety Co.,
et al., C.A. No. 94-C-454 (Kanawha (W.Va) Cir. Ct. filed March 14, 1994).
Columbia Transmission filed a complaint in West Virginia State Court seeking
coverage from various insurers and under various insurance policies for
environmental cleanup costs. All insurers have either executed a standstill
agreement or responded to the complaint. Columbia Transmission is preparing
responses to discovery requests to be submitted to insurers in February 1995.
G. Columbia Gulf Transmission Company v. Aetna Casualty & Surety
Co., et al., C.A. No. 95-C-177 (Kanawha (W.Va) Cir. Ct. filed January 19,
1995). On January 19, 1995, Columbia Gulf Transmission filed a complaint in
West Virginia State Court seeking coverage from various insurers and under
various insurance policies for environmental remediation costs and related
costs.
H. In re Marcor Environmental, Inc. v. Columbia Gas Transmission
Corporation. On September 30, 1994, EPA Region III issued a complaint and
notice of opportunity for hearing against Marcor Environmental, Inc. (Marcor)
and Columbia Transmission for alleged violations of the Clean Air Act
Amendments of 1990 arising from Macor's removal of asbestos at Lanham
Compressor Station at Lanham, West Virginia in 1993. The complaint which seeks
a penalty of $162,500 alleges failure by Marcor and Columbia Transmission, as
owner of the facility, to adequately wet the asbestos material and to ensure it
remained wet pending disposal. On November 4, 1994, Columbia Transmission
filed an answer and a motion to dismiss. A settlement conference among EPA
Region III, Marcor and Columbia Transmission was held on January 12, 1995.
16
17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of the Corporation 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 February 28, 1995,
was approximately 60,000 and the stock closed at $26. On June 19, 1991, the
Corporation suspended the dividend on its common stock. Management cannot
determine at this time when dividends will again be paid.
See Item 7 on page 27 for additional information regarding the Corporation's
common stock prices and dividends.
17
18
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
($ in millions except per share amounts) 1994* 1993* 1992* 1991* 1990
- -------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA ($)
Total operating revenues 2,833.4 3,391.2 2,922.0 2,576.8 2,357.9
Products purchased 976.7 1,574.5 1,236.9 1,056.5 846.8
Earnings (Loss) on common stock
before extraordinary item and
accounting changes 246.2 152.2 90.9 (794.8) 104.7
Earnings (Loss) on common stock 240.6 152.2 51.2 (694.4) 104.7
- -------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Earnings (Loss) per common share ($):
Before extraordinary item and
accounting changes 4.87 3.01 1.79 (15.72) 2.21
Earnings (Loss) on common stock 4.76 3.01 1.01 (13.74) 2.21
Dividends:
Per share ($) - - - 1.16 2.20
Payout ratio (%) N/M N/M N/M N/M 99.5
Average common shares outstanding (000) 50,560 50,559 50,559 50,537 47,316
- -------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization excluding liabilities
subject to Chapter 11:
Common stock equity 1,468.0 1,227.3 1,075.1 1,006.9 1,757.8
Long-term debt 4.3 4.8 5.4 6.1 1,428.7
Short-term debt and current maturities** 1.2 1.3 1.4 138.9 770.7
Total 1,473.5 1,233.4 1,081.9 1,151.9 3,957.2
Total assets 7,164.9 6,957.9 6,505.9 6,332.2 6,196.3
- -------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including short-term
debt and current maturities**):
Common stock equity 99.6 99.5 99.4 87.4 44.4
Debt 0.4 0.5 0.6 12.6 55.6
Capital expenditures ($) 447.2 361.3 299.7 381.9 629.6
Net cash from operations ($) 572.8 850.4 765.4 531.6 420.1
Book value per common share ($) 29.03 24.27 21.26 19.92 34.83
Return on average common equity
before extraordinary item
and accounting changes (%) 18.3 13.2 8.7 N/M 6.2
- -------------------------------------------------------------------------------------------------------------------
N/M - Not meaningful
* Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements. Due to the bankruptcy filings, estimated pre-tax interest
expense of approximately $222 million, $207 million, $203 million and $84
million has not been recorded for 1994, 1993, 1992 and 1991, respectively.
** Prior to its Chapter 11 filing, the Corporation 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.
18
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Index Page
- --------------------------------------------------------------------------
Bankruptcy Matters . . . . . . . . . . .. . . . . . . . . . . 19
Consolidated Review . . . . . . . . . . .. . . . . . . . . . . 25
Liquidity and Capital Resources . . . . .. . . . . . . . . . . 27
Transmission Operations . . . . . . . . .. . . . . . . . . . . 30
Distribution Operations . . . . . . . . .. . . . . . . . . . . 37
Oil and Gas Operations . . . . . . . . .. . . . . . . . . . . 44
Other Energy Operations . . . . . . . . .. . . . . . . . . . . 47
- --------------------------------------------------------------------------
BANKRUPTCY MATTERS
On July 31, 1991, The Columbia Gas System, Inc. (Corporation) and its
wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia
Transmission), filed separate petitions seeking protection under Chapter 11 of
the Federal Bankruptcy Code. Both the Corporation and Columbia Transmission
were granted debtor-in-possession status under the Bankruptcy Code, allowing
them to continue normal business operations subject to the jurisdiction of the
United States Bankruptcy Court for the District of Delaware (Bankruptcy Court).
Events Leading to Bankruptcy Filings
Columbia Transmission's Chapter 11 filing was precipitated by a combination of
events that adversely affected its physical operations and financial viability.
Most notable were federal legislative and regulatory actions, instituted years
after Columbia Transmission's gas purchase contracts were signed, that
significantly impacted Columbia Transmission's ability to sell the gas it had
contracted to buy and to recover its costs from its customers. These problems
were exacerbated by record-setting warm weather in 1990 and 1991, which caused
spot market prices for gas to plunge and created excess transportation
capacity, thus making an unexpected and persistent oversupply of bargain-priced
gas available to Columbia Transmission's customers. As a result, Columbia
Transmission's ability to market its gas was severely undercut, substantially
reducing both sales volumes and revenues.
As of July 31, 1991, the Corporation was in default on $83.5 million of
short-term obligations and negotiations with banks and producers had met with
only limited success. Therefore, on July 31, 1991, the Corporation and
Columbia Transmission filed for protection under Chapter 11 of the Federal
Bankruptcy Code in the Bankruptcy Court. A discussion of the proceedings under
Chapter 11 protection as well as additional information on bankruptcy issues
discussed in this section and related matters is included in Note 2 of Notes to
Consolidated Financial Statements.
In contrast to the situation of many other Chapter 11 debtors, reorganization
of Columbia Transmission has not been hampered by unprofitable or marginal
business operations. Rather, the achievement of the Chapter 11 objective of
reorganization has been impacted by the enormity and complexity of the disputed
and contingent claims filed against it by unaffiliated creditors and by
attempts on behalf of those creditors to obtain recoveries on such claims from
the assets of the Corporation's estate. In addition, Columbia Transmission's
status as a regulated gas transmission company under the Natural Gas Act (NGA)
and its resulting obligations has brought into the bankruptcy forum creditors'
rights issues which are complicated by public law issues arising under the NGA.
Bankruptcy Issues
Intercompany Complaint
On March 19, 1992, the Official Committee of Unsecured Creditors of Columbia
Transmission (Columbia Transmission Creditors' Committee) filed a complaint
(Intercompany Complaint) with the Bankruptcy Court alleging that the $1.7
billion of Columbia Transmission's secured and unsecured debt securities held
by the Corporation
19
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
should be recharacterized as capital contributions (rather than loans) and
equitably subordinated to the claims of Columbia Transmission's other
creditors. The Intercompany Complaint also challenges interest and dividend
payments made by Columbia Transmission to the Corporation of approximately $500
million for the period from 1988 to the petition date and the 1990 property
transfer from Columbia Transmission to Columbia Natural Resources, Inc. (CNR)
as an alleged fraudulent transfer. Based on the SEC standardized measurement
procedures, CNR's properties had a reserve value of approximately $250 million
as of December 31, 1994, a significant portion of which is attributable to the
transfer from Columbia Transmission. At the Bankruptcy Court's request, the
trial proceedings for the Intercompany Complaint were transferred to the U. S.
District Court for the District of Delaware (the District Court) and were
concluded on October 25, 1994. Post trial submissions were completed in
December 1994, and the District Court is expected to render a decision in the
first quarter of 1995. Management believes that the Intercompany Complaint is
without merit; however, the ultimate outcome of these issues is uncertain at
this stage of the proceedings.
Little progress has been made with Columbia Transmission's creditors in an
attempt to establish the value of the estate and to resolve the matters raised
in the Intercompany Complaint. Since the validity of the Corporation's debt
investment in Columbia Transmission is crucial to the determination of the
value of the Corporation's estate, the Corporation's reorganization will be
affected by the ultimate outcome of the Intercompany Complaint.
Prepetition Obligations of Debtor Companies
The accompanying consolidated balance sheet as of December 31, 1994, includes
approximately $4 billion of liabilities subject to the Chapter 11 proceedings
of the Corporation and Columbia Transmission as follows:
($ in millions)
- ---------------------------------------------------------------------
Corporation
Total payable (primarily debt obligations) 2,382.5
Less: payable to affiliates 5.2
--------
Payable to nonaffiliates 2,377.3
--------
Columbia Transmission
Total payable 3,862.3
Less: payable to affiliates 2,250.7
--------
Payable to nonaffiliates 1,611.6
- ---------------------------------------------------------------------
Liabilities Subject to Chapter 11 Proceedings 3,988.9
- ---------------------------------------------------------------------
Columbia Transmission's prepetition obligations include secured and unsecured
debt payable to the Corporation, secured debt interest, estimated supplier
obligations, estimated rate refunds, accrued taxes and other trade payables and
liabilities. Prepetition obligations of the Corporation primarily represent
debentures, bank loans and commercial paper outstanding on the filing date
together with accrued interest to that date. A substantial amount of Columbia
Transmission's liabilities subject to Chapter 11 proceedings relate to amounts
owed to the Corporation. Columbia Transmission's borrowings have been funded
by the Corporation on a secured basis since June 1985 and are secured by
mortgages and a cash collateral order approved by the Bankruptcy Court. On the
petition date, the principal amount of the secured debt outstanding was
$1,340.4 million. Prepetition and postpetition interest on secured debt owed
by Columbia Transmission to the Corporation was $488.3 million at December 31,
1994. In addition to these secured claims, the Corporation has an unsecured
claim against Columbia Transmission of $351 million in installment notes issued
prior to 1985 and accrued interest to the petition date.
Producer Claims Estimation Process
As a result of Columbia Transmission's bankruptcy petition filing in July 1991
and its rejection of more than 4,800 above-market gas purchase contracts with
producers, Columbia Transmission had recorded liabilities of approximately one
billion dollars for estimated contract rejection costs. In addition,
approximately $200 million of take-or-pay and other miscellaneous producer
claims had also been recorded.
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21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
In 1992, the Bankruptcy Court approved the appointment of a claims mediator to
implement a claims estimation procedure related to the rejected above-market
producer contracts and other producer claims. On October 13, 1994, the claims
mediator issued his Initial Report and Recommendation of the Claims Mediator on
Generic Issues for Natural Gas Contract Claims (Report). The Report, which is
subject to Bankruptcy Court review and approval, establishes the parameters
within which producers must initially recalculate their contract rejection and
take-or- pay claims. The recalculated claims will then be subject to challenge
and audit and adjustment based upon claim specific issues. The Report
generally validates the assumptions Columbia Transmission used earlier to
estimate the total value of contract rejection claims filed by producers in the
bankruptcy proceedings and clearly rules out most of the methods the producers
utilized to derive grossly excessive and legally improper amounts in their
original claims which amounted to $13 billion. The claims mediator has
indicated that unaudited claims recalculations should be filed by April 21,
1995.
While the Report uses a lower discount rate than that used by Columbia
Transmission and recognizes certain proved undeveloped reserves, it directs
that calculations of damages be based only on the amount by which a contract
price exceeds a mitigation price and be discounted to a present value as of the
petition date. Not addressed in the report are numerous contract specific
issues that ultimately will be used in the estimation procedure to determine
the allowable level of producer claims. Columbia Transmission is not able to
calculate individual contract rejection claims at this time because it does not
have adequate data from the producers on the proved undeveloped reserves or on
planned gas development projects. This data will only become available, and
subject to challenge and audit, when the individual producers file their
recalculations.
The Report does not address an alternative method for calculating contract
rejection damages sponsored by Columbia Transmission. This methodology
contemplates using the market value of the producers' reserves subject to the
contracts rejected by Columbia Transmission as evidence of the economic value
to producers of such contracts (Market Value Methodology). The claims mediator
is expected to hold a hearing on this alternative methodology in the second
quarter of 1995 and has indicated that Columbia Transmission's pursuit of its
Market Value Methodology will not delay his completion of the discounted cash
flow methodology contained in the Report.
In management's opinion, the $1.3 billion estimate previously reported
represents the worst plausible case for allowed contract rejection claims,
although it is anticipated that the producers' initial recalculations of these
claims may exceed that total. Further, Columbia Transmission does not believe
the Report produces any basis which would cause it to change the amount it
previously recorded for contract rejection (approximately one billion dollars)
given the information currently available to it. However, following the review
of the Report by Columbia Transmission and its counsel, Columbia Transmission
increased the $200 million reserve for take-or-pay and other miscellaneous
producer claims by approximately $55 million in the third quarter of 1994.
The resolution of bankruptcy related issues could significantly influence
future reported financial results. Accounting standards require that as claim
amounts are allowed by the Bankruptcy Court, the full amount of the allowed
claim must be recorded. This could result in liabilities being recorded which
bear little relationship to the amounts ultimately required to be paid in
settlement of those claims and could conceivably exceed the Corporation's total
investment in Columbia Transmission. Any such distortion would not be
corrected until final plans of reorganization are approved for the Corporation
and Columbia Transmission.
Proposed Plans of Reorganization
The Corporation's and Columbia Transmission's discussions with the Columbia
Transmission Creditors' Committee to negotiate a reorganization plan for
Columbia Transmission and expedite emergence from Chapter 11 proceedings had
been largely unsuccessful. Therefore, on January 18, 1994, Columbia
Transmission, with the Corporation as cosponsor, filed a reorganization plan
(plan) and a disclosure statement, for consideration by its creditors and other
interested parties. The plan provides that Columbia Transmission would remain
a wholly-owned subsidiary of the Corporation, will continue to offer an array
of competitive transportation and storage services, and will retain ownership
of its 19,000-mile pipeline network and related facilities. Subsequent to the
filing of the plan, Columbia Transmission had discussions directly with gas
producers who have substantial claims against it. Despite months
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22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
of negotiations and numerous offers of settlement, Columbia Transmission has
been unable to reach agreement on a consensual reorganization plan with the
Columbia Transmission Creditors' Committee. However, Columbia Transmission has
had recent discussions, on an individual basis, with a significant number of
its largest producer claimants, but it is impossible to determine at this time
if these discussions will lead to agreements on the claims.
The Corporation's and Columbia Transmission's exclusive rights to file plans of
reorganization expire April 18, 1995. Prior to that date, the Corporation
intends to file its reorganization plan with the Bankruptcy Court and to
cosponsor amendments to the reorganization plan that Columbia Transmission
filed in January 1994.
Both plans will be subject to review and approval requirements (including
authorizations from the SEC) which may require several months to complete.
Implementation of reorganization plans for Columbia Transmission and the
Corporation, and the levels and timing of distributions to their creditors, are
subject to a number of risk factors which could materially impact their
outcome. Both companies anticipate emerging from bankruptcy at the same time.
The provisions of the reorganization plans of either Columbia Transmission or
the Corporation that are ultimately implemented could be materially different
from the filed plans.
Customer Refunds
Total customer claims in Columbia Transmission's bankruptcy proceedings
relating to, or arising from, contracts with its customers for sales,
transportation, gas storage and similar services and other miscellaneous claims
represent about 450 claims for a total filed amount of approximately $550
million, plus a potentially substantial sum filed as undetermined. While a
significant portion of these claims has been resolved, as a result of a Third
Circuit Court decision directing the pass-through of certain refunds, claims
filed as "undetermined" still remain to be resolved.
The refund issues underlying customer claims include Federal Energy Regulatory
Commission (FERC) Orders Nos. 500 and 528 (Order 500/528) direct charges that
were billed to Columbia Transmission by upstream pipeline companies,
prepetition revenues collected subject to refund in general rate filings,
purchased gas adjustment filings, and other upstream pipeline flowthrough
filings. Appropriate reserves for rate refund liabilities have been recorded
for these matters to reflect management's judgment of the ultimate outcome of
the proceedings. (See Note 2H in Notes to Consolidated Financial Statements
for additional information.)
Customer Recoupment Motion
Various customers of Columbia Transmission filed motions with the Bankruptcy
Court during 1993, seeking authority to exercise alleged recoupment and setoff
rights, whereby they would be permitted to reduce amounts owed to Columbia
Transmission for current services against refunds owed to the customers by
Columbia Transmission. These would include amounts which were not otherwise
payable in full under a July 1993 Third Circuit Court decision, all customer
refunds under a 1990 rate case settlement, and miscellaneous refunds not
otherwise payable in full.
The Bankruptcy Court approved an interim settlement in 1993 under which
customers continued to pay Columbia Transmission for services authorized by the
FERC at approved rates, and Columbia Transmission has agreed to grant these
customers a priority claim to the extent the Bankruptcy Court finds them
entitled to recoupment rights. In January 1994, the Bankruptcy Court issued a
procedural order whereby other customers were permitted to file recoupment and
setoff motions by February 18, 1994. Customers, Columbia Transmission and
other interested parties have filed summary judgment motions and responses on
these issues.
Discussions continued in 1994 with Columbia Transmission's former wholesale
customers and others to resolve a number of FERC proceedings and bankruptcy
claims, including the customer recoupment motion, which remains pending before
the Bankruptcy Court.
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23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Upstream Pipeline Contracts
Columbia Transmission has transportation contracts with certain pipeline
companies that historically have been used to deliver gas to Columbia
Transmission. Some of these pipelines filed claims in the bankruptcy
proceedings which have subsequently been settled. The settlements provide for
the assumption of certain contracts, the termination of certain other contracts
that are no longer necessary for Columbia Transmission's operations, or the
substantial reduction of the transportation contracts. As a result,
approximately $463 million of claims filed by the pipelines against Columbia
Transmission will be withdrawn when all settlements receive Bankruptcy Court
and regulatory approvals. Columbia Transmission retains the option of
rejecting such contracts through the bankruptcy process in the event that
settlements do not receive the Bankruptcy Court and FERC approvals. (See Note
2B in Notes to Consolidated Financial Statements for additional information.)
Other Related Issues
Interest Expense
Interest expense of the Corporation is not being accrued during bankruptcy, but
a calculation of interest is included in a footnote on the statements of
consolidated income and consolidated balance sheets. Such interest has been
calculated based on an interpretation of the contractual arrangements which
govern the various debt instruments the Corporation has outstanding exclusive
of any redemption premiums. In 1993, the Official Committee of Unsecured
Creditors of the Corporation (Committee) asserted claims for interest which
exceed disclosed amounts by approximately $40 million. There are several
factors to be considered in making these calculations that are subject to
uncertainty as to their ultimate outcome in the bankruptcy proceeding,
including the interest rates and method of calculation to be applied to overdue
payments of principal and interest. In addition, the Committee has asserted
that approximately $110 million of redemption premiums should be paid on high
cost debt instruments to compensate investors for anticipated lower interest
rates when the debt is refinanced. These amounts reflect, in part, interest
rate markets in late 1993. Resolution of these issues will be dependent upon,
among other items, interest rates and market conditions at the time of
emergence from bankruptcy.
Security Holder Litigation
After the announcement on June 19, 1991, regarding the Corporation's probable
charge to second quarter earnings and the suspension of its dividend, 17
complaints including purported class actions were filed against the Corporation
and its directors and certain officers of the debtor companies in the District
Court. The actions, which generally allege violations of certain anti-fraud
provisions of the Securities Act of 1933 and the Securities Exchange Act of
1934, have been consolidated. On October 31, 1994, the class action plaintiffs
filed an amended and consolidated complaint against the non-debtor defendants
in the District Court essentially alleging the same causes of action as the
previously filed complaints. In addition, these plaintiffs filed a motion for
class certification in both the Bankruptcy Court and the District Court. The
plaintiffs also filed a motion seeking to withdraw the litigation against the
Corporation from the Bankruptcy Court to the District Court. On November 1,
1994, the Corporation filed a motion with the Bankruptcy Court that seeks to
require the individual class action plaintiffs to file supplementary
information with respect to their previously-filed proofs of claims. Any
person not responding would be barred from asserting their claims pursuant to
such procedures. In an order dated November 30, 1994, the District Court
stayed both the District Court and Bankruptcy Court litigation until a final
judgment is entered in the Intercompany Complaint litigation.
On February 13, 1995, the Corporation, in order to promptly address the
securities claims in its plan of reorganization, requested the District Court
to modify the stay order by considering the Corporation's motion to supplement
class proofs of claims. The plaintiffs have objected to this modification.
Also in 1991, three derivative actions were filed in the Court of Chancery in
and for New Castle County (Delaware) alleging that directors breached their
fiduciary duties. These suits have been stayed by either the bankruptcy filing
or by stipulation of the parties.
While the Corporation and its officers and directors believe that they have
meritorious defenses to these actions, the outcome is uncertain at this time.
23
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Internal Revenue Service Matters
During 1994, a settlement was negotiated with Internal Revenue Service (IRS)
representatives on all of the issues included in the duplicate claims of $553.7
million which the IRS had filed against both debtor companies and the
consolidated Columbia Gas System for tax deficiencies, interest and penalties
for the years 1983-1990. The settlement was approved by the Joint Committee on
Taxation of the U. S. Congress on June 30, 1994, and the Bankruptcy Court on
October 12, 1994. The settlement reduced the original claim to approximately
$112 million. The final cost of the settlement is expected to be about $46
million after taking into consideration certain tax deductions that become
available in subsequent years. The after-tax impact of the settlement had been
previously recorded.
The IRS is currently conducting an audit of the 1991-1992 tax years. As part
of this audit the Corporation has received a proposed notice of disallowance
for its tax deduction of interest expense during this period. The issue
concerns only the timing of the interest deduction and not the deductibility of
interest expense. Over the next several months the Corporation will present
evidence to IRS representatives supporting this deduction. If necessary, the
Corporation will pursue this issue through the IRS appeals process or the
Bankruptcy Court. If the Corporation cannot sustain the deduction in the years
taken, interest expense on the tax deficiency could be due to the IRS, with an
after-tax impact of approximately $10 million at December 31, 1994.
Leveraged Employee Stock Ownership Plan (LESOP)
On March 2, 1993, the Trustee for the Indenture, under which debentures were
issued by the Employees Thrift Plan of Columbia Gas System (Thrift Plan), filed
a complaint against the Corporation in the Bankruptcy Court. The Trustee
alleges that matching payments made by the Corporation to the Thrift Plan
should have been allocated to pay debt service on the outstanding debentures
instead of credited to the employees' accounts.
On March 24, 1994, the Bankruptcy Court denied the Corporation's motion for
summary judgment and on April 22, 1994, the Corporation filed a motion for
leave to appeal the ruling of the Bankruptcy Court which was granted May 18,
1994. Oral argument in the Corporation's appeal was held before the U.S.
District Court for the District of Delaware on October 27, 1994, but the court
has not yet issued its decision. If the Corporation's appeal is denied, the
matter will proceed to trial. The Corporation believes that it has meritorious
defenses to the Indenture Trustee's claims and that the nonpayment of LESOP
debt will not affect the participants' benefits under the plan.
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25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
CONSOLIDATED REVIEW
Net Income
The Corporation's net income for 1994 was $240.6 million, or $4.76 per share,
an increase of $88.4 million, or $1.75 per share over the previous year. After
adjusting both periods for the effect of bankruptcy and unusual items, 1994's
net income was approximately $157.9 million, essentially unchanged from
adjusted 1993 net income of $160.4 million. The impact of lower oil and gas
prices, warmer weather and higher operating costs for the distribution segment
were offset by interest earned on cash accumulated during bankruptcy and
improved results for the transmission segment due in part to the full year
effect of FERC Order No. 636 (Order 636).
Unusual and Bankruptcy Related Items
After-Tax Effect on Net Income
($ in millions) 1994 1993
- ---------------------------------------------------------------------------------------------------
Bankruptcy Related Items
- Estimated interest costs not recorded for prepetition debt 144.2 134.5
- Professional fees and related expenses (30.1) (25.6)
- Producer claim adjustment (35.4) -
Unusual Items
- Reserve for customer settlements (22.8) -
- IRS settlement adjustments 10.3 (44.3)
- Environmental activity 0.7 (45.0)
- Writedown of investment in Columbia LNG - (37.9)
- Other unusual items 15.8 10.1
----- -----
Total 82.7 (8.2)
===== =====
Revenues
For 1994 operating revenues decreased $557.8 million, to $2,833.4 million
primarily reflecting the elimination of Columbia Transmission's merchant
function in November 1993. Under Order 636, wholesale customers are now
purchasing their gas requirements from third parties and using Columbia
Transmission's transportation services for delivery. Also reducing revenues
were pipeline exit fees of $130 million recorded last year that were offset in
products purchased expense and had no effect on income. Lower revenues in
1994, compared to last year, were also attributable to Columbia Transmission
establishing a $35 million reserve in the current year for customer
settlements, warmer weather for the distribution segment and the effect of
lower prices and reduced gas production.
Operating revenues for 1993 increased more than 16 percent from 1992 to
$3,391.2 million due largely to the effect of Columbia Transmission's new rate
design, pipeline exit fees of $130 million for Columbia Transmission, higher
retail sales resulting from colder weather and higher distribution rates.
Revenues from the pipeline exit fees were offset in products purchased expense
and had no effect on income.
Expenses
Operating expenses of $2,460.2 million for 1994, decreased $557.6 million from
1993. The largest portion of this decrease was attributable to a $597.8
million reduction for products purchased reflecting the elimination of Columbia
Transmission's merchant function and 1993 expense associated with pipeline exit
fees, mentioned above. The current period total expense was also lower by
comparison due to the effect of certain 1993 items; namely a $57.5 million
writedown for the Corporation's investment in Columbia LNG and environmental
accruals of $66.8 million. The favorable effect of these items was offset by
generally increasing operating costs, depreciation and depletion expense and
other taxes.
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26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
In 1993, higher sales necessitated an increase in volumes of gas purchased
resulting in an increase in products purchased expense of $337.6 million over
1992. Also contributing to the increase were higher average rates for gas
purchased and pipeline exit fees. Higher operation and maintenance expense in
1993 of $26.5 million reflected higher labor and benefits costs, including
$14.8 million for severance costs associated with reengineering, and a $66.8
million addition to the environmental reserve as well as rising operating
costs. The 1992 recording of a writedown of $126.4 million in the carrying
value of oil and gas properties due to depressed energy prices was the
principal reason for the $128.3 million decrease in depreciation and depletion
expense in 1993.
Other Income (Deductions)
Other Income (Deductions) in 1994 resulted in income of $19 million compared to
a loss of $85.3 million in the prior year. This improvement primarily
reflected the effect of $74.5 million of interest expense recorded in 1993 for
the IRS settlement and a subsequent $15.8 million reduction in this reserve in
1994. The current period also includes prepetition interest expense of $14.9
million for estimated producer claims against Columbia Transmission based on an
initial interpretation of the claims mediator's report (see Note 2 in Notes to
Consolidated Financial Statements for additional information). Interest income
and other, net was $38.8 million higher in 1994 due primarily to a $21 million
reserve adjustment for carrying charges related to prior period exchange
activity as well as establishing a reserve in 1993 for pipeline partnerships.
Income benefited from not accruing interest expense for prepetition obligations
in 1994 and 1993 by approximately $222 million and $207 million, respectively.
(Since the July 31, 1991 bankruptcy filing, the estimated effect of not
accruing interest expense on these prepetition obligations totals approximately
$716 million. However, the actual interest that will ultimately be paid
pursuant to the final plans of reorganization could differ significantly and
cannot be determined at this time). Reorganization items, net reflects
bankruptcy issues that decreased income in 1994 by $12.3 million and improved
income $8.9 million in 1993. In 1994, a $40 million reserve for producer
claims was recorded, and professional fees and related expenses increased $4.7
million from last year to $35.4 million. These higher expenses were partially
offset by a $23.5 million increase in interest earned on accumulated cash.
Other Income (Deductions) reduced income in 1993 by $85.3 million versus $1.5
million in 1992. Interest expense increased $87.8 million in 1993 due largely
to recording interest on prior years' taxes of $74.5 million primarily as a
result of the IRS settlement. The decrease of $13.2 million in Interest income
and other, net reflected $19.5 million for a FERC order eliminating interest
payments from certain upstream pipeline suppliers and a reserve for pipeline
partnership investments partially offset by increased interest income on prior
years' taxes and other issues. The change between 1993 and 1992 for
Reorganization items, net increased income $17.2 million. Professional fees
and related expenses, combined with other miscellaneous reorganization items
decreased $4.2 million while interest earned on accumulated cash increased
income $13 million.
Income Taxes
Increased income led to higher income tax expense of $146 million for 1994, an
increase of $10.1 million over 1993. For the period between 1993 and 1992,
income tax expense increased to $135.9 million, up $65.4 million. This
increase was due to higher income, adjustments for the IRS settlement and an
increased tax rate. See Note 6 in Notes to Consolidated Financial Statements
for additional information.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF COMMON STOCK PRICES AND DIVIDENDS
Market Price
------------------------------- Quarterly
Quarter Ended High Low Close Dividends Paid
- ----------------------------------------------------------------------------
$ $ $ CENT
1994
December 31 29 22 1/4 23 1/2 -
September 30 28 7/8 26 26 7/8 -
June 30 30 3/4 24 7/8 27 -
March 31 29 7/8 21 1/2 26 1/8 -
- ----------------------------------------------------------------------------
1993
December 31 27 3/8 22 1/4 22 3/8 -
September 30 27 1/2 20 26 1/8 -
June 30 25 3/4 20 24 3/4 -
March 31 24 1/4 18 1/8 22 1/4 -
- ----------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
Cash from Operations
Net cash from operations of $572.8 million for 1994, was a decrease of $277.6
million, largely due to Order 500/528 refunds made by Columbia Transmission in
early 1994, exit fee payments made in the current period, together with the
effect of lower oil and gas prices and gas production as well as warmer weather
in the fourth quarter. In addition, in the prior period cash from operations
was higher due to refunds received from certain pipelines and the sale of
Columbia Transmission's gas in underground storage, resulting from the
elimination of its merchant function.
In 1993, cash from operations of $850.4 million was up $85 million over the
year earlier. This improvement primarily was due to the full year effect of
Columbia Transmission's new rate design, refunds received in 1993 from certain
suppliers and higher rates for Distribution and colder weather than 1992.
Higher oil and gas production and gas prices also contributed to the
improvement.
Financing Activities
The Corporation maintained a debtor-in-possession facility (DIP Facility)
through September 1994 for up to $100 million, including the availability of
letters of credit of up to $50 million. On September 15, 1994, the Corporation
amended the DIP facility to discontinue the borrowing option and allow solely
for the issuance of letters of credit of up to $25 million. As of January 31,
1995, $13.7 million of letters of credit were outstanding under the DIP
Facility. The Corporation's liquidity needs are being satisfied by internally
generated funds. As of January 31, 1995, the Corporation and its subsidiaries,
excluding Columbia Transmission, had $263.8 million invested in money market
instruments.
The liquidity needs of Columbia Transmission are being satisfied by internally
generated funds. As of January 31, 1995, Columbia Transmission had $1,279
million invested in money market instruments. Columbia Transmission also
maintains a DIP Facility solely for the issuance of letters of credit of up to
$25 million. As of January 31, 1995, the balance of outstanding letters of
credit under Columbia Transmission's DIP Facility was $1.8 million.
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28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Derivatives Used For Canadian Escrow Investment
The sale of Columbia Gas Development of Canada Ltd. (Columbia Canada), a
wholly-owned Canadian oil and gas exploration and production subsidiary, to
Anderson Exploration Ltd. was effective as of December 31, 1991. The sales
price for Columbia Canada was $94.8 million. Of this amount, $27.7 million
was placed in escrow as security for certain post-closing obligations of the
Corporation including indemnification for potential losses arising from
litigation involving Columbia Canada. The Corporation expects to receive all
or substantially all of the escrow account when the litigation is concluded.
The Corporation uses financial instruments to protect its exposure to
fluctuations in the exchange rates for the Canadian escrow investment. The
funds are invested in short-term Canadian government securities. To insure
that the Corporation's U.S. dollar proceeds are not affected by changes in the
exchange rate between the Canadian dollar-denominated securities and the U.S.
dollar, hedging is undertaken at a very nominal cost. The hedging is
accomplished by the Corporation selling forward the amount of Canadian dollars
expected to be received at the next maturity date of an individual investment.
Upon such maturity date, that Canadian dollar "short" position is offset with a
like purchase (or "long" position) of Canadian dollars and a new short position
for the next investment is created simultaneously. Since the value of the
Canadian dollar has fallen vis-a-vis the U.S. dollar, this hedge prevents any
loss in the value of the investment.
Capital Expenditures
(in millions) 1995 1994 1993
- ----------------------------------------------------------------------------
Columbia Transmission $169 $136 $118
Other Transmission 22 43 19
Distribution 158 151 118
Oil and Gas 118 102 95
Other Energy 24 15 11
- ----------------------------------------------------------------------------
Total $491 $447 $361
- ----------------------------------------------------------------------------
Capital expenditures for 1994 were $447 million, an increase of $86 million
over 1993. The largest portion of the investments in the transmission
subsidiaries (Transmission) were made to assure the safety and reliability of
the pipelines and for compliance with the Clean Air Act Amendments of 1990. In
addition to expenditures required to ensure safe and reliable service and
improved service where warranted, the distribution subsidiaries' (Distribution)
program includes investments to provide deliveries to gas powered electric
generating plants and third-party public refueling stations for natural gas
vehicles. The capital expenditures for the oil and gas segment increased $7
million from the 1993 level to reflect additional expenditures for the
southwest exploration program.
In 1995 capital expenditures will increase $44 million to $491 million. The
largest portion will continue to be for the ongoing replacement and upgrading
of the distribution and interstate pipeline facilities. Expenditures are also
planned for 75 company-owned natural gas vehicle fueling stations. Investment
in Transmission and Distribution will remain essentially at the 1994 level. An
increase in 1995 expenditures in the oil and gas segment is for renewed
exploration drilling in the southwest to prevent reserve declines and for
development drilling in Appalachia delayed as a result of an extremely wet
spring in 1994.
Public Utility Holding Company Act of 1935 Reform
In June 1994, the SEC initiated reform of the Public Utility Holding Company
Act of 1935 (Act) with the announced intent of developing recommendations for
legislative or regulatory changes by July 1995. The substantive provisions of
the Act have not been amended since its enactment. The Corporation is one of
only 15 public utility holding
28
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
companies remaining registered under the Act and one of only three registered
gas utility holding companies. A two-day roundtable was held in July 1994 at
which representatives of registered companies, exempt companies, state
commissions, consumer advocates and rating agencies spoke. There was agreement
that reform of the Act is overdue. A Concept Release requesting comments was
issued in October 1994. Columbia joined with other registered gas utility
holding companies in filing comments suggesting specific regulatory reforms.
At the same time that the SEC study is proceeding, legislation calling for
repeal of the Act has been introduced in Congress. Whether the reform
ultimately will occur through repeal of the Act, through targeted amendments of
specific terms of the Act or through regulatory reforms remains to be seen.
The reporting and approval requirements and restrictions placed on the
Corporation by the Act have resulted in delays and lost opportunities and, on
occasion, may have caused the Corporation to alter a business plan to comply
with restrictions under the Act. Repeal or reform would benefit the
Corporation by eliminating or lessening these detrimental effects.
Shareholder Rights Plan
The Corporation is seeking to implement a shareholder rights plan (Rights Plan)
to protect shareholders' investments in the event of an unsolicited, inadequate
offer for the Corporation's common stock.
The Corporation's shareholders are scheduled to vote on amendments to the
Corporation's Certificate of Incorporation (Charter) required to allow
implementation of the plan at the Corporation's annual meeting on April 28,
1995. The Rights Plan will also require approval of the SEC and the Bankruptcy
Court.
In the unlikely event the Rights Plan would be triggered, all shareholders,
except the person or group attempting the unsolicited takeover, would be
entitled to purchase fractional shares of preferred stock at a discount. These
fractional shares would have voting and dividend rights equivalent to the
Corporation's common stock. The issuance of the preferred stock is designed to
substantially dilute the third party's equity interest in the Corporation and
significantly increase the Corporation's capitalization, thereby making its
acquisition much more expensive.
The Rights Plan, which will become effective as soon as all necessary approvals
are obtained, terminates automatically 18 months after the Corporation emerges
from Chapter 11 protection, subject to extension if an offer is pending.
A proxy statement which describes the proposed amendment to the Charter and the
proposed Rights Plan has been mailed to all holders of the Corporation's common
stock of record as of February 28, 1995. For further information concerning
the Rights Plan, please review the Proxy Statement (incorporated herein by
reference).
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30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATIONS
During 1994, Transmission continued to focus on a strategy of providing a
portfolio of storage and transportation services to customers at competitive
prices. This strategy will continue to be supported by new technologies to
improve customer service, modernization and upgrading of pipeline operations to
ensure safe and reliable customer service, and reengineering key business
processes to improve the companies' competitive position.
Marketing Initiatives
Columbia Transmission announced in late 1994 a proposal to expand its pipeline
and storage capacity to serve the increasing natural gas requirements of
customers in its market area. Preliminary discussions with customers have
indicated a need for the increased capacity. The extent of any capacity
expansion by Columbia Transmission is dependent upon the ultimate level of
customer commitments to be received in the coming months. However, based on
preliminary discussions, Columbia Transmission is anticipating expanding its
system to serve as much as 250,000-300,000 Mcf per day (Mcf/d) of incremental
firm markets. This expanded service will be phased in over a multi-year period
beginning in November 1997 and will be comprised of both firm transportation
and storage services. An open season for the market expansion project was held
from February 15, 1995, to March 16, 1995. Columbia Transmission believes that
the rates for these services will be competitive with other pipeline proposals.
Also in early 1995, construction was completed on facilities needed for
Columbia Transmission to provide nearly 60,000 Mcf/d of new firm transportation
service to the Eagle Point Cogeneration Plant in West Deptford, New Jersey, and
to a power plant in Massachusetts. These facilities will also allow Columbia
Transmission to provide 9,600 Mcf/d of off peak transportation service to the
Vineland Cogeneration Limited Partnership's 46.5 megawatt cogeneration plant in
Vineland, New Jersey.
Based on a November 1994 agreement with the City of Richmond, Commonwealth Gas
Services, Inc., and Virginia Natural Gas Company, Columbia Transmission will
install additional vaporization equipment at its Chesapeake liquefied natural
gas (LNG) facilities to provide these customers an incremental 33,650 Mcf/d of
peak deliveries, raising the total available sendout from 81,700 Mcf/d to
115,350 Mcf/d. The customers will fund the cost of the vaporization equipment,
which is estimated to be approximately $2.4 million. This expanded LNG service
is expected to commence in December 1995.
Columbia Transmission has reached a 25-year agreement to deliver 23,300 Mcf/d
of firm transportation to a Maryland cogeneration facility beginning in June
1996. The agreement requires $11 million of new construction, which will be
jointly funded by Columbia Transmission and the owner of the cogeneration
facility.
Capital Expenditure Program
Transmission's 1994 capital expenditure program of approximately $179 million,
and anticipated capital expenditures over the next five years, reflect the
segment's continued commitment to maintaining its competitive position by
modernizing and upgrading existing facilities. The commitment will ensure a
safe, reliable and efficient pipeline system, which conforms to all pipeline
safety regulations. Total expenditures in this area are expected to
approximate $130 million per year over the next five years. Other significant
future capital expenditures include the new market development programs
previously discussed and compliance with the Clean Air Act Amendments of 1990.
Regulatory Matters
1990 Rate Case Settlement
In 1992, the FERC approved a 1990 rate case settlement wherein Columbia
Transmission and Columbia Gulf proposed to pay pre- and postpetition refunds
with interest at FERC prescribed rates. In August 1994, the Bankruptcy Court
declined to approve this settlement, ruling that the refund is a prepetition
unsecured claim and payment of such claims must be addressed in a plan of
reorganization. Various state agencies appealed the Bankruptcy Court's order
to the District Court for the District of Delaware and filed a motion with the
FERC to order an immediate and full refund of the settlement amounts. The
District Court has held all procedural dates in abeyance pending the FERC's
final ruling on the state agencies' motion. On January 11, 1995, FERC denied
the state agencies' motion to direct Columbia
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Transmission to make all such refunds to its customers on the grounds that the
necessary regulatory approvals have been granted, and that the unresolved
issues relate solely to the interpretation of the Bankruptcy Code. In February
1995, the FERC denied rehearing on the order.
FERC Order on the Recovery of Carrying Charges
In June 1994, the FERC granted rehearing of a prior order and determined that
Columbia Transmission could recover approximately $20 million in carrying
charges related to prior period exchange activity. In July 1994, certain
parties filed a request for rehearing of this decision, which is still pending.
The beneficial effect on income of the FERC's decision was recorded in 1994.
Columbia Gulf's Rate Case
On October 31, 1994, Columbia Transmission terminated its long-standing
contract with Columbia Gulf, under which Columbia Gulf transported gas supply
acquired by Columbia Transmission in the southwest, on a cost-of-service basis
that assured recovery of Columbia Gulf's operating costs. This action was
taken because Columbia Transmission's merchant function was essentially
eliminated under Order 636. Columbia Gulf submitted a general rate filing in
order to reflect the elimination of this contract and recover higher costs
since the last rate adjustment. On November 1, 1994, it placed its new rates
into effect, subject to refund. The new rates provide additional annual
revenue of approximately $23 million over previously approved rates. Various
parties have challenged proposals by Columbia Gulf in this proceeding,
including the requested revenue increase, proposed changes in depreciation
rates, and the projected levels of service upon which the rates would be
developed. Settlement discussions with the FERC and interested parties are
ongoing. A hearing on this rate filing is currently scheduled to begin in
September 1995.
Customer Refunds
Approximately 450 claims in Columbia Transmission's bankruptcy proceedings
relating to, or arising from, contracts with its customers for sales,
transportation, gas storage and similar services and other miscellaneous claims
total approximately $550 million, plus a potentially substantial sum filed as
undetermined claims. Columbia Transmission believes that a significant portion
of these claims has been resolved. The claims filed as "undetermined" still
remain to be resolved.
In April 1994, Columbia Transmission refunded approximately $139 million to its
customers to settle a portion of their claims. The majority of these refunds
were for overpayments Columbia Transmission and its customers previously made
to upstream suppliers under Order 500/528 for take-or-pay and related charges.
A significant unresolved portion of the customer claims is attributable to the
Baltimore Gas & Electric v. FERC litigation in which various customers have
challenged Columbia Transmission's right to recover Order 500/528 direct
charges upstream pipeline companies billed Columbia Transmission. For this
issue, the accompanying financial statements reflect a $35 million reserve.
Settlement discussions are underway with the customers on this and other
significant issues related to the bankruptcy claims, as well as transition
costs recoverable from the customers under Order 636. (See Note 2H in Notes to
Consolidated Financial Statements for additional information.)
Other refund issues underlying customer claims include prepetition revenues
collected subject to refund in general rate filings, purchased gas adjustment
filings, transportation cost recovery adjustment filings, and other upstream
pipeline flowthrough filings. Reserves that reflect management's judgment of
the ultimate outcome of the proceedings have been recorded for these matters.
At a December 1993 hearing, the Bankruptcy Court observed that the FERC should
determine whether customers are entitled to the actual interest earned on
refunds being held by Columbia Transmission in a restricted investment account
(RIA) or the higher FERC-prescribed interest rate. The FERC determined that
Columbia Transmission must disburse the RIA funds with interest actually earned
while in the RIA account (which was established in March 1993) and with
interest at the FERC prescribed rate for the period prior to the date the RIA
was created. On October 5, 1994, the FERC denied a request by Columbia
Transmission's customers for rehearing of its order. The FERC's order has been
appealed.
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32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Upstream Pipeline Contracts
Columbia Transmission has transportation contracts with certain pipeline
companies that historically have been used to deliver gas to Columbia
Transmission. Columbia Transmission has settled claims filed by some of these
pipelines in the bankruptcy proceedings. These settlements provide for the
assumption of certain contracts, the termination of certain other contracts
that are no longer necessary for Columbia Transmission's operations, or the
substantial reduction of the transportation contracts. As a result,
approximately $463 million of claims filed by the pipelines against Columbia
Transmission will be withdrawn when all settlements receive Bankruptcy Court
and regulatory approvals. These settlements include projected exit fee
payments of approximately $105 million, including amounts already paid to
certain pipelines through December 1994, and are conditioned upon Columbia
Transmission's recovery of the exit fees through rates. (See Note 2 in Notes to
Consolidated Financial Statements for additional information.)
Order 94 Costs
In January 1994, the FERC rejected on rehearing prior orders approving
settlements between Columbia Transmission and four of its upstream pipeline
suppliers. These settlements permitted the pipelines to direct bill Columbia
Transmission for production-related costs authorized under FERC Order No. 94
(Order 94), provided Columbia Transmission could recover the costs from its
customers. After reversing a previous ruling and determining that Columbia
Transmission's 1985 Purchase Gas Adjustment Settlement bars such recovery, the
FERC held that the pipelines are not entitled to bill any Order 94 charges to
Columbia Transmission. It ordered the upstream pipelines to refund the
principal amounts of all Order 94 collections received from Columbia
Transmission, but waived any requirement that these pipelines pay interest on
the refunds. Since Columbia Transmission had been accruing interest income on
these refunds since 1990, these orders led to a $19.5 million reduction to
pre-tax income in 1993. In October 1994, the FERC denied all requests for
rehearing but ordered the upstream pipeline suppliers to pay Columbia
Transmission interest on the refunds from the date the stays were issued in
February 1994. As a result, in September 1994, Columbia Transmission recorded
approximately $1 million of interest income. Although the orders required that
refunds be made by November 17, 1994, Columbia Transmission and the pipelines
agreed to an extension to allow judicial review, subject to certain conditions,
one being that any refunds will accrue interest at FERC rates while the issues
are litigated. Columbia Transmission, its upstream pipelines, and two other
customers of one upstream pipeline have filed petitions for review of the
subject orders with the U. S. Court of Appeals for the District of Columbia.
Production Area Facilities
Columbia Transmission owns and operates natural gas gathering and processing
facilities in production areas. In its orders addressing the company's
restructuring proposals under Order 636, the FERC allowed Columbia Transmission
to maintain its existing rate structure and recover costs associated with these
facilities until it files its next general rate case. Management continues to
evaluate the long-term plans for the gathering and processing facilities, which
have a net book value of approximately $59.7 million at December 31, 1994.
Management believes that substantially all of these costs will be recovered
through rates or sale of the facilities; however, the ultimate outcome of this
issue is uncertain at this time, and future charges to income may be required.
Columbia Gulf Show Cause Order
In its September 1993 order on Columbia Transmission's and Columbia Gulf's
Order 636 compliance filings, the FERC initiated a proceeding concerning
Columbia Gulf's transportation service to Columbia Transmission. It directed
Columbia Gulf to show cause as to why it had not filed for FERC abandonment
authorization to reduce capacity on its mainline facilities. Columbia Gulf
responded in December 1993, asserting that no abandonment filing was required.
During 1994 and early 1995, Columbia Transmission and Columbia Gulf responded
to information requests from the FERC's staff. Management continues to believe
that an abandonment filing was not necessary; however, the ultimate outcome of
this issue is uncertain at this time.
Environmental Matters
Columbia Transmission reached an agreement during 1994 with the U.S.
Environmental Protection Agency (EPA) that will give the agency oversight
responsibility for an ongoing environmental self-assessment and remediation
program Columbia Transmission started in 1990. The agreement calls for the
cleanup to be done under the guidelines of the
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33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Comprehensive Environmental Response Compensation and Liability Act. This
agreement was approved by the Bankruptcy Court in November 1994 with a February
23, 1995, effective date.
Agreements have also been reached with two state environmental agencies
concerning Columbia Transmission's environmental remediation programs. In
Kentucky, Columbia Transmission settled all notices of violation issued prior
to January 1, 1994, and will reimburse the state for its costs to oversee the
remediation work under an EPA order. In Pennsylvania, Columbia Transmission
agreed to reimburse the state for its oversight costs. Both agreements have
received Bankruptcy Court approval.
All of Columbia Transmission's future remediation work will be performed under
the EPA order which details specific approvals and procedures that must be
followed. A study previously undertaken for Columbia Transmission which
quantified the scope of remediation activities to be undertaken in future years
is being reviewed by an independent consultant in light of the order and
additional information accumulated during 1994. The results of this study are
not expected to be available until early to mid-1995. Until the new study
results are available, management has no basis to change its previously
disclosed estimated level of environmental expenditures of up to $20 million
per year over a 10 to 12 year period. Earnings are charged as costs become
probable and reasonably estimable, regardless of when expenditures are made.
Columbia Transmission's recorded net liability for environmental matters was
approximately $135 million at December 31, 1994. This amount represents the
lower end of a range of reasonable outcomes with the upper end estimated to
total approximately $280 million based on previous studies.
Predecessor companies of Columbia Transmission may have been involved in the
operation of manufactured gas plants. When such plants were abandoned,
material used and created in the process was sometimes buried at the site.
Columbia Transmission is unable at this time to determine if it will become
liable for any characterization or remediation costs at such sites.
During 1994, Columbia Gulf continued its remediation program. Additional site
characterization studies at various locations were completed which resulted in
additional accruals of approximately $19.3 million for environmental matters of
which a portion was recovered in current period revenues. The additional
accruals were to remediate newly discovered PCB and hydrocarbon contamination
at certain compressor station sites, pipeline drip sites, and measurement
sites. During the fourth quarter of 1994, Columbia Gulf made significant
progress on completing remediation work identified to date. Additional
remediation work remains to be completed in 1995. Columbia Gulf's
environmental liabilities recorded as of December 31, 1994, are $5.8 million
which includes the estimate for 1995 work. Should future screenings identify
additional exposure, the remediation costs will be quantified and additional
accruals may become necessary.
The eventual total cost of full future environmental compliance for
Transmission 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 potentially
responsible party by the EPA and the difficulty of determining liability, if
any, in proportion to other responsible parties; (5) possible insurance
recoveries; and (6) the effect of possible technological changes relating to
future remediation.
Management expects most environmental assessment and remediation costs will be
recoverable through rates or insurance. Court suits have been filed by both
Columbia Transmission and Columbia Gulf against several of their insurance
carriers for recovery of environmental remediation costs. Although significant
charges to earnings could be required prior to rate recovery, management does
not believe that environmental expenditures will have a material adverse effect
on the Corporation's financial position based on known facts, existing laws and
regulations and the period over which expenditures are required.
Clean Air Act Amendments of 1990
Transmission previously disclosed that, based upon preliminary studies to
determine the impact of the Clean Air Act Amendment of 1990 (CAA- 90),
estimated capital expenditures necessary to comply with the first phase could
be in
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34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
excess of $30 million over the next few years. As a result of certain areas
being reclassified from non-attainment to attainment, it is now estimated that
the capital expenditures necessary to comply with the first phase will be
approximately $15 million over the next few years. Until regulations are
finalized, the capital expenditures necessary to comply fully with CAA-90
cannot be estimated. Management anticipates that capital expenditures made in
compliance with CAA-90 will be recoverable through the ratemaking process.
Partnership Issues
Columbia Gulf is a general partner in the Trailblazer, Overthrust and Ozark
pipeline partnerships. Since the partnerships are nonrecourse,
project-financed pipelines, the partnerships' firm shipper contracts were
assigned as collateral for loans to various banks (or in the case of Ozark, to
the Indenture Trustee).
During 1994, various pipeline shippers, including Columbia Transmission,
entered into negotiations with the partnerships for exit fees to substantially
reduce the cost of or provide for the release from transportation contracts.
Agreements have been reached on certain contracts and are currently pending
approval by the FERC. Columbia Gulf's investment in the partnerships as of
December 31, 1994, amounted to $34.7 million, net of valuation reserves and
before related deferred taxes.
In February 1995, an agreement was reached which provides for the sale of
Columbia Gulf's Ozark partnership investment. The agreement contains usual
closing conditions and is subject to certain governmental approvals. Closing
is expected to occur on May 1, 1995. The impact of the sale of Columbia Gulf's
interest in the partnership is not expected to have a material impact on the
financial condition of the company.
Reengineering Activities
As previously reported, the Corporation initiated a reengineering program in
which the subsidiaries were to evaluate and streamline organizational
structures to improve efficiencies. This continuous improvement process will
extend into 1995 and beyond. In 1993, Transmission established reserves of
approximately $4 million for the projected cost of its Reengineering Retention
and Release program for employees whose positions were being eliminated.
During 1994, this reserve was increased by $3.9 million. The total reserve
balance for Transmission for the Reengineering Release and Retention program as
of December 31, 1994, was approximately $3.4 million.
Volumes
Throughput for Columbia Transmission is now primarily composed of a
transportation service, while prior periods included tariff sales to local
distribution companies (LDCs) and other customers in its market area. Columbia
Gulf throughput includes main line transportation service from Louisiana to
West Virginia and short-haul transportation service primarily from the Gulf of
Mexico to Rayne, Louisiana. Transmission's 1994 throughput was 1,272 Bcf, a
decrease of 83.9 Bcf from 1993. This decrease reflects a timing change for the
recognition of transportation for storage activity and reduced short-haul
transportation needed by customers for spot purchases. In 1993, throughput
decreased 18.4 Bcf from 1992 to 1,355.9 Bcf. The reduction was largely
attributable to a small decrease in sales resulting from implementing Order 636
in November 1993, and lower transportation reflecting the effect of a one-time
arrangement in 1992 whereby customers used transportation to repay certain gas
delivered to them in an earlier period. Under Order 636, a large portion of
Transmission's fixed costs are being recovered through a monthly demand charge.
As a result, variations in total throughput have less impact on income.
An increase of 142.7 Bcf in market area transportation over 1993 was primarily
due to customers switching from sales to transportation services, resulting
from the implementation of Order 636, partially offset by a timing change in
the recognition of market area transportation for storage activity. Absent
these changes, total volumes delivered to market reflected a small decrease of
8 Bcf from 1993 due primarily to slightly warmer weather.
Market area transportation decreased 13.1 Bcf from 1992 to 1993 due primarily
to the one-time arrangement in 1992 in which customers used transportation to
repay certain gas Columbia Transmission delivered to them during the 1990-1991
winter. This was partially offset by a throughput improvement resulting from
customers using storage transportation services to deliver gas withdrawn from
storage in 1993.
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35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Columbia Gulf's mainline transportation service in 1994 increased 10.4 Bcf over
1993 and 5.6 Bcf between 1992 and 1993. This increase primarily reflected
additional transportation services for customers to move gas to Columbia
Transmission's storage and to meet their supply requirements.
In 1994, short-haul transportation, which is primarily used by marketers and
customers for delivery of spot market gas, decreased from 1993 by 29.2 Bcf
while 1993 was essentially unchanged from the prior year.
With the implementation of Order 636 on November 1, 1993, sales volumes were
virtually eliminated, except for small volume customers. The 1994 decrease
from the prior year was largely offset by increased transportation services as
virtually all former sales customers converted their pre-Order 636 sales
requirements to firm transportation services.
The 12.3 Bcf decrease in sales between 1992 and 1993 was due primarily to the
implementation of Order 636, partially offset by colder weather during 1993 and
the timing of prepaid gas sales.
Net Revenues
Net revenues for 1994 were $872.9 million, an increase of $31.4 million over
the prior year. Due to the substantial reduction of the merchant function,
certain costs previously included as a cost of gas sold and transportation
expense are now included in operating expense rather than net revenues. This
change increased both net revenues and operating expense by $155.8 million, but
had no effect on operating income. After adjusting for this reclassification,
net revenues decreased $124.4 million. This decrease included the effect of a
$35 million reserve established in 1994 for various customer and regulatory
settlements discussed previously and a lower cost-of-service recovery level of
$26.4 million reflecting Columbia Transmission's restructuring under Order 636,
which required that costs related to its merchant function be eliminated from
rates. Reduced net revenues attributable to the lower cost-of-service is
largely offset by elimination of merchant-related costs in operating expenses.
The timing of recovery of storage service transportation costs also reduced net
revenues. In addition, 1993 benefited from higher revenue of $20.8 million
associated with the recovery of certain gas costs in that period allowed under
the terms of a 1989 customer settlement and a $21.6 million improvement for a
reserve adjustment.
Net revenues in 1993 were $841.5 million, an increase of $80.1 million over
1992. Included in 1993's net revenues was the beneficial effect of several
unusual items, including the recovery of prior period gas costs, a rate refund
reserve adjustment and the favorable effect of colder weather in 1993.
Operating Income
For 1994, operating income of $205.4 million increased $26.7 million over 1993.
Operating expense decreased $151.1 million after adjusting for certain costs
mentioned above. In 1994, operating expense was lower largely due to a
writedown of $57.5 million in the investment in the Cove Point LNG facility as
well as a $66.8 million environmental reserve addition in 1993 and lower other
taxes in the current period. This improvement was tempered by an increase in
depreciation expense of $6.1 million, largely due to a higher plant balance in
service and new depreciation rates, and increased labor and benefits expense
due in part to higher employee relocation costs.
Operating income for 1993 of $178.7 million increased $48.8 million over 1992.
The combined effect of higher net revenues and a 1992 provision for gas supply
costs more than offset the impact of the writedown for the investment in the
Cove Point LNG facility. Additional reserves for environmental costs of $66.8
million and $65.3 million were recorded in 1993 and 1992, respectively. After
adjusting for these and other unusual items, operating income would have
increased $37.8 million. These improvements more than offset higher operating
expenses, including increased labor and benefits costs due in part to employee
severance costs.
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36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $(18.3) $1,027.2 $ 924.8
Transportation revenues 742.9 633.2 449.0
Storage revenues 141.7 125.3 113.7
- -------------------------------------------------------------------------------------------------------------
Total revenues 866.3 1,785.7 1,487.5
- -------------------------------------------------------------------------------------------------------------
Less: Associated cost of gas (6.6) 944.2 726.1
- -------------------------------------------------------------------------------------------------------------
Net Revenues 872.9 841.5 761.4
- -------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Provision for gas supply charges - - 38.6
Operation and maintenance 509.6 451.3 438.3
Depreciation 103.9 97.8 95.6
Other taxes 54.0 56.2 59.0
Writedown of investment in Columbia LNG Corporation - 57.5 -
- -------------------------------------------------------------------------------------------------------------
Total Operating Expenses 667.5 662.8 631.5
- -------------------------------------------------------------------------------------------------------------
OPERATING INCOME $205.4 $ 178.7 $ 129.9
- -------------------------------------------------------------------------------------------------------------
TRANSMISSION OPERATING HIGHLIGHTS
1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 179.1 137.2 114.2 152.9 279.5
- --------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Transportation
Columbia Transmission
Market area 1,038.6 895.9 909.0 849.9 799.5
Columbia Gulf
Main-line 590.3 579.9 574.3 535.4 613.3
Short-haul 595.9 625.1 625.0 564.7 497.4
Intrasegment eliminations (953.7) (928.7) (930.0) (833.1) (810.7)
- --------------------------------------------------------------------------------------------------------------
Total Transportation 1,271.1 1,172.2 1,178.3 1,116.9 1,099.5
Sales 0.9 183.7 196.0 112.6 89.2
- --------------------------------------------------------------------------------------------------------------
Total Throughput 1,272.0 1,355.9 1,374.3 1,229.5 1,188.7
- --------------------------------------------------------------------------------------------------------------
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37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATIONS
Distribution launched a number of marketing, regulatory, service and
operational initiatives in 1994 to overcome the challenges and take advantage
of opportunities that are present in the new, highly-competitive energy
marketplace. They include: reengineering key business processes, enhancing
market research capabilities, targeting nontraditional markets, providing
cost-effective customer services, maintaining a flexible, reliable, competitive
gas supply, and pursuing needed regulatory reforms.
Marketing Initiatives
Both electric and gas-on-gas competition continue to threaten Distribution's
traditional markets. Electric's aggressive marketing programs have made
inroads into Distribution's space and water heating markets over the past
several years. Deregulation within the electric industry and more open access
to the electric grid is another competitive factor that could be significant,
particularly in the industrial segment. There is also competition with other
gas companies and with pipeline companies who seek to connect existing
customers directly, bypassing Distribution.
Another challenge facing Distribution is the mature nature of its traditional
residential, commercial and industrial markets. Despite a 1.6 percent net
increase of 30,400 residential and commercial customers during 1994, average
usage by customers in these market segments continues to trend downward due to
conservation and more efficient appliances. Just to stay even, Distribution
must add three customers for every two it loses. As a result, only nominal
increases in deliveries to these core markets are projected over the next few
years.
To overcome these competitive challenges and improve profitability,
Distribution is initiating marketing strategies based on analyses of its core
residential, commercial and industrial market segments. Through these studies,
Distribution will be better able to evaluate current and potential marketing
programs and the profitability of each segment in relation to the resources
needed to serve it, determine how to improve sales to existing customers and
define customers' energy and service needs.
To ensure it is situated to effectively compete in growth areas, Distribution
is planning strategic line extensions. This proactive approach is supported by
Distribution's competitive rate structure and the quality, flexibility and
responsiveness of its customer services.
Although approximately 60 percent of Distribution's industrial and large
commercial throughput is susceptible to bypass, it has avoided any substantial
inroads by pipelines into these markets through rate and capacity release
strategies and the negotiation of unique customer service arrangements. As a
result, estimated exposure is only 20 percent of total industrial and
commercial throughput that accounts for only $10 to $15 million in annual net
revenue. Efforts by the electric industry to make additional inroads into
Distribution's traditional residential and commercial markets are being
countered through aggressive marketing plans and innovative financing programs
that encourage customers to choose natural gas fueled replacement appliances.
Since 1987, approximately 1.5 Bcf, less than one percent of Distribution's
annual residential load, was lost to electric add-on heat pumps and electric
water heaters. Distribution plans to reverse this trend by aggressively
marketing and promoting new technologies such as the new "Triathlon" gas heat
pump, the first commercial natural gas fueled year-round climate control
system. While net volume gains may not be significant, existing volumes will
be retained.
To enhance opportunities for future growth, Distribution is targeting several
nontraditional markets, including natural gas vehicles (NGVs), cooling and
electric power generation. These offer significant growth opportunities but
each will require time to develop.
In 1994, Distribution initiated a five year, $38 million program that will help
provide the infrastructure needed to encourage the purchase and use of NGVs.
It will establish up to 160 publicly accessible natural gas fueling stations
throughout its service territory. A total of 20 new fueling stations were
completed in 1994, and an additional 75 fueling stations are planned in 1995.
During the five-year period, Distribution expects to increase the number of
NGVs in its own fleet from 600 to 2,000.
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38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
The Clean Air Act Amendments of 1990 (CAA-90), which require many electric
power generating facilities to reduce emissions by installing expensive exhaust
scrubbers or using cleaner burning fuels, is creating new marketing
opportunities for natural gas, the cleanest burning of all hydrocarbons.
Distribution now serves 15 large generating plants that use 25 to 30 Bcf a
year, including a facility in Virginia that was added in 1994. Additional
growth in this market is expected toward the end of the decade when Phase II of
CAA-90, which contains more stringent standards, is implemented. Distribution
anticipates current deliveries for power generation could double by the year
2000.
Distribution is also promoting the use of new, environmentally friendly and
cost-efficient natural gas cooling equipment by commercial and industrial
customers. It currently serves only about two percent of this market. In 1994,
new sales of gas cooling equipment in Distribution's territory totaled 3,000
refrigerant tons and added 54 million cubic feet of annual gas load. The new
"Triathlon" heat pump is also expected to increase residential use of natural
gas for cooling.
Capital Expenditures
In addition to maintaining and upgrading facilities to assure safe, reliable
and efficient operation, Distribution's 1994 capital expenditure program of
$151 million (an increase of $33 million over 1993) was directed at extending
service to new areas and developing future markets including NGVs and power
generation.
The 1995 capital expenditure program amounts to approximately $158 million,
including $56 million for new business development and $69 million for
replacement and betterment projects.
Gas Supply
In 1994, for the first time in its history, Distribution purchased all of its
natural gas supply directly from producers and marketers and contracted for
capacity on several different pipelines to transport this gas from various
producing areas to its customers. Its contracts for gas supply not only
consider the lowest price, but also the reliability, flexibility and
performance capabilities of the suppliers and the pipelines involved.
To meet its customers' needs during the heating season, Distribution's gas
supply portfolio consists of storage services (50 percent), firm capacity on
interstate pipelines (48 percent) and peaking service for the coldest winter
days (2 percent). This favorable mix of storage and transportation permits
high annual utilization of Distribution's firm transportation capacity.
FERC Order 636 allows Distribution and other pipeline capacity holders to
release unneeded capacity to third parties. During 1994, Distribution released
about 190 Bcf in pipeline capacity resulting in revenues of approximately $10.5
million to reduce costs to firm customers. In return for the risks associated
with aggressively managing the release of capacity and thereby reducing
customer costs, Distribution is proposing capacity release incentive plans in
some states that would permit retention of a portion of the resulting revenues.
Reengineering
A reengineering program addressing corporate center support activities
evaluated various key processes and streamlined the organizational structure to
improve operating efficiencies. Accordingly, a liability and associated
expense of approximately $2.5 million were recorded in third quarter 1993 for
projected severance costs to compensate employees whose positions were
eliminated in 1994 or are scheduled for elimination in 1995. The liability as
of December 31, 1994 is approximately $2 million.
In 1994, Distribution began implementation of a comprehensive initiative termed
"Project Customer" to reshape, streamline and enhance field processes involved
in delivering customer service. As a result of consolidating certain functions
and implementating new practices, Distribution recorded a liability of $5.1
million and associated expense of approximately $4.1 million in December 1994
representing salary and related severance benefit costs for 240 employees.
Commonwealth Gas Services, Inc. (Commonwealth Services) recorded approximately
$1 million as a regulatory asset pending recovery in a future general rate
case. The actual termination of employees and related cash payments are
expected to begin in the second quarter of 1995 and continue over several
years. As further improvement measures are identified, additional reserves
will be required.
38
39
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Regulatory Matters
Regulatory activity in Distribution's operating jurisdictions during 1994
resulted in a series of unprecedented settlements. These arrangements provided
over $70 million in annual revenue increases, recovery of postretirement
benefits in all states and significant regulatory reform initiatives, including
pilot weather normalization adjustments in Ohio and Kentucky, and a gas supply
management incentive mechanism in Pennsylvania.
In Ohio, the Public Utilities Commission approved a settlement agreement that
resolved a number of service and rate incentive issues and provided for an
annual revenue increase of $47.5 million, effective November 1994. This
comprehensive settlement was developed through a unique collaborative effort by
key stakeholders who reached an agreement for an increase in rates prior to
formal rate proceedings. The agreement provided for recovery of operating
costs based on a partially projected period, a possible revenue adjustment
effective in May 1996, and a recovery mechanism for Order 636 transition costs.
Under the agreement, Columbia Gas of Ohio, Inc. (Columbia of Ohio) is not
permitted to file a general rate case that would become effective prior to
January 1998. Additionally, the settlement included a one-year experimental
weather normalization adjustment to alleviate the impact of unusual weather on
customers' bills and Columbia of Ohio's revenues. This provision required a
$6.6 million reserve to be recorded in the second quarter of 1994 for a
customer refund of revenues resulting from unusually cold weather in early
1994. As a result of recent customer concerns with this program, Columbia of
Ohio agreed to several modifications in February 1995. The modifications
include an agreement between parties to continue the program through the trial
period to appropriately evaluate potential benefits of the program but to
discontinue any further upward adjustment to customer bills associated with the
program.
In Pennsylvania, the Public Utility Commission approved a settlement agreement
that increased annual revenues by $16.6 million, effective August 1, 1994. To
mitigate regulatory lag, operating costs were projected through September 1994,
and rates went into effect three months earlier than they would have had the
case been fully litigated. The commission order approved, with modifications,
Columbia Gas of Pennsylvania, Inc.'s (Columbia of Pennsylvania) annual gas cost
recovery filing and an incentive program for gas supply management.
Subsequently, the Pennsylvania Office of Consumer Advocate (OCA) challenged the
legality of the commission's adoption of a gas supply management incentive
mechanism. The commission granted the OCA's request for reconsideration of the
issue but has not ruled on the merits of the request.
In Kentucky, the Public Service Commission approved Columbia Gas of Kentucky,
Inc.'s (Columbia of Kentucky) comprehensive settlement that provides for a
$9.75 million increase in annualized revenues in three steps: $6 million in
November 1994, $2.25 million in October 1995, and $1.5 million in October 1996.
The settlement precludes Columbia of Kentucky from filing a new rate case for
three years but provides for a weather normalization adjustment over this same
period.
In Virginia, Commonwealth Services received approval from the State Corporation
Commission of the 1993 regulatory settlement that provided for a $3.5 million
increase in annual revenue, effective in mid-1993.
In Maryland, Columbia Gas of Maryland, Inc. (Columbia of Maryland) implemented
the second phase of a two-step increase in rates, effective March 1, 1994, as
provided in its 1993 general rate settlement. The $600,000 increase covered
the costs of constructing, operating and maintaining a propane peak-shaving
plant in Hagerstown, Maryland. The Public Service Commission (PSC) recently
approved a settlement of Columbia of Maryland's expedited rate case that was
filed in mid-1994. The new rate levels that became effective November 1, 1994
are designed to generate an additional $800,000 in annual revenue.
In 1995, rate case filings are tentatively scheduled in Maryland, Virginia and
Pennsylvania seeking increased annual revenues totalling approximately $30
million. The majority of these revenues will not be realized until 1996.
There is ongoing interest in extending unbundled service, or open
transportation, to residential/human needs customers. The staff of the
Maryland PSC has recommended that utilities be required to offer a full range
of unbundled services by 1996, and the PSC has requested that utilities respond
to the staff's recommendation. In Ohio, Columbia of Ohio
39
40
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
will work with the Collaborative to study the feasibility of residential
transportation and performance-based rate incentives. Through regulatory,
political and other forums, Distribution will continue to actively participate
in shaping the definition of the LDC's merchant role in the evolving energy
market.
Full recovery of Distribution's accrued costs for other postretirement benefits
has been approved in all of its five states. In addition, Columbia of Ohio and
Columbia of Kentucky are permitted to recover the transition obligation over 18
years, Columbia of Pennsylvania over 18 years and five months, Columbia of
Maryland over 20 years, and Commonwealth Services over 40 years. Columbia of
Kentucky, as part of a comprehensive rate settlement, absorbed the 1993
incremental other postretirement benefit costs that had been previously
deferred. Accordingly, a pre-tax charge of approximately $875,500 was recorded
in the fourth quarter of 1994.
Although Columbia of Pennsylvania has been authorized to recover its other
postretirement benefit costs, recent intermediate appellate court rulings
involving two other Pennsylvania utilities could impact the future
recoverability of these costs. Both cases may be appealed to the Pennsylvania
Supreme Court. Depending upon the final disposition of the cases, Columbia of
Pennsylvania's recovery of these incremental other postretirement benefit costs
might be subject to question. It is management's opinion, however, that
Columbia of Pennsylvania will be allowed continued recovery of other
postretirement benefit costs on an accrual basis including the transition
obligation.
Environmental Matters
During 1994, Distribution made significant progress in implementing its
comprehensive environmental program, which is designed to ensure compliance
with all state and federal environmental requirements.
During the year, Distribution continued its inventory of sites as well as a
review of current procedures. The initial inventory and assessment process is
expected to continue over the next two years, after which Distribution expects
to implement an ongoing site assessment process designed to monitor continuing
compliance.
Distribution's environmental emphasis continues to focus on former manufactured
gas plant sites. Thirteen such sites have been identified, and environmental
investigations are being conducted at five of these sites where remedial action
may be required. Investigations will be conducted at the other sites in the
future. To the extent site investigations have been completed, remediation
plans developed, and any Distribution responsibility for remedial action
established, the appropriate liability has been recorded. As additional
investigations are completed and remediation costs can be determined, the
appropriate liabilities will be recorded. Distribution also recorded
corresponding regulatory assets in anticipation of the recovery of remediation
costs through normal rate proceedings. As of December 31, 1994, Distribution's
recorded net liability was $5.6 million.
Integrated Resource Planning
The 1992 Federal Energy Policy Act required that state utility commissions
consider the benefits of adopting the Act's integrated resource planning (IRP)
and demand-side management (DSM) provisions for natural gas by October 1994.
Generally speaking, the state regulatory commissions in Distribution's market
area concluded that the additional federal regulations were unwarranted and
that existing state rules and regulations are sufficient to allow LDCs a
flexible approach to resource planning and the pursuit of cost-effective DSM
programs.
Electric DSM programs continue to be a significant concern to Distribution.
While most electric DSM programs are proceeding on a pilot basis, there is a
large potential competitive impact if these ratepayer-funded marketing programs
continue and expand on a large-scale basis. Distribution is developing and
implementing cost-effective DSM programs on a selected basis that should enable
it to continue to effectively compete for new load and replacement appliances
and equipment to improve system load factors and operating economics. However,
because the DSM economic justification of capacity avoidance generally supports
higher incentives for certain electric end-use equipment, competitive concerns
remain.
Distribution continues to encourage state regulators to deal with utility IRP
programs on a comprehensive basis. It believes that under such an approach,
commissions are more likely to recognize the many significant resource
40
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
efficiency and environmental advantages of using natural gas rather than
electricity for most residential and commercial and many industrial end uses.
Most commissions, however, have been reluctant to deal with the relative
environmental and resource conservation impacts of using natural gas versus
coal, oil or nuclear generated electric power for residential and commercial
end uses because of the complexity and political sensitivity of the issue in
states with major coal production.
Volumes
Throughput of 513 Bcf for 1994 reflects an increase of 3.2 Bcf over 1993.
Transportation deliveries were 15 Bcf higher due largely to increased
industrial demand in Ohio, Virginia and Kentucky as well as industrial
customers shifting from tariff sales to transportation services in order to
reduce their overall energy costs. The transportation improvement was tempered
by a sales decline of 11.8 Bcf that included the effect of nearly 3 percent
warmer weather. Also reducing sales was lower customer usage due to
conservation measures and more efficient appliances.
Distribution's 1993 throughput of 509.8 Bcf reflected a 23.1 Bcf increase over
1992. Transportation deliveries were 13.8 Bcf higher due largely to increased
usage by power generating facilities while the sales increase of 9.3 Bcf
reflected colder weather in 1993 and additional customers being served.
Net Revenues
The beneficial impact from new rates put into effect during 1994, resulting
from recent regulatory settlements, and increased transportation deliveries
were the principal reasons for higher net revenues of $735.9 million, up $9.9
million over last year. Partially offsetting these improvements was a $21.4
million effect for reduced sales volumes. Revenues would have been reduced by
an additional $5 million had it not been for the pilot weather normalization
adjustment that is allowed in some of Distribution's service areas. Columbia
of Ohio's payment plan for low income customers, which was suspended for much
of 1994, resulted in a $6.6 million reduction in both revenues and operating
expenses; and therefore, had no effect on operating income.
Net revenues of $726 million for 1993 were $29.5 million higher then the prior
year. Higher throughput and new rates in effect during 1993 represented the
largest portion of this increase.
Operating Income
Operating income for 1994 of $128.3 million, decreased $18.1 million from 1993,
due to $28.0 million of higher operating expenses that were only partially
offset by improved net revenues. Other taxes increased $12.2 million due
principally to higher gross receipts and property taxes while the $2.2 million
increase in depreciation expense primarily reflected plant additions. The
increase in operation and maintenance expense of $13.6 million included higher
labor and benefits expense as well as the effect of employee severance accruals
associated with implementing productivity and customer service initiatives.
Reducing the effect of these higher expenses was the $6.6 million of lower
expense for the customer low income payment plan. Also tempering the effect of
higher operating expenses was a unique regulatory arrangement that permits
Columbia of Ohio to capitalize certain interest charges that improved net
income but not operating income. (The beneficial effect of this issue is
eliminated on the consolidated financial statements because the Corporation,
while in Chapter 11, is not recording interest expense.)
The effect of $29.5 million higher net revenues for 1993 compared to 1992, was
partially offset by increased operating expenses of $20.8 million, which
resulted in improved operating income of $8.7 million. Higher operation and
maintenance expense was due primarily to changes attributable to implementing
Order 636 as well as higher other expenses resulting from the initial costs
incurred from the streamlining of the corporate service function. Plant
additions led to higher depreciation expense while increased gross receipts
taxes and property taxes were due to higher taxable revenues and plant
additions.
41
42
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1994 1993 1992
- -------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $1,741.9 $1,754.0 $1,574.2
Less: Cost of gas sold 1,087.2 1,098.6 945.3
- -------------------------------------------------------------------------------------------
Net Sales Revenues 654.7 655.4 628.9
- -------------------------------------------------------------------------------------------
Transportation revenues 88.8 76.7 73.4
Less: Associated gas costs 7.6 6.1 5.8
- -------------------------------------------------------------------------------------------
Net Transportation Revenues 81.2 70.6 67.6
- -------------------------------------------------------------------------------------------
Net Revenues 735.9 726.0 696.5
- -------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 405.1 391.5 382.7
Depreciation 64.5 62.3 57.6
Other taxes 138.0 125.8 118.5
- -------------------------------------------------------------------------------------------
Total Operating Expenses 607.6 579.6 558.8
- -------------------------------------------------------------------------------------------
OPERATING INCOME $ 128.3 $ 146.4 $ 137.7
- -------------------------------------------------------------------------------------------
42
43
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS*
1994 1993 1992 1991 1990
- -------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 151.4 117.8 99.7 98.0 107.0
- -------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
Residential 189.7 194.7 186.2 178.4 173.5
Commercial 80.8 83.4 81.8 78.3 76.8
Industrial and Other 10.0 14.2 15.0 11.0 16.8
- -------------------------------------------------------------------------------------------------------------
Total 280.5 292.3 283.0 267.7 267.1
Transportation 232.5 217.5 203.7 194.7 198.6
- -------------------------------------------------------------------------------------------------------------
Throughput 513.0 509.8 486.7 462.4 465.7
- -------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
Spot market** 235.3 142.3 169.9 113.9 140.6
Producers 67.5 56.9 57.1 64.4 40.4
Pipelines - 118.4 84.0 68.2 51.7
Storage withdrawals (injections) (14.0) (6.7) (10.7) 11.4 38.1
Other (8.3) (18.6) (17.3) 9.8 (3.7)
- -------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 280.5 292.3 283.0 267.7 267.1
Gas received for delivery
to customers 232.5 217.5 203.7 194.7 198.6
- -------------------------------------------------------------------------------------------------------------
Total Sources 513.0 509.8 486.7 462.4 465.7
- -------------------------------------------------------------------------------------------------------------
CUSTOMERS
Residential 1,764,968 1,737,609 1,711,946 1,686,918 1,724,281
Commercial 167,067 164,037 161,937 160,378 165,144
Industrial and Other 2,312 2,302 2,382 2,366 2,420
- -------------------------------------------------------------------------------------------------------------
Total 1,934,347 1,903,948 1,876,265 1,849,662 1,891,845
- -------------------------------------------------------------------------------------------------------------
DEGREE DAYS 5,530 5,677 5,507 4,998 4,783
- -------------------------------------------------------------------------------------------------------------
* Includes Columbia Gas of New York, Inc. through March 31, 1991.
** Reflects volumes under purchase contracts of less than one year.
43
44
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
Lower energy prices, particularly in the second half of 1994, adversely
impacted operations of the oil and gas segment. Overall, natural gas prices
averaged $2.18 per Mcf in 1994 compared to $2.28 in 1993. Oil prices also
declined, averaging $15.09 per barrel in 1994 as compared to $16.17 per barrel
in 1993. If the depressed level of natural gas prices experienced early in
1995 continues, a writedown of the oil and gas properties may be required for
the first quarter of 1995.
Fluctuations in oil and gas prices can cause significant variations in revenues
for the oil and gas segment. To dampen the impact of these price swings and
help stabilize revenues, the oil and gas segment uses options contracts and
price swap agreements to lessen the price risk for a portion of its production.
Capital Expenditures
The 1994 capital expenditures program increased to $102 million from the $95
million level in 1993. While a large portion of these expenditures is for
development drilling and the installation of an offshore production platform in
the Gulf of Mexico, expenditures for the exploration program in the Southwest
increased approximately $9 million. In 1995, the capital expenditure program
of $118 million will continue to focus on development drilling while
maintaining a significant level of expenditures for exploration.
Columbia Gas Development Corporation (Columbia Development) drilled 64 gross
(32 net) wells in 1994, with an 86 percent success rate. Of these, 39 were
drilled in the Austin Chalk located in Texas, all of which were successful.
Productivity and economics in the Austin Chalk were enhanced by continued
emphasis on drilling multiple horizontal laterals from a single vertical well
bore. This type of well increases production and reduces the overall cost per
lateral, since more productive reservoirs can be accessed and the costs of the
vertical portion of each well are shared by more than one lateral.
Horizontal wells drilled in the Austin Chalk formation in 1994 tested at daily
rates ranging from 250 to 1,750 barrels of oil with up to 3.5 million cubic
feet of associated gas. Columbia Development holds varying interests in these
wells.
Columbia Development participated in nine wells drilled offshore in the Gulf of
Mexico during 1994. It has a 100 percent working interest in two of these
wells, each of which tested at rates in excess of 6 million cubic feet of gas
per day. Columbia Development has varying working interests in the remaining
wells.
In the Appalachian area, Columbia Natural Resources, Inc. (CNR), completed 121
gross (69 net) development wells in 1994, with a success rate of 83 percent.
Approximately 44 percent of these wells were in the Rose Run formation in
southeast Ohio, with a success rate of 65 percent which is more than double the
industry average. Favorable reservoir characteristics allow Rose Run prospects
to quickly generate a return on invested capital. CNR's 1995 development
program has been increased to a level sufficient to commence drilling on
previously identified Rose Run prospects.
Gathering Facilities
Under Order 636, the natural gas pipeline industry is required to eventually
unbundle gathering services from other transportation services. Columbia
Transmission provides transportation services, including gathering services,
for a significant portion of gas produced by CNR. If there is a significant
increase in gathering rates as a result of unbundling, certain reserves could
be uneconomical to produce which could have a material adverse effect on CNR's
operating strategies and financial results beginning in 1996. The extent of
any potential asset impairment or increase in operating costs cannot be
quantified at this time.
Reserves
Net proved gas reserves at the end of 1994 totalled 684 Bcf, compared to 697
Bcf at the end of 1993. The decline in gas prices and a slight increase in
lifting costs are primarily responsible for a 36 Bcf downward revision in
44
45
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
recoverable gas reserves in the Appalachian area. Without this reduction,
newly discovered Appalachian reserves and extensions of 54 Bcf exceeded
production by approximately 21 Bcf. In the Southwest new discoveries and
extensions of 31 Bcf and an upward revision of 5 Bcf in recoverable gas
reserves exceeded production during 1994 by approximately 2 Bcf.
Proved reserves for oil, condensate and natural gas liquids decreased slightly
from 12.8 million barrels at the end of 1993 to 12.3 million barrels for 1994
as production of 3.6 million barrels was largely replaced through extensions
and discoveries of 1.4 million barrels and net upward reserves revisions of 1.6
million barrels.
Royalty Dispute
Columbia Development resolved a royalty dispute with the U.S. Minerals
Management Service (MMS) in 1994 for which a $5.4 million reserve had been
established. Under the terms of a settlement, Columbia Development agreed to
remit approximately $500,000 in additional royalties and interest to the MMS
and the remainder of the reserve was reversed.
Volumes
Gas production decreased 6.7 percent in 1994 to 66.7 Bcf as production declined
in both the Southwest and Appalachian areas. The decrease in Southwest
production was due to normal production declines, production problems on an
offshore well and wells shut-in due to workovers. In the Appalachian area, the
decline was attributable to normal declines from older wells combined with
production curtailments resulting from replacement and repair of Columbia
Transmission's lines and compressor facilities. In 1993, gas production
increased 3 percent to 71.5 Bcf over 1992, largely due to new Southwest
offshore production and new onshore production in Texas, south Louisiana and
New Mexico.
Oil and liquids production in 1994 of approximately 3.6 million barrels was
essentially unchanged from 1993. An increase in Appalachian oil production due
to the increased activity in the eastern Ohio area was offset by a decrease in
natural gas liquids produced in the Southwest program due to the
above-mentioned offshore well experiencing production problems. In 1993, oil
and liquids production increased nearly 18 percent due to the success of the
Southwest program.
Operating Revenues
In 1994, operating revenues were $205.3 million, a decline of $16.9 million or
8 percent from 1993. The impact of lower oil and gas prices and the decrease
in gas production was only partially offset by the combined effect of recording
of a reserve of $5.4 million in 1993 for a royalty dispute and the subsequent
reversal of most of this reserve in 1994. Lower energy prices and gas
production in 1994 more than offset a $7.5 million improvement from hedging
results compared to 1993.
In 1993, higher gas prices along with increased oil and gas production resulted
in operating revenues of $222.2 million, a 12 percent increase over 1992.
Operating Income (Loss)
Operating income for 1994 declined by $23 million to $30.6 million due to the
lower operating revenues and an increase in depletion expense of $12.4 million
as a result of the depressed energy prices.
Operating income was $53.6 million in 1993 compared to an operating loss of
$101.2 million in 1992. The 1992 operating loss was due to a $126.4 million
writedown in the carrying value of oil and gas properties. The improvement in
operating income in 1993 also reflected higher operating revenues and lower
depletion expense.
45
46
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
STATEMENTS OF OPERATING INCOME FROM OIL AND GAS OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Gas $150.7 $163.8 $ 143.1
Oil and liquids 54.6 58.4 55.6
- -------------------------------------------------------------------------------------------------------------
Total Operating Revenues 205.3 222.2 198.7
- -------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 76.9 83.7 78.7
Depreciation and depletion 86.2 73.8 210.0
Other taxes 11.6 11.1 11.2
- -------------------------------------------------------------------------------------------------------------
Total Operating Expenses 174.7 168.6 299.9
- -------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) $ 30.6 $ 53.6 $(101.2)
- -------------------------------------------------------------------------------------------------------------
OIL AND GAS OPERATING HIGHLIGHTS*
1994 1993 1992 1991 1990
- -------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 101.6 95.1 70.8 120.8 229.0
- -------------------------------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf) 683.8 697.0 779.5 808.1 925.7
Oil and Liquids (000 barrels) 12,255 12,792 14,650 15,568 18,991
- -------------------------------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf) 66.7 71.5 69.2 76.3 75.3
Oil and Liquids (000 barrels) 3,611 3,603 3,061 3,411 2,688
- -------------------------------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf) 2.18 2.28 2.02 1.81 2.00
Oil and Liquids ($ per barrel) 15.09 16.17 18.20 21.10 22.86
- -------------------------------------------------------------------------------------------------------------
* Years 1991 and 1990 include results from Canadian operations that were sold
effective December 31, 1991.
46
47
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OTHER ENERGY OPERATIONS
Market Center
In October 1994, the Corporation opened a natural gas market center in
Pittsburgh, Pennsylvania. Managed by Columbia Energy Services Corporation
(CES), the market center offers a variety of natural gas supply services for
third parties as well as the Corporation's distribution and transmission
subsidiaries. These services respond to the changing needs of local utilities,
industrial consumers and others managing gas supply in the new environment
generated by Order 636.
In order to offer an additional energy service to its customers, the
Corporation intends to seek the necessary regulatory approvals in 1995 to
market electric power. This would allow the purchase of electric power from
electric utilities and cogeneration facilities which would then be sold to
other electric utilities as well as other customers.
Propane
During 1994, propane sales by Columbia Propane Corporation and Commonwealth
Propane, Inc., totaled 68.5 million gallons, an increase of 18 percent from the
previous year. The propane companies serve approximately 68,200 customers in
parts of Kentucky, Maryland, New York, North Carolina, Ohio, Pennsylvania,
Virginia and West Virginia. The companies are focusing their sales efforts on
the higher-margin residential segment.
Cogeneration
The Corporation is involved in several cogeneration projects through TriStar
Ventures Corporation (TriStar), a wholly-owned subsidiary. With the opening
of a 47-megawatt cogeneration facility in June 1994 in Vineland, New Jersey,
TriStar now holds various interests in four operating facilities with a total
capacity of nearly 300 megawatts. TriStar and its partners have other projects
in various stages of development. Value for the Corporation is also created
from the projects by increased throughput for the transmission subsidiaries and
for the oil and gas segment through additional sales opportunities.
Cove Point Facility
A partnership between Columbia LNG Corporation (Columbia LNG) and a
wholly-owned subsidiary of Potomac Electric Power Company was formed in October
1993. The partnership is pursuing a business plan to offer a peaking service
and to reactivate the Cove Point Terminal. On November 3, 1993, the
partnership filed an application with FERC to acquire all of the existing plant
and pipeline facilities owned by Columbia LNG, for authorization to
recommission the plant and construct liquefaction facilities and to charge
customers based upon negotiated market rates for the services.
By orders issued July 27, 1994, and September 28, 1994, the FERC determined
that the proposed peaking operation is in the public interest; however, the
proposal to charge customers market based rates was denied. The September 28,
1994 order, which directed the partnership to use cost of service based rates,
also contained certain rate base determinations which allowed only a portion of
Columbia LNG's current rate base to be used in the calculation of the cost
based rates. On December 5, 1994, the partnership's request for
reconsideration of the rate base issues was denied by the FERC.
On December 12, 1994, the FERC certificate to recommission the facility and
offer a peaking service was accepted by the partnership, and the Cove Point
Terminal and pipeline facilities were contributed by Columbia LNG to the
partnership as its initial capital contribution. It is anticipated that the
peaking service will be operational in the fall of 1995.
Derivatives
The Corporation's other energy operations minimize the risk of market
fluctuations by using commodity futures from time to time to hedge prices on
propane inventories and commitments for natural gas purchases and sales. These
agreements are not used for purposes of speculation.
47
48
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
CES uses commodity futures contracts to assure acceptable margins on the
purchase and resale of natural gas when it makes commitments for the purchase
or sale of natural gas in future months. When CES 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, Inc. (CPI) purchases propane and places it in inventory
for future sale. CPI sells commodity futures on a portion of its inventory at
the time of purchase to protect it from decreasing prices and to assure an
acceptable margin.
Environmental Matters
The Columbia Gas System Service Corporation (Service Corporation) received a
"General Notice of Potential Liability and Section 104(2) Request for
Information" from the EPA concerning a process site to which the Service
Corporation sent certain solvents. Service Corporation has joined a group for
the purpose of sharing the costs of the clean-up. Management does not believe
this Superfund matter will have a material adverse effect on future income or
on the Corporation's financial position.
Net Revenues
An increase in demand for services in the new environment generated by Order
636 resulted in $3.8 million higher net revenues for gas marketing activities
in 1994 and an increase of $1.7 million for 1993 over the year earlier. The
cold weather in the first quarter of 1994, which resulted in higher sales
volumes and margins, was primarily responsible for the $3 million increase in
1994 net revenues from propane operations. In 1993, these revenues increased
$0.8 million due to increased sales to higher-margin residential customers.
Other revenues decreased $3.8 million in 1994 as the Corporation's
reengineering program resulted in a decline in revenues for professional
services provided to affiliated companies. In 1993, other revenues increased
$3.1 million from the prior year to $73.4 million as revenues from affiliated
companies and coal royalties increased.
Operating Income
The $15.8 million increase in operating income in 1994 is primarily due to the
$12.8 million decrease in operating expenses reflecting the impact of the
reserve recorded in 1993 for employee severance costs and the related
efficiencies achieved in 1994. The 1993 operating income decline of $5.1
million was primarily due to the recording of the severance reserve.
48
49
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM OTHER ENERGY OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------
NET REVENUES
Gas marketing revenues $232.1 $176.5 $80.4
Less: Products purchased 225.3 173.5 79.1
- ---------------------------------------------------------------------------------------------------------------
Net Gas Marketing Revenues 6.8 3.0 1.3
- ---------------------------------------------------------------------------------------------------------------
Propane revenues 63.2 56.5 53.1
Less: Products purchased 33.4 29.7 27.1
- ---------------------------------------------------------------------------------------------------------------
Net Propane Revenues 29.8 26.8 26.0
- ---------------------------------------------------------------------------------------------------------------
Other revenues 69.6 73.4 70.3
- ---------------------------------------------------------------------------------------------------------------
Net Revenues 106.2 103.2 97.6
- ---------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 76.3 90.8 80.8
Depreciation and depletion 7.1 5.9 4.9
Other taxes 5.3 4.8 5.1
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 88.7 101.5 90.8
- ---------------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 17.5 $ 1.7 $ 6.8
- ---------------------------------------------------------------------------------------------------------------
OTHER ENERGY OPERATING HIGHLIGHTS
1994 1993 1992 1991 1990
- -------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 15.1 11.2 15.0 10.2 14.1
- -------------------------------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions) 68.5 58.1 63.3 70.5 74.4
Customers 68,218 67,895 65,899 64,618 63,546
- -------------------------------------------------------------------------------------------------------------
49
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- -------------------------------------------------------------------------------
Index Page
- -------------------------------------------------------------------------------
Comparative Gas Operations Data . . . . . . . . . . . . . . . . . . . . 51
Report of Independent Public Accountants . . . . . . . . . . . . . . . 52
Statements of Consolidated Income . . . . . . . . . . . . . . . . . . . 53
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . 54
Statements of Consolidated Cash Flows . . . . . . . . . . . . . . . . . 56
Statements of Consolidated Common Stock Equity . . . . . . . . . . . . 57
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . 58
Schedule II - Valuation and Qualifying Accounts . . . . . . . . . . . . 94
- -------------------------------------------------------------------------------
50
51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
COMPARATIVE GAS OPERATIONS DATA
The Columbia Gas System, Inc. and Subsidiaries
1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------------------------
SALES AND TRANSPORTATION
REVENUES ($ in millions)*
Residential 1,224.1 1,217.5 1,089.1 1,019.3 943.9
Commercial 464.0 466.5 426.5 402.4 370.2
Industrial 188.5 153.8 97.6 78.0 94.1
Wholesale 111.3 683.1 617.6 407.1 341.5
Other 28.7 45.2 51.5 48.1 51.5
Transportation 597.9 601.9 438.6 425.0 373.2
- ------------------------------------------------------------------------------------------------------------
Total Sales and Transportation Revenues 2,614.5 3,168.0 2,720.9 2,379.9 2,174.4
- ------------------------------------------------------------------------------------------------------------
SALES (Bcf)*
Residential 189.8 194.8 186.3 178.5 173.5
Commercial 80.8 83.5 81.9 78.4 76.8
Industrial 75.9 53.8 29.4 24.9 31.2
Wholesale 65.5 167.3 171.3 111.5 92.1
Other 13.1 25.3 30.6 33.7 28.3
- ------------------------------------------------------------------------------------------------------------
Total Sales 425.1 524.7 499.5 427.0 401.9
Transportation volumes 1,061.8 993.7 982.4 972.1 977.6
- ------------------------------------------------------------------------------------------------------------
Total Throughput 1,486.9 1,518.4 1,481.9 1,399.1 1,379.5
- ------------------------------------------------------------------------------------------------------------
SOURCES OF GAS SOLD (Bcf)
Total gas purchased 400.1 476.3 433.0 370.6 453.3
Total gas produced 66.8 71.5 69.2 76.3 75.3
Exchange gas - net (2.6) (11.2) 17.5 (15.3) 21.1
Gas withdrawn from (delivered to) storage (14.0) 17.9 14.5 24.7 (137.5)
Company use and other (25.2) (29.8) (34.7) (29.3) (10.3)
- ------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 425.1 524.7 499.5 427.0 401.9
- ------------------------------------------------------------------------------------------------------------
CUSTOMERS AT YEAR END
Residential 1,764,968 1,737,609 1,711,946 1,687,631 1,724,281
Commercial 167,067 164,037 161,937 160,420 165,144
Industrial 2,394 2,280 2,358 2,345 2,400
Wholesale 73 5 78 80 81
Other 140 143 217 200 142
- ------------------------------------------------------------------------------------------------------------
Total Customers at Year End 1,934,642 1,904,074 1,876,536 1,850,676 1,892,048
- ------------------------------------------------------------------------------------------------------------
AVERAGE USAGE PER CUSTOMER (Mcf)
Residential 107.5 112.1 108.8 105.8 100.6
Commercial 483.6 509.0 505.8 488.7 465.0
- ------------------------------------------------------------------------------------------------------------
DEGREE DAYS FOR RETAIL OPERATIONS 5,530 5,677 5,507 4,998 4,783
% Colder (warmer) than normal (1) 1 (2) (11) (15)
- ------------------------------------------------------------------------------------------------------------
*Certain amounts in prior periods have been reclassified to conform with the
current presentation.
51
52
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of The Columbia Gas System, Inc.:
We have audited the accompanying consolidated balance sheets of The Columbia
Gas System, Inc. (a Delaware corporation, the "Corporation") and subsidiaries
as of December 31, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
On July 31, 1991, the Corporation and Columbia Gas Transmission Corporation
("Columbia Transmission"), a wholly-owned subsidiary, filed separate petitions
seeking protection under Chapter 11 of the Federal Bankruptcy Code. Note 2
discusses, among other matters, uncertainties associated with the Chapter 11
proceedings, including the status of the Corporation's loans to Columbia
Transmission, certain prepetition intercompany asset transfers and the
measurement of certain liabilities. This note also discusses purported class
action and other complaints which have been filed against the Corporation
generally alleging violations of certain securities laws. The accompanying
financial statements do not reflect any liability associated with these
complaints as the Corporation believes it has meritorious defenses to these
actions; however, the ultimate outcome is uncertain. As a result of these
matters, the Corporation may take, or be required to take, actions which may
cause assets to be realized or liabilities to be liquidated for amounts other
than those reflected in the financial statements. These factors create
substantial doubt about the Corporation's ability to continue as a going
concern. The accompanying financial statements have been prepared assuming
that the Corporation and Columbia Transmission will continue as going concerns
which contemplate the realization of assets and payment of liabilities in the
ordinary course of business. The appropriateness of the Corporation continuing
to present financial statements on a going concern basis is dependent upon,
among other items, the terms of the ultimate plan of reorganization and the
ability to generate sufficient cash from operations and financing sources to
meet obligations.
As discussed in Note 5, effective January 1, 1994, the Corporation changed its
method of accounting for postemployment benefits pursuant to standards
promulgated by the Financial Accounting Standards Board.
The schedule listed in the Index to Item 8, Financial Statements and
Supplementary Data, is the responsibility of the Corporation's management and
is presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic consolidated financial
statements. This schedule has been subjected to the auditing procedures
applied in the audits of the basic consolidated financial statements and, in
our opinion, fairly states in all material respects the financial data required
to be set forth therein in relation to the basic consolidated financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
New York, New York
February 9, 1995
52
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31 (in millions except per share amounts) 1994* 1993* 1992*
- --------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Gas sales $2,016.6 $2,566.1 $2,282.3
Transportation 597.9 601.9 438.6
Other 218.9 223.2 201.1
- --------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,833.4 3,391.2 2,922.0
- --------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Products purchased 976.7 1,574.5 1,236.9
Operation 879.1 782.5 764.4
Maintenance 133.7 165.5 157.1
Depreciation and depletion 261.7 239.8 368.1
Other taxes 209.0 198.0 194.0
Other - 57.5 38.6
- --------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,460.2 3,017.8 2,759.1
- --------------------------------------------------------------------------------------------------------------
OPERATING INCOME 373.2 373.4 162.9
- --------------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
Interest income and other, net (Note 12) 46.1 7.3 20.5
Interest expense and related charges** (Note 13) (14.8) (101.5) (13.7)
Reorganization items, net (Note 2I) (12.3) 8.9 (8.3)
- --------------------------------------------------------------------------------------------------------------
Total Other Income (Deductions) 19.0 (85.3) (1.5)
- --------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES, EXTRAORDINARY
- --------------------------------------------------------------------------------------------------------------
ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 392.2 288.1 161.4
- --------------------------------------------------------------------------------------------------------------
Income taxes (Note 6) 146.0 135.9 70.5
- --------------------------------------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 246.2 152.2 90.9
Extraordinary item (Note 11E) - - (39.7)
Cumulative effect of change in accounting
for postemployment benefits (Note 5) (5.6) - -
- --------------------------------------------------------------------------------------------------------------
NET INCOME $ 240.6 $ 152.2 $ 51.2
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
(based on average shares outstanding)
Before extraordinary item and accounting change $ 4.87 $ 3.01 $ 1.79
Extraordinary item - - (0.78)
Change in accounting for postemployment benefits (0.11) - -
- --------------------------------------------------------------------------------------------------------------
Earnings on Common Stock $ 4.76 $ 3.01 $ 1.01
- --------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (thousands) 50,560 50,559 50,559
- --------------------------------------------------------------------------------------------------------------
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements.
**Due to the bankruptcy filings, estimated interest expense of approximately
$222 million, $207 million and $203 million has not been recorded for 1994,
1993 and 1992, respectively (see Note 2E of Notes to Consolidated Financial
Statements).
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
53
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS
The Columbia Gas System, Inc. and Subsidiaries
ASSETS as of December 31 (in millions) 1994* 1993*
- --------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant, at original cost $6,637.5 $6,329.8
Accumulated depreciation and depletion (3,180.8) (3,048.4)
- --------------------------------------------------------------------------------------------------------------
3,456.7 3,281.4
- --------------------------------------------------------------------------------------------------------------
Oil and gas producing properties, full cost method 1,261.9 1,208.7
Accumulated depletion (637.6) (600.0)
- --------------------------------------------------------------------------------------------------------------
624.3 608.7
- --------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment 4,081.0 3,890.1
- --------------------------------------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
Accounts receivable - noncurrent 205.2 218.9
Unconsolidated affiliates 80.7 67.7
Other 20.5 38.6
- --------------------------------------------------------------------------------------------------------------
Total Investments and Other Assets 306.4 325.2
- --------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 1,481.8 1,340.4
Accounts receivable
Customers (less allowance for doubtful accounts
of $11.6 and $11.8, respectively) 425.5 588.7
Other 135.9 132.7
Gas inventory 230.3 197.8
Other inventories - at average cost 42.0 40.1
Prepayments 134.2 124.6
Other 35.4 63.0
- --------------------------------------------------------------------------------------------------------------
Total Current Assets 2,485.1 2,487.3
- --------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES 292.4 255.3
- --------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $7,164.9 $6,957.9
- --------------------------------------------------------------------------------------------------------------
* Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements.
** The Corporation has 10,000,000 shares of preferred stock, $50 par value,
authorized but unissued.
*** Due to the bankruptcy filings, estimated accrued interest of approximately
$716 million and $494 million has not been recorded as of December 31,
1994 and December 31, 1993, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
54
55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CAPITALIZATION AND LIABILITIES as of December 31 (in millions) 1994* 1993*
- --------------------------------------------------------------------------------------------------------------
COMMON STOCK EQUITY
Common stock, par value $10 per share - outstanding 50,563,335
and 50,559,225 shares, respectively $505.6 $ 505.6
Additional paid in capital 601.9 601.8
Retained earnings 430.5 189.9
Unearned employee compensation (70.0) (70.0)
- --------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 1,468.0 1,227.3
LONG-TERM DEBT 4.3 4.8
- --------------------------------------------------------------------------------------------------------------
Total Capitalization** 1,472.3 1,232.1
- --------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Debt obligations 1.2 1.3
Accounts and drafts payable 153.2 184.4
Accrued taxes 175.2 129.5
Estimated rate refunds 92.2 245.4
Estimated supplier obligations 69.7 146.3
Overrecovered gas costs 59.5 1.8
Transportation and exchange gas payable 35.1 66.8
Other*** 273.8 285.9
- --------------------------------------------------------------------------------------------------------------
Total Current Liabilities 859.9 1,061.4
- --------------------------------------------------------------------------------------------------------------
LIABILITIES SUBJECT TO CHAPTER 11 PROCEEDINGS (Note 2B) 3,988.9 3,927.8
- --------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Deferred income taxes - noncurrent 344.1 253.8
Investment tax credits 38.6 40.0
Postretirement benefits other than pensions 236.3 230.0
Other 224.8 212.8
- --------------------------------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits 843.8 736.6
- --------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2, 3, and 11) - -
- --------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $7,164.9 $6,957.9
- --------------------------------------------------------------------------------------------------------------
55
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31 (in millions) 1994* 1993* 1992*
- --------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $240.6 $152.2 $ 51.2
Adjustments for items not requiring (providing) cash:
Depreciation and depletion 261.7 239.8 368.1
Deferred income taxes 72.2 19.1 (30.3)
Amortization of prepayments for producer
contract modifications - 19.3 23.9
Extraordinary item - - 39.7
Change in accounting for postemployment benefits 5.6 - -
Other - net (25.0) 220.5 233.0
Changes in components of working capital:
Accounts receivable 135.9 (1.4) (87.0)
Gas inventory (32.5) 115.7 71.2
Accounts payable (35.5) (59.3) 31.3
Accrued taxes 45.7 5.5 8.3
Estimated rate refunds (133.3) (59.4) 91.5
Estimated supplier obligations (49.7) 131.2 (3.9)
Other working capital 87.1 67.2 (31.6)
- --------------------------------------------------------------------------------------------------------------
Net Cash From Operations 572.8 850.4 765.4
- --------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
Capital expenditures** (433.6) (345.7) (294.5)
Other investments - net (1.3) 3.9 75.4
- --------------------------------------------------------------------------------------------------------------
Net Investment Activities (434.9) (341.8) (219.1)
- --------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Retirement of long-term debt (0.9) (0.8) (2.4)
Increase in short-term debt and other
financing activities 4.4 12.0 4.4
Net debtor-in-possession financing - - (136.0)
- --------------------------------------------------------------------------------------------------------------
Net Financing Activities 3.5 11.2 (134.0)
- --------------------------------------------------------------------------------------------------------------
Increase in cash and temporary cash
investments 141.4 519.8 412.3
Cash and temporary cash investments
at beginning of year 1,340.4 820.6 408.3
- --------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments
at end of year*** $ 1,481.8 $ 1,340.4 $ 820.6
- --------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest 0.8 0.5 1.4
Cash paid for income taxes (net of refunds) 37.4 88.7 120.4
- --------------------------------------------------------------------------------------------------------------
* Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements.
** Includes amounts transferred from cash paid to employees and for other
employee benefits and other operating cash payments.
*** The Corporation considers all highly liquid debt instruments to be cash
equivalents.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
56
57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
The Columbia Gas System, Inc. and Subsidiaries
Common Stock*
--------------------------- Additional Unearned
(In millions except Shares Par Paid In Retained Employee
for share amounts) Outstanding(000) Value Capital Earnings Compensation
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1991 50,559 $505.6 $601.8 $(13.5) $(87.0)
Net Income 51.2
Sale of LESOP shares 17.0
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1992 50,559 505.6 601.8 37.7 (70.0)
Net Income 152.2
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1993 50,559 505.6 601.8 189.9 (70.0)
Net Income 240.6
Common stock issued:
Long-Term Incentive Plan 4 0.1
- -------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1994 50,563 $505.6 $601.9 $430.5 $(70.0)
- -------------------------------------------------------------------------------------------------------------------
*100 million shares authorized at December 31, 1994, 1993 and 1992 - $10 par
value.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
57
58
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 Corporation and all subsidiaries. All
intercompany accounts and transactions have been eliminated, except
for the Corporation's investment in Columbia LNG Corporation which was
presented as a one line equity investment in 1993(see Note 11E).
On July 31, 1991, the Corporation and its wholly-owned subsidiary,
Columbia Gas Transmission Corporation (Columbia Transmission), filed
separate petitions seeking protection under Chapter 11 of the Federal
Bankruptcy Code. The debtor companies are operating their businesses
as debtors-in-possession (DIP) under the jurisdiction of the United
States Bankruptcy Court for the District of Delaware (Bankruptcy
Court). As such, the debtor companies cannot engage in transactions
outside the ordinary course of business without obtaining Bankruptcy
Court approval (see Note 2).
The accompanying financial statements reflect all adjustments
necessary in the opinion of management to present fairly the results
of operations in accordance with generally accepted accounting
principles applicable to a going concern. Such presentation
contemplates the realization of assets and payment of liabilities in
the ordinary course of business. As a result of the reorganization
proceedings under Chapter 11, the debtor companies may take, or be
required to take, actions which may cause assets to be realized, or
liabilities to be liquidated, for amounts other than those reflected
in the financial statements. The appropriateness of continuing to
present consolidated financial statemetns on a going concern basis is
dependent upon, among other things, the terms of the plan of
reorganization, future profitable operations and the ability to
generate sufficient cash from operations and financing sources to meet
obligations. The consolidated financial statements do not include any
adjustments relating to the recoverability and classification of
recorded asset amounts, or the amounts and classification of
liabilities that might be necessary as a result of the outcome of the
uncertainties discussed herein.
Certain reclassifications have been made to the 1993 and 1992
financial statements to conform to the 1994 presentation.
B. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation," 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. The Corporation's interstate transmission
companies and Columbia LNG Corporation (Columbia LNG) did not meet
these criteria, and consequently are not applying the provisions of
SFAS No. 71. The Corporation's gas distribution subsidiaries continue
to follow the accounting and reporting requirements of SFAS No. 71.
Certain expenses and credits subject to utility regulation or rate
determination normally reflected in income are deferred on the balance
sheet and are recognized in income as the related amounts are included
in service rates and recovered from or refunded to customers.
Condensed information for assets and liabilities subject to utility
regulation and rate determination are as follows:
58
59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
At December 31 ($ in millions) 1994 1993
--------------------------------------------------------------------------------
ASSETS
Postemployment and postretirement benefits 146.2 138.1
Unrecovered gas costs 8.2 55.8
Regulatory effects of accounting for income taxes, net 25.3 27.3
Other 54.8 24.6
--------------------------------------------------------------------------------
Total 234.5 245.8
--------------------------------------------------------------------------------
LIABILITIES
Rate refunds and reserves 80.1 63.5
Over recovered gas costs 60.3 1.9
--------------------------------------------------------------------------------
Total 140.4 65.4
--------------------------------------------------------------------------------
C. 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 distribution companies
includes an allowance for funds used during construction (AFUDC).
In addition, Columbia Gas of Ohio, Inc. is permitted to include in its
plant investment post-in-service carrying charges on those eligible
plant investments which are placed in service between December 31,
1990, and December 31, 1994. Columbia Gas of Ohio, Inc., is
currently recovering plant investment post-in-service carrying charges
for 1991, 1992 and 1993 in rates. Subject to commission approval, the
carrying charges are also authorized to be included in base rates in
subsequent rate filings. These carrying charges are subject to a net
income limitation, as determined by the commission. Property, plant
and equipment of other subsidiaries includes interest during
construction (IDC).
The 1994, 1993 and 1992 before-tax rates for AFUDC and IDC were 8.0
percent and 9.6 percent, respectively. They represent the rates in
effect prior to Chapter 11 filings. The portion of interest
capitalized by subsidiaries during the period the Corporation is in
bankruptcy is eliminated in the consolidated financial statements.
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. The Corporation's subsidiaries
provide for annual depreciation on a composite straight-line basis.
The average annual depreciation rate for Transmission property was 2.7
percent in 1994 and 2.6 percent in 1993 and 1992. The average annual
depreciation rate for Distribution property was 3.3 percent in 1994,
1993 and 1992.
D. OIL AND GAS PRODUCING PROPERTIES. The Corporation's subsidiaries
engaged in exploring for and developing oil and gas reserves follow
the full cost method of accounting. Under this method of accounting,
all productive and nonproductive costs directly identified with
acquisition, exploration and development activities including certain
payroll and other internal costs are capitalized in a countrywide cost
center. If costs exceed the sum of the estimated present value of the
cost center's net future oil and gas revenues and the lower of cost or
estimated value of unproved properties, an amount equivalent to the
excess is charged to current depletion expense. Gains or losses on
the sale or other disposition of oil and gas properties are normally
recorded as adjustments to capitalized costs.
59
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Depletion for subsidiaries is based upon the ratio of current-year
revenues to expected total revenues, utilizing current prices, over
the life of production.
E. 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 as unexercised. 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. Realized gains and losses
from the settlement of propane futures contracts are included in
products purchased.
F. GAS INVENTORY. Gas inventory is carried at cost on a last-in,
first-out (LIFO) basis. The current replacement cost of gas inventory
at December 31, 1994, was approximately $212 million for the
distribution companies. Liquidation of LIFO layers related to gas
delivered by the distribution companies does not affect income since
the effect is passed through to customers as part of purchased gas
adjustment tariffs.
G. INCOME TAXES AND INVESTMENT TAX CREDITS. The Corporation 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 gas distribution
subsidiaries were deferred and are being amortized over the life of
the related properties to conform with regulatory policy.
H. ESTIMATED RATE REFUNDS. Certain rate-regulated subsidiaries collect
revenues subject to refund pending final determination in rate
proceedings. In connection with such revenues, estimated rate refund
liabilities are recorded which reflect management's current judgment
of the ultimate outcome of the proceedings. No provisions are made
when, in the opinion of management, the facts and circumstances
preclude a reasonable estimate of the outcome.
I. DEFERRED GAS PURCHASE COSTS. The Corporation'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.
J. REVENUE RECOGNITION. The Corporation'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. Columbia
Transmission also records the impact on revenues of the future
recovery or refund of differences between current transportation costs
and amounts currently included in the billed rates. In addition,
Columbia Transmission and Columbia Gulf record the effect on revenues
to reflect the recovery or refund of differences between current fuel
usage and amounts retained.
2. REORGANIZATION PROCEEDINGS UNDER CHAPTER 11 OF THE BANKRUPTCY CODE
A. GENERAL. Under the Bankruptcy Code, actions by creditors to collect
prepetition indebtedness are stayed and other contractual obligations
may not be enforced against either the Corporation or Columbia
Transmission. As debtors-in-possession, both the Corporation and
Columbia Transmission have the right, subject to Bankruptcy Court
approval and certain other limitations, to assume or reject executory
contracts and unexpired leases. In this context, "rejection" means
that the debtor companies are relieved of their obligations to
perform further under the contract or lease but are subject to a claim
for damages for the breach thereof. Any claims for damages resulting
from rejection are treated as general unsecured claims in the
reorganization. The parties affected by these rejections may file
claims with the Bankruptcy Court
60
61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
in accordance with bankruptcy procedures. Prepetition claims which
were contingent or unliquidated at the commencement of the Chapter 11
proceeding are generally allowable against the debtor-in-possession in
amounts fixed by the Bankruptcy Court. Substantially all liabilities
as of the petition date are subject to resolution under plans of
reorganization to be approved by the Bankruptcy Court after
submission to any required vote by affected parties. The
Corporation's reorganization plan will also require approval by the
Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935.
B. PREPETITION OBLIGATIONS. Columbia Transmission's prepetition
obligations include secured and unsecured debt payable to the
Corporation, estimated supplier obligations, estimated rate refunds,
accrued taxes and other trade payables and liabilities. Prepetition
obligations of the Corporation primarily represent debentures, bank
loans and commercial paper outstanding on the filing date together
with accrued interest to that date. A substantial amount of Columbia
Transmission's liabilities subject to Chapter 11 proceedings relate to
amounts owed to the Corporation. Columbia Transmission's borrowings
have been funded by the Corporation on a secured basis since June 1985
and are secured by mortgages and a cash collateral order approved by
the Bankruptcy Court. On the petition date, the principal amount of
the First Mortgage Bonds outstanding was $930.4 million. A secured
inventory financing agreement of $410 million was also outstanding on
the petition date. Prepetition and postpetition interest on secured
debt owed by Columbia Transmission to the Corporation is $488.3
million at December 31, 1994. In addition to these secured claims,
the Corporation has an unsecured claim against Columbia Transmission
of $351 million in installment notes issued prior to 1985 and accrued
interest to the petition date.
61
62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The accompanying Consolidated Balance Sheets include approximately $4
billion of liabilities subject to the Chapter 11 proceedings of the
Corporation and Columbia Transmission as follows:
($ in millions) 1994 1993
----------------------------------------------------------------------------------------------------------------
CORPORATION
Debentures:
6 1/4% Series due October 1991 12.0 12.0
6 5/8% Series due October 1992 7.4 7.4
7 1/4% Series due May 1993 15.0 15.0
9% Series due August 1993 150.0 150.0
7% Series due October 1993 12.0 12.0
9% Series due October 1994 20.2 20.2
8 3/4% Series due April 1995 16.2 16.2
9 1/8% Series due October 1995 22.0 22.0
10 1/8% Series due November 1995 18.6 18.6
8 3/8% Series due March 1996 32.9 32.9
9 1/8% Series due May 1996 18.6 18.6
8 1/4% Series due September 1996 26.4 26.4
7 1/2% Series due March 1997 23.3 23.3
7 1/2% Series due June 1997 26.3 26.3
7 1/2% Series due October 1997 28.4 28.4
7 1/2% Series due May 1998 23.7 23.7
10 1/4% Series due May 1999 25.0 25.0
9 7/8% Series due June 1999 21.8 21.8
10 1/4% Series due August 2011 100.0 100.0
10 1/2% Series due June 2012 200.0 200.0
10 3/20% Series due November 2013 100.0 100.0
9 1/5% to 9 1/2% Series A Medium-Term Notes due 1998 through 2019 200.0 200.0
8 19/20% to 9 49/50% Series B Medium-Term Notes due 1998 through 2020 200.0 200.0
9 11/20% to 9 37/50% Series C Medium-Term Notes due 2000 through 2020 50.0 50.0
----------------------------------------------------------------------------------------------------------------
1,349.8 1,349.8
Unamortized debt discount, less premium (7.2) (7.2)
----------------------------------------------------------------------------------------------------------------
1,342.6 1,342.6
Subordinated Guarantee of Leveraged Employee Stock
Ownership Plan debt 87.0 87.0
Short-Term debt:
Commercial Paper 266.5 266.5
Bank Loans 621.0 621.0
----------------------------------------------------------------------------------------------------------------
Prepetition debt obligations 2,317.1 2,317.1
Other 65.4 65.1
----------------------------------------------------------------------------------------------------------------
Total 2,382.5 2,382.2
----------------------------------------------------------------------------------------------------------------
Less amounts payable to affiliates 5.2 4.9
----------------------------------------------------------------------------------------------------------------
TOTAL CORPORATION 2,377.3 2,377.3
----------------------------------------------------------------------------------------------------------------
COLUMBIA TRANSMISSION
Secured debt obligations 1,828.7 1,686.8
Unsecured debt obligations 351.2 351.2
Payables to other affiliates 70.8 70.0
Estimated supplier obligations 1,300.5 1,251.8
Estimated rate refunds 82.3 60.4
Taxes 93.6 89.3
Other 135.2 139.9
----------------------------------------------------------------------------------------------------------------
Total 3,862.3 3,649.4
----------------------------------------------------------------------------------------------------------------
Less amounts payable to affiliates 2,250.7 2,098.9
----------------------------------------------------------------------------------------------------------------
TOTAL COLUMBIA TRANSMISSION 1,611.6 1,550.5
----------------------------------------------------------------------------------------------------------------
TOTAL 3,988.9 3,927.8
----------------------------------------------------------------------------------------------------------------
62
63
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
INTERCOMPANY COMPLAINT
On March 19, 1992, the Official Committee of Unsecured Creditors of
Columbia Transmission (Columbia Transmission Creditors' Committee) filed
a complaint (Intercompany Complaint) with the Bankruptcy Court alleging
that the $1.7 billion of Columbia Transmission's secured and unsecured
debt securities held by the Corporation should be recharacterized as
capital contributions (rather than loans) and equitably subordinated to
the claims of Columbia Transmission's other creditors. The Intercompany
Complaint also challenges interest and dividend payments made by Columbia
Transmission to the Corporation of approximately $500 million for the
period from 1988 to the petition date and the 1990 property transfer from
Columbia Transmission to Columbia Natural Resources, Inc. (CNR) as an
alleged fraudulent transfer. Based on the SEC standardized measurement
procedures, CNR's properties had a reserve value of approximately $250
million as of December 31, 1994, a significant portion of which is
attributable to the transfer from Columbia Transmission. At the
Bankruptcy Court's request, the trial proceedings for the Intercompany
Complaint were transferred to the U. S. District Court for the District
of Delaware (the District Court). On September 12, 1994, the trial for
the Intercompany Complaint began in the District Court and concluded on
October 25, 1994. Post trial briefs were filed in December 1994, and the
District Court is expected to render a decision in the first quarter of
1995. Management believes that the Intercompany Complaint is without
merit; however, the ultimate outcome of these issues is uncertain at this
stage of the proceedings.
Little progress has been made with Columbia Transmission's creditors in
an attempt to establish the value of the estate and to resolve the
matters raised in the Intercompany Complaint. Since the validity of the
Corporation's debt investment in Columbia Transmission is crucial to the
determination of the value of the Corporation's estate, the Corporation's
reorganization could be affected by the ultimate outcome of the
Intercompany Complaint.
PRODUCER CLAIMS ESTIMATION PROCESS
Columbia Transmission has recorded liabilities of approximately $1.3
billion to reflect the estimated effects of rejecting its above- market
producer contracts and estimated producer obligations associated with
pricing disputes and take-or-pay obligations for historical periods.
With Bankruptcy Court approval, Columbia Transmission rejected more than
4,800 above-market gas purchase contracts with producers. The producers
whose gas purchase contracts were rejected filed claims for damages that,
after being adjusted for duplicative and other erroneous claims, are in
excess of $13 billion. The Bankruptcy Court approved the appointment of
a claims mediator in 1992 to implement a claims estimation procedure
related to the rejected above-market producer contracts and other
producer claims. On October 13, 1994, the claims mediator issued his
Initial Report and Recommendation of the Claims Mediator on Generic
Issues for Natural Gas Contract Claims (Report). The Report, which is
subject to Bankruptcy Court review and approval, establishes the
parameters within which producers must initially recalculate their
contract rejection and take-or-pay claims. The recalculated claims will
then be subject to challenge and audit and adjustment based upon claim
specific issues. The Report generally validates the assumptions Columbia
Transmission used earlier to estimate the total value of contract
rejection claims filed by producers in the bankruptcy proceedings and
clearly rules out most of the methods the producers utilized to derive
grossly excessive, and legally improper amounts in their original claims.
While the Report uses a lower discount rate than that used by Columbia
Transmission and recognizes certain proved undeveloped reserves, it
directs that calculations of damages be based only on the amount by which
a contract price exceeds a mitigation price and be discounted to a
present value as of the petition date. Not addressed in the Report are
numerous contract specific issues that ultimately will be used in the
estimation procedure to determine the allowable level of producer claims.
Columbia Transmission is not able to calculate individual contract
rejection claims at this time because it does not have adequate data from
the producers on the proved undeveloped reserves or on planned gas
development projects. This data will not become available, and subject
to challenge and audit, until the individual producers file their
recalculations.
63
64
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The Report does not address an alternative method for calculating
contract rejection damages sponsored by Columbia Transmission. This
methodology contemplates using the market value of the producers'
reserves subject to the contracts rejected by Columbia Transmission as
evidence of the economic value to producers of such contracts (Market
Value Methodology). The claims mediator is expected to hold a hearing on
this alternative methodology in the second quarter of 1995 and has
indicated that Columbia Transmission's pursuit of its Market Value
Methodology will not delay his completion of the discounted cash flow
methodology contained in the Report.
In management's opinion the $1.3 billion estimate previously reported
represents the worst plausible case for allowed contract rejection
claims, although it is anticipated that the producers' initial
recalculations of these claims may exceed that total. Further, Columbia
Transmission does not believe the Report produces any basis which would
cause it to change the amount it previously recorded for contract
rejection costs (approximately one billion dollars) given the information
currently available to it. However, following the review of the Report
by Columbia Transmission and its counsel, Columbia Transmission increased
the $200 million reserve for take-or-pay and other miscellaneous producer
claims by approximately $55 million in the third quarter of 1994. The
$55 million reserve addition is composed of approximately $40 million for
disallowance of recovery of recoupable take-or-pay proposed by the Report
and approximately $15 million of additional prepetition interest on
certain claims.
The resolution of bankruptcy related issues could significantly influence
future reported financial results. Accounting standards require that as
claim amounts are allowed by the Bankruptcy Court, the full amount of the
allowed claim must be recorded. This could result in liabilities being
recorded which bear little relationship to the amounts ultimately
required to be paid in settlement of those claims and could conceivably
exceed the Corporation's total investment in Columbia Transmission. Any
such distortion would not be corrected until final plans of
reorganization are approved for the Corporation and Columbia
Transmission.
UPSTREAM PIPELINE CLAIMS FOR TRANSPORTATION CONTRACTS
Columbia Transmission has transportation contracts with certain pipeline
companies that historically have been used to deliver gas to Columbia
Transmission. With regard to claims made against Columbia Transmission
by some of these pipelines in the bankruptcy proceedings, Columbia
Transmission has reached settlements that will provide for the assumption
of certain contracts, the termination of certain other contracts that are
no longer necessary for Columbia Transmission's operations, or the
substantial reduction of the transportation contracts. As a result,
approximately $463 million of claims filed by pipelines against Columbia
Transmission will be withdrawn when the settlements receive Bankruptcy
Court and regulatory approvals. The estimated cost of settlements
include projected exit fee payments of $105 million including amounts
already paid to certain pipelines through December 1994. Those
settlements with exit fees are conditioned upon Columbia Transmission's
recovery of the exit fees through rates.
INTERNAL REVENUE SERVICE MATTERS
The Internal Revenue Service (IRS) filed identical claims of $553.7
million against both debtor companies and the consolidated Columbia Gas
System for tax deficiencies, interest and penalties for the years
1983-1990. Negotiations with IRS representatives have resulted in a
settlement on all of the issues included in the IRS claims. The
settlement was approved by the Joint Committee on Taxation of the U. S.
Congress on June 30, 1994, and the Bankruptcy Court on October 12, 1994.
The settlement reduced the original claim to approximately $112 million.
The final cost of the settlement is expected to be about $46 million
after taking into consideration certain tax deductions that become
available in subsequent years. The impact of the settlement was recorded
in 1993.
The IRS is currently conducting an audit of the 1991-1992 tax years. As
part of this audit the Corporation has received a proposed notice of
disallowance for its tax deduction of interest expense during this
period. The issue concerns only the timing of the interest deduction and
not the deductibility of interest expense. Over the next several months
the Corporation will present evidence to IRS representatives supporting
this
64
65
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
deduction. If necessary, the Corporation will pursue this issue through
the IRS appeals process or the Bankruptcy Court. If the Corporation
cannot sustain the deduction in the years taken, interest expense on the
tax deficiency could be due to the IRS with an after-tax impact of
approximately $10 million at December 31, 1994.
RETIREMENT PLAN CLAIM
The Pension Benefit Guaranty Corporation (PBGC) filed claims of $150
million against both the Corporation and Columbia Transmission alleging
that if the retirement plan had been terminated by March 31, 1992, it
would have been underfunded. Management believes that the claims made by
the PBGC are inappropriate and in error since the Bankruptcy Court has
approved continued operation of the retirement plan, required annual
contributions are being made, there is no intention to terminate the plan
and the plan is not underfunded. Management further believes that the
PBGC's claim can be resolved without any financial consequences to the
Corporation or Columbia Transmission. On January 29, 1993, the PBGC
confirmed that while it remains confident that issues regarding its
claims can be resolved by mutual agreement, the PBGC has decided not to
proceed further with settlement negotiations regarding withdrawal of its
claims at the present time due to the uncertainties associated with the
bankruptcy proceedings. At December 31, 1994, the date of the latest
actuarial valuation, plan assets exceeded the accumulated benefit
obligations by $219.4 million.
C. PLANS OF REORGANIZATION. On January 18, 1994, Columbia Transmission
with the Corporation as co-sponsor, filed a reorganization plan (plan)
and a disclosure statement for consideration by its creditors and other
interested parties. The plan provided that Columbia Transmission would
remain a wholly-owned subsidiary of the Corporation, continue to offer an
array of competitive transportation and storage services, and retain
ownership of its 19,000-mile pipeline network and related facilities.
Subsequent to the filing of the plan, Columbia Transmission had
discussions directly with gas producers who have substantial claims
against it. Despite months of negotiations and numerous offers of
settlement, Columbia Transmission has been unable to reach agreement on a
consensual reorganization plan with the Columbia Transmission Creditors'
Committee. However, Columbia Transmission has had recent discussions, on
an individual basis, with a significant number of its largest producer
claimants, but it is impossible to determine at this time if these
discussions will lead to agreements on the claims.
The Corporation's and Columbia Transmission's exclusive rights to file
plans of reorganization expire April 18, 1995. Prior to that date, the
Corporation intends to file its reorganization plan with the Bankruptcy
Court and to cosponsor amendments to the reorganization plan that
Columbia Transmission filed in January 1994.
Both plans will be subject to review and approval requirements (including
authorizations from the SEC) which may require several months to
complete.
Implementation of reorganization plans for Columbia Transmission and the
Corporation, and the levels and timing of distributions to their
creditors, are subject to a number of risk factors which could materially
impact their outcome. Both companies anticipate emerging from bankruptcy
at the same time. The provisions of the reorganization plans of either
Columbia Transmission or the Corporation that are ultimately implemented
could be materially different from the filed plans.
D. PAYMENT OF DIVIDENDS AND DEBT SERVICE. The Corporation's Board of
Directors suspended the payment of dividends on the Corporation's common
stock on June 19, 1991. The Corporation also discontinued payments
related to debt service. Columbia Transmission suspended dividend,
interest and debt payments to the Corporation. The Corporation and
Columbia Transmission have also suspended the payment of most other
prepetition obligations. Management cannot predict at this time when or
whether any financial restructuring plans will be approved or what
provisions, if any, such plans would contain as related to the resumption
of dividends, debt service and other payments.
E. INTEREST EXPENSE. Interest expense of the Corporation has not been
accrued since the bankruptcy filing, but a calculation of interest is
included in a footnote on the Statements of Consolidated Income and
Consolidated Balance Sheets. Such interest has been calculated based on
an interpretation of the contractual
65
66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
arrangements which govern the various debt instruments the Corporation
has outstanding exclusive of any redemption premiums. In 1993, the
Official Committee of Unsecured Creditors of the Corporation asserted
claims for interest which exceed disclosed amounts by approximately $40
million. There are several factors to be considered in making these
calculations that are subject to uncertainty as to their ultimate outcome
in the bankruptcy proceeding, including the interest rates and method of
calculation to be applied to overdue payments of principal and interest.
In addition, the committee has asserted that approximately $110 million
of redemption premiums should be paid on the high cost debt instruments
to compensate investors for anticipated lower interest rates when the
debt is refinanced. Amounts disclosed as committee assertions reflect,
in part, interest rate markets in late 1993. Resolution of these issues
will be dependent upon, among other items, interest rates and market
conditions at the time of emergence from bankruptcy.
A favorable District Court decision in the Intercompany Complaint
litigation could result in interest expense being recorded for parent
company prepetition debt obligations prior to emergence from Chapter 11.
F. SECURITY HOLDER LITIGATION. After the announcement on June 19, 1991,
regarding the Corporation's probable charge to second quarter earnings
and the suspension of its dividend, 17 complaints including purported
class actions were filed against the Corporation and its directors and
certain officers of the debtor companies in the District Court. The
actions, which generally allege violations of certain anti-fraud
provisions of the Securities Act of 1933 and the Securities Exchange Act
of 1934, have been consolidated. On October 31, 1994, the class action
plaintiffs filed an amended and consolidated complaint against the
non-debtor defendants in the District Court essentially alleging the same
causes of action as the previously filed complaints. In addition, these
plaintiffs filed a motion for class certification in both the Bankruptcy
Court and the District Court. The plaintiffs also filed a motion seeking
to withdraw the litigation against the Corporation from the Bankruptcy
Court to the District Court. On November 1, 1994, the Corporation filed
a motion that seeks to require the individual class action plaintiffs to
file supplementary information with respect to their previously-filed
proofs of claims. Any person not responding would be barred from
asserting their claims pursuant to such procedures. In an order dated
November 30, 1994, the District Court stayed both the District Court and
Bankruptcy Court litigation until a final judgment is entered in the
Intercompany Complaint litigation.
On February 13, 1995, the Corporation, in order to promptly address the
securities claims in its plan of reorganization, requested the District
Court to modify the stay order by considering the Corporation's motion to
supplement class proofs of claims. The plaintiffs have objected to this
modification.
Also in 1991, three derivative actions were filed in the Court of
Chancery in and for New Castle County (Delaware) alleging that directors
breached their fiduciary duties. These suits have been stayed by either
the Bankruptcy Court filing or by stipulation of the parties.
While the Corporation and its officers and directors believe that they
have meritorious defenses to these actions, the outcome is uncertain at
this time.
G. CUSTOMER RECOUPMENT RIGHTS. During 1993, several customers of Columbia
Transmission filed motions with the Bankruptcy Court, seeking authority
to exercise alleged recoupment and setoff rights that are disputed by
Columbia Transmission. In their motion the customers seek to be
permitted to reduce amounts owed to Columbia Transmission for current
services against refunds owed to the customers by Columbia Transmission,
including amounts which were not otherwise payable in full under the July
1993 Third Circuit decision discussed below. This would include all
customer refunds under the 1990 rate case settlement and miscellaneous
refunds not otherwise payable in full to them. Columbia Transmission
estimates these refund claims to be approximately $216 million; however,
the amount is subject to change as customers quantify their filed claims.
The claims associated with the Baltimore Gas & Electric v. FERC
litigation (described below) is included in the recoupment and setoff
motions filed by the customers.
On October 20, 1993, the Bankruptcy Court approved an interim settlement
under which customers continued to pay Columbia Transmission for
FERC-authorized services at authorized rates, and Columbia Transmission
has agreed to grant these customers a priority claim to the extent the
Bankruptcy Court finds
66
67
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
them entitled to recoupment rights. In January 1994, the Bankruptcy
Court issued a procedural order whereby other customers were permitted to
file recoupment and setoff motions by February 18, 1994. Customers,
Columbia Transmission and other interested parties have filed summary
judgment motions and responses on these issues, and this matter is
currently pending before the Bankruptcy Court.
H. CUSTOMER REFUNDS. Total customer claims in Columbia Transmission's
bankruptcy proceedings relating to, or arising from, Columbia
Transmission's contracts with its customers for sales, transportation,
gas storage and similar services and other miscellaneous claims represent
about 450 claims for a total filed amount of approximately $550 million,
plus a potentially substantial sum filed as undetermined. While a
significant portion of these filed claims has been resolved, the claims
filed as undetermined still remain to be resolved.
In March 1994, the Bankruptcy Court granted Columbia Transmission's
Motion to partially implement the Third Circuit's refund decision
directing the pass-through of certain refunds. The decision stated that
refunds Columbia Transmission received from upstream pipelines, as well
as the Gas Research Institute (GRI) surcharge payments it collected from
customers are held in trust by Columbia Transmission, for those customers
and the GRI and are not part of Columbia Transmission's estate. Under
the Third Circuit ruling, approximately $173 million in refunds that
Columbia Transmission has received, or expects to receive postpetition
from upstream pipelines and GRI surcharges collected, should be passed
through to the customers and to the GRI. However, the Third Circuit
determined that $35 million in upstream pipeline refunds and GRI
surcharges, which Columbia Transmission collected prior to filing Chapter
11 while received in trust, were subject to the "lowest intermediate cash
balance test" (the amount remaining in trust at the time of bankruptcy)
and should be distributed on a pro rata basis to the customers and to the
GRI to the extent of Columbia Transmission's $3.3 million cash balance on
July 31, 1991. The Third Circuit affirmed another part of the U.S.
District Court's decision and held that approximately $16 million that
Columbia Transmission owes upstream suppliers, for gas purchased and
transportation services received prior to its bankruptcy filing, is
ordinary unsecured debt which must be discharged in the bankruptcy
process.
In April 1994, Columbia Transmission issued refunds of approximately $139
million to its customers, pursuant to the Third Circuit decision, for
settlement of a portion of their claims. The majority of these refunds
were for pass-through refunds of FERC Order Nos. 500 and 528 (Order
500/528) take-or-pay and related charges received from upstream pipelines
that Columbia Transmission had previously paid and then collected from
its customers.
A significant portion of the customer claims is attributable to the
Baltimore Gas & Electric Co. v. FERC litigation, in which various
Columbia Transmission customers and others challenged Columbia
Transmission's right to recover Order 500/528 direct charges that were
billed to Columbia Transmission by former upstream pipeline suppliers.
Such charges are estimated to be approximately $125 million (principal).
Interest through the July 31, 1991 petition date would be approximately
$40 million. In June 1994, the U.S. Court of Appeals for the District of
Columbia Circuit (D.C. Circuit Court) ruled that Columbia Transmission's
1985 Purchased Gas Adjustment (PGA) Settlement bars the recovery of some
portion of such costs and ordered the FERC to investigate the pipeline
charges in question and to disallow the recovery of amounts attributable
to Columbia Transmission's gas purchasing practices prior to April 1,
1987. In September 1994, Columbia Transmission filed a motion with the
FERC asking that it set procedures and hold a hearing to address issues
raised by the court's decision. In December 1994, the FERC issued an
order on remand from the court's decision that requires Columbia
Transmission to submit a factual filing that identifies the portion of
upstream pipeline supplier fixed charges that may be flowed through
without violation of the 1985 PGA Settlement, as interpreted by the D. C.
Circuit Court. Pending submission of Columbia Transmission's estimate of
the charges actually billed to it by the upstream pipelines which are
eligible for recovery, the FERC deferred further proceedings. Columbia
Transmission's evidentiary filing is due to FERC on March 16, 1995. For
this issue the accompanying financial statements reflect a $35 million
reserve. Columbia Transmission is continuing settlement discussions with
customers on this issue and other significant issues related to the
bankruptcy claims, as well as costs recoverable from the customers under
FERC Order 636 (Order 636), as transition costs. Any amounts ultimately
determined
67
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
to be due the customers upon conclusion of the required FERC proceedings
are prepetition unsecured claims in the bankruptcy proceedings and,
therefore, are not entitled to payment of postpetition interest.
Other refund issues underlying customer claims include prepetition
revenues collected subject to refund in general rate filings, purchased
gas adjustment filings, transportation cost recovery adjustment filings,
and other upstream pipeline flowthrough filings. Appropriate reserves
for rate refund liabilities have been recorded for these matters to
reflect management's judgment of the ultimate outcome of the proceedings.
At a December 1993 hearing, the Bankruptcy Court observed that the FERC
should determine whether customers are entitled to the actual interest
earned on refunds being held by Columbia Transmission or the higher
FERC-prescribed interest rate. The FERC determined that Columbia
Transmission must disburse the restricted investment account (RIA) funds
with interest actually earned on the RIA funds while in the RIA account,
which was established in March 1993, and with interest at the FERC
prescribed rate for the period of time before the RIA was created. On
October 5, 1994, FERC denied a request by Columbia Transmission's
customers for rehearing of its order. One customer filed an appeal of
these orders in the D.C. Circuit Court.
I. REORGANIZATION ITEMS. During 1994, 1993 and 1992 the Corporation and
Columbia Transmission have earned interest income on cash accumulated
from the suspension of payments related to prepetition liabilities,
incurred expenses associated with professional fees and other related
services and, in 1994, reflected adjustments to producer claim levels
based on the claims mediator's report, as detailed below:
($ in millions) 1994 1993 1992
---------------------------------------------------------------------------------------------------
Interest income on accumulated cash 63.4 39.9 26.9
Professional fees and related expenses (35.4) (29.9) (30.7)
Other reorganization items, net (40.3) (1.1) (4.5)
---------------------------------------------------------------------------------------------------
REORGANIZATION ITEMS, NET (12.3) 8.9 (8.3)
---------------------------------------------------------------------------------------------------
68
69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
J. FINANCIAL INFORMATION FOR THE DEBTOR COMPANIES. Condensed financial
information for the Corporation and Columbia Transmission as of, and for,
periods ended December 31, are as follows:
Corporation Columbia Transmission
----------------------- ----------------------
($ in millions) 1994 1993 1994 1993
----------------------------------------------------------------------------------------------------
Current assets
Cash and temporary
cash investments 218.5 128.7 1,253.5 1,209.2
Other 205.6 168.7 360.2 461.8
Total current assets 424.1 297.4 1,613.7 1,671.0
Current liabilities (14.8) (19.2) (330.0) (629.6)
-----------------------------------------------------------------------------------------------------
Working capital 409.3 278.2 1,283.7 1,041.4
Noncurrent assets 3,669.8 3,476.4 2,321.5 2,269.4
Estimated liabilities subject
to Chapter 11 proceedings (2,382.5) (2,382.2) (3,862.3) (3,649.4)
Noncurrent liabilities (228.6) (145.1) (232.0) (178.6)
-----------------------------------------------------------------------------------------------------
NET EQUITY 1,468.0 1,227.3 (489.1) (517.2)
-----------------------------------------------------------------------------------------------------
Operating revenues - - 705.0 1,654.5
Operating expenses (96.6) (7.1) (529.3) (1,433.6)
-----------------------------------------------------------------------------------------------------
Operating income (loss) (96.6) (7.1) 175.7 220.9
Other income (deductions) 390.5 219.0 (135.2) (216.3)
Income taxes 53.2 59.7 9.2 22.8
Cumulative effect of
accounting change (0.1) - (3.1) -
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 240.6 152.2 28.2 (18.2)
-----------------------------------------------------------------------------------------------------
NET CASH FROM OPERATIONS 60.6 64.8 171.3 502.0
-----------------------------------------------------------------------------------------------------
3. REGULATORY MATTERS
A. In April 1992, the FERC issued Order 636, its final rule on Pipeline
Service Obligations and Equality of Transportation Services by Pipelines.
This order fundamentally changes the role of pipelines from providing a
significant merchant function to one in which they perform almost
exclusively as transporters and storers of gas that distribution
companies and end users purchase directly from producers and other
suppliers.
During 1993, the FERC issued a series of orders on the restructuring
proposals that included an order that allowed Columbia Transmission and
Columbia Gulf to implement restructured services on November 1, 1993.
While confirming its initial ruling regarding the ineligibility for
recovery of producer contract rejection costs as gas supply realignment
or Order 500/528 costs, the FERC did rule that Columbia Transmission
could seek to recover a small portion of the contract rejection costs
that had earlier been ruled to be unrecoverable. The FERC also agreed to
waive a nine-month time limit on Columbia Transmission's ability to seek
recovery of unrecovered purchased gas costs to the extent the costs
resulted from contracts that are currently in litigation, including
bankruptcy litigation. Approximately $13.3 million in unrecovered
purchased gas costs were outstanding at December 31, 1994, in addition to
approximately $139 million of prepetition unrecovered purchased gas costs
that have not been paid due to the bankruptcy filing.
The FERC affirmed that Columbia Transmission could continue recovery of
the costs associated with the gathering and processing of natural gas
until it files a general rate case. Management continues to evaluate
69
70
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
long-term plans for these gathering facilities, which have a net book
value of $59.7 million at December 31, 1994. While the ultimate outcome
of issues related to realization of its investment in gathering and
processing facilities is uncertain at this time, management believes that
substantially all of these costs will be recovered through rates or sale
of the facilities.
As part of a September 1993 order on Columbia Transmission's and Columbia
Gulf's Order 636 compliance filings, the FERC initiated a proceeding
concerning Columbia Gulf's transportation service to Columbia
Transmission. Columbia Gulf was directed to show cause as to why it did
not file for abandonment to reduce capacity on its mainline facilities
under Section 7(b) of the Natural Gas Act. Columbia Gulf responded to
the show cause order in December 1993, and asserted that no abandonment
filing was required. In 1994 and early 1995, Columbia Transmission and
Columbia Gulf responded to information requests from the FERC staff.
Management continues to believe that an abandonment filing was not
necessary; however, the ultimate outcome of this issue is uncertain at
this time.
B. In January 1994, the FERC granted requests for rehearing of prior orders
approving settlements between Columbia Transmission and four of its
upstream pipeline suppliers relating to those suppliers' direct billings
to Columbia Transmission in the mid-1980s of production- related costs
authorized under FERC's Order No. 94 (Order 94). The rehearing orders
reject the settlements because they are expressly contingent upon
Columbia Transmission's recovery of the Order 94 settlement payments from
its customers, and that Columbia Transmission's 1985 PGA Settlement
essentially bars such recovery. However, the orders also hold that these
pipelines are not entitled to bill any Order 94 charges to Columbia
Transmission, and ordered these upstream pipelines to refund the
principal portion of all Order 94 collections from Columbia Transmission,
but waived any requirements that these pipelines pay interest on the
refunds. Since Columbia Transmission has been reflecting the interest
income on these refunds since 1990, the effect of these orders led to a
$19.5 million reduction in interest income in 1993. On October 18, 1994,
the FERC essentially denied all requests for rehearing but ordered the
upstream pipeline suppliers to pay Columbia Transmission interest on the
refunds from the date a stay was issued in February 1994. As a result,
in September 1994 Columbia Transmission recorded approximately $1 million
of interest income. The orders also required that refunds be made by
November 17, 1994; however, Columbia Transmission and the pipelines have
agreed, subject to certain conditions, to extensions of time to make
refunds pending judicial review. Columbia Transmission, its upstream
pipelines, and two other customers of one upstream pipeline filed
petitions for review of the subject orders with the U. S. Court of
Appeals for the District of Columbia Circuit.
C. In June 1994, the FERC granted Columbia Transmission's request for
rehearing of a prior order that disallowed the recovery by Columbia
Transmission of approximately $20 million in carrying charges related to
prior period exchange activity and determined that Columbia Transmission
could recover these charges. In July 1994, certain parties filed a
request for rehearing of this decision, which is still pending. The
beneficial effect on income of the FERC's decision was recorded in 1994.
D. On October 31, 1994, Columbia Transmission terminated its long-standing
transportation contract with Columbia Gulf, under which Columbia Gulf
transported gas supply acquired by Columbia Transmission in the
southwest, and Columbia Gulf's recovery of its actual operating costs was
assured. This action was taken because Columbia Transmission no longer
required such transportation following the elimination of its merchant
function under Order 636.
As a result of the termination of this contract, as well as increases in
costs generally since its last rate filing, Columbia Gulf submitted a
general rate filing to the FERC. On November 1, 1994, Columbia Gulf
placed into effect, subject to refund, its new rates which will provide
additional annual revenue of approximately $23 million over Columbia
Gulf's previously approved rates. Settlement discussions with the FERC
and interested parties are ongoing. A hearing on issues related to this
rate filing is currently scheduled to begin in September 1995.
70
71
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
4. COMMODITY HEDGING ACTIVITIES
Subsidiaries in the Corporation's oil and gas and other energy operations
engage in commodity hedging activities to minimize the risk of market
fluctuations associated with the price of crude oil and natural gas
production, propane inventories and commitments for natural gas purchases
and sales. The hedging objectives include assurance of stable and known
minimum cash flows, fixing favorable prices and margins when they become
available and participation in any long-term increases in value. Under
internal guidelines, speculative positions are prohibited.
The Corporation's oil and gas production companies utilize options and
swaps on futures as well as commodity price and basis swaps. The options
provide a price floor for future production volumes and the opportunity
to benefit from any increases in prices. Commodity price swaps provide
for the receipt of a differential between a specified strike price and a
negotiated term of actual futures prices if the futures prices averaged
below the strike price. 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, 1994, there were a
total of 1,700 open contracts representing a notional quantity amounting
to 17 Bcf of natural gas production through September of 1995. A total
of $0.5 million in option premium costs as well as $1.7 million of
unrealized gains have been deferred on the consolidated balance sheet
with respect to these open contracts.
During the year ended December 31, 1994, a total of $3.6 million was
recognized in operating income as realized gains on the settlement of
crude oil and natural gas option and swap contracts.
The Corporation's propane and gas marketing operations utilize futures
contracts and basis swaps to assure adequate margins on the purchase and
resale of natural gas as well as protecting the value and margins of its
propane inventories. At December 31, 1994, there were a total of 773
open contracts through December 1995, representing a notional quantity
amounting to approximately 8 Bcf of natural gas. A total of $3.1 million
of unrealized losses have been deferred on the consolidated balance sheet
with respect to these open contracts. These unrealized losses are offset
by gains which take place when the products are sold.
During the year ended December 31, 1994, $2.7 million of losses were
recognized in operating income on the settlement of natural gas futures
and basis swaps. In addition, $0.1 million was recognized as losses on
the settlement of propane futures contracts.
Gains and losses on propane and gas marketing hedging activities were
offset by amounts realized from the sale of the underlying products.
The Corporation and its subsidiaries are exposed to credit losses in the
event of nonperformance by the counterparties to its various hedging
contracts. Management has evaluated such risk and believes that overall
business risk is minimized as a result of these hedging contracts which
are primarily with major investment grade financial institutions.
5. ACCOUNTING CHANGE
Effective January 1, 1994, the Corporation adopted the Financial
Accounting Standards Board's statement SFAS No. 112, "Employers'
Accounting for Postemployment Benefits." This statement requires
employers to recognize obligations which exist 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.
71
72
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The adoption of this statement resulted in an accrual of $14.4 million of
which $5.6 million was deferred by certain of the distribution
subsidiaries as a regulatory asset pending rate recovery authorization
from their respective state commissions. The after-tax effect of the
remainder reduced net income by $5.6 million.
72
73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
6. INCOME TAXES
The components of income tax expense are as follows:
Year Ended December 31 ($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
INCOME TAXES
Currently payable
Federal 63.8 107.2 90.0
State 10.0 9.6 10.8
------------------------------------------------------------------------------------------------
Total Currently Payable 73.8 116.8 100.8
------------------------------------------------------------------------------------------------
Deferred
Federal 78.9 17.6 (32.2)
State (5.3) 2.3 3.3
------------------------------------------------------------------------------------------------
Total Deferred 73.6 19.9 (28.9)
------------------------------------------------------------------------------------------------
Deferred Investment Credits (1.4) (0.8) (1.4)
------------------------------------------------------------------------------------------------
Income taxes included in income before extraordinary
item and cumulative effect of accounting change 146.0 135.9 70.5
Deferred taxes related to extraordinary item and
cumulative effect of accounting change (3.3) - (20.4)
------------------------------------------------------------------------------------------------
TOTAL INCOME TAXES 142.7 135.9 50.1
------------------------------------------------------------------------------------------------
Total income taxes are different than the amount which would be
computed by applying the statutory Federal income tax rate to book
income before income tax. The major reasons for this difference are
as follows:
Year Ended December 31 ($ in millions) 1994 1993 1992
-------------------------------------------------------------------------------------------------------
Book income (loss) before income taxes,
extraordinary item and cumulative effect 392.2 288.1 161.4
of accounting change
Tax expense (benefit) at statutory Federal
income tax rate 137.3 35.0% 100.8 35.0% 54.9 34.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal
income tax benefit 2.6 0.6 7.6 2.7 9.8 6.1
Estimated non-deductible expenses 6.4 1.6 8.1 2.8 6.4 4.0
Effect of change in tax rates on deferred taxes
previously provided - - 8.7 3.0 - -
Adjustment to prior years' tax provision due to
pending settlement - - 9.2 3.2 - -
Other (0.3) - 1.5 0.5 (0.6) (0.4)
-------------------------------------------------------------------------------------------------------
INCOME TAXES BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 146.0 37.2% 135.9 47.2% 70.5 43.7%
-------------------------------------------------------------------------------------------------------
73
74
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Deferred tax balances are as follows:
At December 31 ($ in millions) 1994 1993
--------------------------------------------------------------------------------------------
Net current liabilities (assets)
Federal (23.8) (3.9)
State (3.7) (0.7)
--------------------------------------------------------------------------------------------
Total (27.5) (4.6)
--------------------------------------------------------------------------------------------
Net noncurrent liabilities
Federal 280.6 190.7
State 63.5 63.1
--------------------------------------------------------------------------------------------
Total 344.1 253.8
--------------------------------------------------------------------------------------------
TOTAL DEFERRED INCOME TAXES 316.6 249.2
--------------------------------------------------------------------------------------------
Deferred income taxes result from temporary differences between the
financial statement carrying amounts and the tax basis of existing
assets and liabilities. The source of these differences and tax
effect of each is as follows:
At December 31 ($ in millions) 1994 1993
--------------------------------------------------------------------------------------------
Property basis differences 627.8 613.5
Accrued interest on debt 230.5 147.0
Gas purchase costs (7.9) 63.0
Transportation costs 20.8 -
Partnership deferrals 27.0 25.4
Deferred revenue 11.4 11.0
Estimated supplier obligations (345.3) (343.8)
Estimated rate refunds (69.9) (85.4)
Postretirement benefits (49.4) (46.1)
Environmental liabilities (49.6) (57.1)
Capitalized inventory overheads (41.5) (26.2)
Unbilled utility revenue (11.1) (7.5)
Interest on prior years' taxes 0.9 (27.0)
Other (27.1) (17.6)
--------------------------------------------------------------------------------------------
TOTAL DEFERRED INCOME TAXES 316.6 249.2
--------------------------------------------------------------------------------------------
74
75
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
7. PENSION AND OTHER POSTRETIREMENT BENEFITS
A. PENSION PLANS
The Corporation has a noncontributory, qualified defined pension plan
covering essentially all employees. Benefits are based primarily on
years of credited service and employees' highest three-year average
annual compensation in the final five years of service. The
Corporation's funding policy complies with Federal law and tax
regulations.
The Corporation also has a nonqualified pension plan that provides
benefits to some employees in excess of the qualified plan's Federal tax
limits.
The following table shows the components of net pension expense for the
qualified and nonqualified plans and the annual contributions for each of
the three years ended December 31, 1994:
PENSION COSTS ($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------
Service cost 34.2 31.7 30.5
Interest cost 68.8 68.8 66.1
Actual return on assets (11.3) (126.9) (55.8)
Net amortization (deferral) (66.1) 56.5 (13.2)
-----------------------------------------------------------------------------------------------
NET PENSION EXPENSE 25.6 30.1 27.6
-----------------------------------------------------------------------------------------------
ANNUAL CONTRIBUTION 7.0 18.0 23.5
-----------------------------------------------------------------------------------------------
ASSUMED ASSET EARNINGS RATE 9.0% 9.0% 9.0%
-----------------------------------------------------------------------------------------------
75
76
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The following table reconciles plan assets and liabilities to the
funded status of the plan:
PLAN ASSETS AND OBLIGATIONS at December 31 ($ in millions) 1994 1993
-----------------------------------------------------------------------------------------------
Plan assets at fair value 893.6 945.2
-----------------------------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Vested benefits 628.5 729.4
Nonvested benefits 45.8 49.3
-----------------------------------------------------------------------------------------------
Accumulated benefit obligation 674.3 778.7
Effect of projected future salary increases 153.5 201.5
-----------------------------------------------------------------------------------------------
TOTAL PROJECTED BENEFIT OBLIGATION 827.8 980.2
-----------------------------------------------------------------------------------------------
Plan assets in excess of (less than) projected benefit obligation 65.8 (35.0)
Unrecognized net gain (158.2) (44.4)
Unrecognized prior service cost 60.7 65.0
Unrecognized transition obligation 9.3 10.4
-----------------------------------------------------------------------------------------------
PREPAID (ACCRUED) PENSION COST (22.4) (4.0)
-----------------------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION 8.5% 7.0%
-----------------------------------------------------------------------------------------------
AVERAGE COMPENSATION GROWTH RATE 5.5% 5.5%
-----------------------------------------------------------------------------------------------
The expected long-term rate of return was 9.0%. Plan assets consist of
primarily equity and fixed income securities.
As of December 31, 1994, the assumption for the discount rate has been
revised upward to 8.5%. The net effect of this change was to decrease
the accumulated benefit obligation and the projected benefit obligation
by $125.7 million and $188.8 million, respectively.
76
77
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
B. OTHER POSTRETIREMENT BENEFITS
The Corporation's subsidiaries also provide medical coverage and life
insurance to retirees. Essentially all active employees are eligible for
benefits upon retirement after completing ten consecutive years of
service after age 45. Normally, spouses and dependents of retirees are
also eligible for medical benefits. The following table shows
components of other postretirement costs for each of the three years
ended December 31, 1994:
OTHER POSTRETIREMENT COSTS ($ in millions) 1994 1993 1992
----------------------------------------------------------------------------------------
Service cost 15.3 16.2 13.3
Interest cost 24.6 25.9 22.5
Actual return on assets (2.1) (12.6) (2.9)
Other, net (4.9) 7.8 (0.4)
----------------------------------------------------------------------------------------
OTHER POSTRETIREMENT COSTS 32.9 37.3 32.5
----------------------------------------------------------------------------------------
ASSUMED ASSET EARNINGS RATE* 9.0% 9.0% 9.0%
----------------------------------------------------------------------------------------
*One of the several established medical trusts is subject to taxation
which results in an after-tax asset earnings rate that is less than
9.0%.
The following table provides a reconciliation of other postretirement
costs' funded status with amounts reflected on the Corporation's
balance sheet at December 31, 1994 and 1993:
PLAN ASSETS AND OBLIGATIONS AT DECEMBER 31 ($ in millions) 1994 1993
-----------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retiree 168.2 188.1
Fully eligible active plan participants 73.9 72.0
Other participants 61.9 89.7
-----------------------------------------------------------------------------------------
Total 304.0 349.8
Plan assets at fair value (91.2) (79.9)
Unrecognized actuarial net gain (loss) 52.1 (9.4)
-----------------------------------------------------------------------------------------
ACCRUED POSTRETIREMENT BENEFIT COST 264.9 260.5
-----------------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION 8.5% 7.0%
-----------------------------------------------------------------------------------------
AVERAGE COMPENSATION GROWTH RATE 5.5% 5.5%
-----------------------------------------------------------------------------------------
The expected long-term, pre-tax rate of return was 9.0%. One of the
established retiree medical trusts is subject to tax, resulting in an
assumed after-tax rate of return of slightly less than 9.0%. Plan assets
consist of shares in various equity and fixed income mutual funds and are
attributable to the retiree medical and retiree life insurance plans.
As of December 31, 1994, the assumption for the discount rate has been
revised upward to 8.5%. The net effect of the change was a $33.9 million
decrease in the accumulated postretirement benefit obligation.
77
78
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The medical accumulated postretirement benefit obligation (APBO) at
December 31, 1994 and 1993 is also based on medical inflation trend
rates, starting at 9.0% and 11.0% and decreasing to 6.0% and 5.5% after
six years and ten years, respectively. A one percent increase in medical
inflation trend rates for each future year would have increased the APBO
by $16.1 million and other postretirement costs by $3.3 million in 1994.
Most of the Corporation's regulated subsidiaries were prefunding retiree
medical costs by year-end 1994 through collective bargaining and
noncollective bargaining voluntary employee beneficiary association
(VEBA) trusts and a 401(h) account, since they were permitted rate
recovery of these costs on an accrual basis consistent with financial
reporting herein. Contributions of approximately $20.7 million and $16.9
million were made to these retiree medical trusts in 1994 and 1993,
respectively. The Corporation's nonregulated subsidiaries fund retiree
medical costs on a pay-as-you-go basis.
All of the Corporation's subsidiaries participate in funding for retiree
life insurance benefits, using a noncontributory VEBA trust. The
Corporation's funding policy is to make annual contributions to this
trust, subject to the statutory maximum tax-deductible limit.
Contributions of approximately $3.8 million and $4.4 million were made to
the retiree life insurance VEBA trust in 1994 and 1993, respectively.
8. LONG-TERM INCENTIVE PLAN
The Corporation has a Long-Term Incentive Plan (Plan) which provides 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 has the right to modify any
outstanding award. A total of 1,500,000 shares of the Corporation's
authorized common stock was initially reserved for issuance under the
Plan's provisions. There were 384,070 shares remaining available for
awards at December 31, 1994.
Stock appreciation rights, which are 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.
78
79
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Transactions for the three years ended December 31, 1994, are as follows:
Options
---------------------------
Without Stock With Stock Option
Appreciation Appreciation Price
Rights Rights Range
---------------------------------------------------------------------------------------------------------
Outstanding 12/31/91 563,760 163,650 $34.30-$46.68
---------------------------------------------------------------------------------------------------------
1992
Granted - - -
Exercised - - -
Cancelled (34,410) - $34.30-$46.68
Converted - - -
Outstanding 12/31/92 529,350 163,650 $34.30-$46.68
---------------------------------------------------------------------------------------------------------
1993
Granted - - -
Exercised - - -
Cancelled (23,730) (7,500) $34.30-$46.68
Converted - - -
Outstanding 12/31/93 505,620 156,150 $34.30-$46.68
---------------------------------------------------------------------------------------------------------
1994
Granted - - -
Exercised - - -
Cancelled (20,655) - $34.30-$46.68
Converted - - -
Outstanding 12/31/94 484,965 156,150 $34.30-$46.68
---------------------------------------------------------------------------------------------------------
Exercisable 12/31/94 484,965 156,150 $34.30-$46.68
---------------------------------------------------------------------------------------------------------
In addition to the options, a contingent stock award of 4,110 shares
was granted to a key executive in 1991 which was issued on September
30, 1994.
9. DEBT OBLIGATIONS
The Corporation's filing for protection under the Bankruptcy Code
constituted an event of default under substantially all of its debt
agreements. Because payment of debt which existed at the filing date
is suspended by the Bankruptcy Code, substantially all of the
Corporation's debt, including short-term debt, has been classified as
Liabilities Subject to Chapter 11 Proceedings. In addition, payment
of interest on prepetition debt is suspended, and no interest expense
on such debt has been recorded since commencement of the bankruptcy
proceedings (see Note 2E).
Following the Chapter 11 filing, the Corporation received approval
from the Bankruptcy Court and the SEC, under the Public Utility
Holding Company Act of 1935, for debtor-in-possession financing
(the DIP Facility).
79
80
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
On September 15, 1994, the Corporation converted its remaining $100
million DIP Facility to a $25 million letter of credit DIP Facility with
Chemical Bank (Chemical). Columbia Transmission also maintains a DIP
Facility with Chemical solely for the issuance of letters of credit for
up to $25 million. The DIP Facilities expire on December 31, 1995,
unless extended by mutual agreement.
Both the Corporation's and Columbia Transmission's facilities carry a fee
of 1% per annum on the issued, but undrawn amount of each letter of
credit outstanding under those facilities. The Corporation's facility
also carries a commitment fee of 1/2 of 1 percent per annum on the
average daily unused amount of the full facility. Other additional fees
have been paid under the DIP Facility.
10. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
SFAS 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 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 uncertainties related to the outcome of the Corporation's Chapter 11
proceedings and the resulting effect upon the ultimate value of the
Corporation's financial assets and liabilities add significantly to the
uncertain nature of any estimate of fair value. The estimates of fair
value required under SFAS No. 107 require the application of broad
assumptions and estimates. Accordingly, any actual exchange of such
financial instruments could occur at values significantly different from
the amounts disclosed.
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable
to estimate that value:
As cash and temporary cash investments, current receivables, current
payables, and certain other short-term financial instruments are all
short-term in nature, their carrying amount approximates fair value. The
estimated fair values of the Corporation's other financial instruments
are reflected in the accompanying table.
Long-term investments
Long-term investments include escrowed proceeds from the sale of the
Canadian subsidiary which consist of Canadian Treasury bills ($25.2
million and $25.4 million for 1994 and 1993, respectively) which are
hedged with short-term foreign currency contracts. The carrying amounts
of the Canadian Treasury bills and the short-term foreign currency
contracts approximate fair value. Long-term investments also include an
income tax refund receivable with associated interest ($30.3 million and
$31.2 million for 1994 and 1993, respectively) whose carrying amount
approximates fair value. Also included are loans receivable ($4.0
million for 1994 and $12.8 million for 1993) whose estimated fair values
are based on the present value of estimated future cash flows using an
estimated rate for similar loans extended currently. It is not
practicable to estimate the fair value of long-term receivables ($146.7
million and $144.4 million for 1994 and 1993, respectively) for the
expected recovery by Columbia Transmission of certain gas purchase
liabilities for which the timing and amount of payments to be received
will be dependent on the outcome of the Chapter 11 proceedings. As
discussed in Note 2, the uncertainties related to these proceedings could
significantly influence the fair value of this financial instrument. The
financial instruments included in long-term investments are primarily
reflected in Investments and Other Assets in the consolidated balance
sheets.
80
81
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Liabilities subject to Chapter 11 proceedings
The estimated fair value of the Corporation's debentures and medium-term
notes is based on quoted market prices for those issues that are traded
on an exchange, and estimates provided by brokers for other issues.
However, quoted market prices and broker estimates inherently include
judgments concerning the outcome of the Corporation's and Columbia
Transmission's Chapter 11 proceedings.
Note 2 discusses the uncertainties related to these proceedings which
could significantly influence the fair value of these financial
instruments. It was not practicable to estimate the fair value of the
remaining long-term debt, which includes the Subordinated Guarantee of
the Leveraged Employee Stock Ownership Plan debt ($87.0 million) and
miscellaneous debt of Columbia Transmission ($1.4 million for 1994 and
1993), because no reliable measurement methodology exists. Prior to
filing its petition for protection under Chapter 11 of the Bankruptcy
Code, the Corporation regularly issued commercial paper, bank notes and
other short-term debt instruments. The carrying amount of such
securities ($892.6 million) is included in Liabilities Subject to Chapter
11 Proceedings. Payment of these obligations and any related interest is
subject to approval by the Bankruptcy Court. Although investors from
time to time may buy and sell these debt obligations, the terms of any
such transactions are private and not disclosed to the Corporation.
Because there can be no assurance as to the ultimate timing and amount of
principal and interest repayments of these obligations, it is not
practicable to determine their fair values.
The carrying amount of other Liabilities Subject to Chapter 11
Proceedings ($1,617.1 million for 1994 and $1,556.0 million for 1993)
primarily represents accounts payable, accrued liabilities and other
liabilities. As discussed in Note 2, these liabilities are subject to
adjustment at the direction of the Bankruptcy Court. In addition, the
timing of the ultimate payment of these liabilities, as well as interest,
if any, is also subject to determination by the Bankruptcy Court.
Accordingly, it is not practicable to determine the fair value of these
liabilities.
1994 1993
--------------------- ----------------------
Carrying Fair Carrying Fair
At December 31 ($ in millions) Amount Value Amount Value
--------------------------------------------------------------------------------------------------------------------
Long-term investments for which it is:
Practicable to estimate fair value 60.1 59.7 69.8 69.9
Not practicable to estimate fair value 146.7 - 144.4 -
Liabilities subject to Chapter 11 proceedings for which it is:
Practicable to estimate fair value
Long-term debt 1,390.8 1,664.8 1,390.8 1,557.5
Not practicable to estimate fair value
Long-term debt 88.4 - 88.4 -
Bank loans and commercial paper 892.6 - 892.6 -
Other 1,617.1 - 1,556.0 -
------------------------------------------------------------------------------------------------------------------
11. OTHER COMMITMENTS AND CONTINGENCIES
A. CAPITAL EXPENDITURES. Capital expenditures for 1995 are currently
estimated at $491 million. Of this amount, $191 million is for
transmission operations, $158 million for distribution operations, $118
million for oil and gas operations, and $24 million for other energy
operations.
81
82
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
B. PARTNERSHIP PROJECTS. Columbia Gulf is a general partner in the
Trailblazer, Overthrust and Ozark pipeline partnerships. Since the
partnerships are nonrecourse, project-financed pipelines, the
partnerships' firm shipper contracts were assigned as collateral for
loans to various banks (or in the case of Ozark, to the Indenture
Trustee).
During 1994, various pipeline shippers, including Columbia Transmission,
entered into negotiations with the partnerships for exit fees to
substantially reduce the cost of or provide for the release from
transportation contracts. Agreements have been reached on certain
contracts, and are currently pending approval by the FERC. Columbia
Gulf's investment in the partnerships, as of December 31, 1994, amounted
to $34.7 million, net of valuation reserves and before related deferred
taxes.
In February 1995, an agreement was reached which provides for the sale of
Columbia Gulf's Ozark partnership investment. The agreement contains
usual closing conditions and is subject to certain governmental
approvals. Closing is expected to occur on May 1, 1995. The impact of
the sale of Columbia Gulf's interest in the partnership is not expected
to have a material impact on the financial condition of the company.
C. OTHER LEGAL PROCEEDINGS. The Corporation 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 the Corporation's consolidated
financial position or results of operations.
The sale of Columbia Gas Development of Canada, Ltd. (Columbia Canada), a
wholly-owned Canadian oil and gas exploration and production subsidiary,
to Anderson Exploration Ltd., was effective December 31, 1991. The sales
price from Columbia Canada was $94.8 million. Of this amount, $27.7
million was placed in escrow as security for certain post-closing
obligations of the Corporation including indemnification for potential
losses arising from litigation involving Columbia Canada. The
Corporation expects to receive all or substantially all of the escrow
account when the litigation is concluded. Upon emergence from
bankruptcy, the Corporation is obligated to deposit into an escrow
account an additional $25 million (Canadian). If after emergence from
bankruptcy, the Corporation maintains an investment grade bond rating for
a six-month period, the additional deposit would be returned. Also, the
Corporation has the right to provide a letter of credit in place of the
cash deposit. As of December 31, 1994, $25.2 million, including accrued
interest, remains in escrow for potential losses arising from litigation
and is included in Accounts Receivable - Noncurrent.
D. ASSETS UNDER LIEN. The letters of credit issued under the
debtor-in-possession financing arrangement on behalf of the Corporation
are secured by the granting of a first priority senior security interest
in collateral consisting of cash and/or cash equivalents in an amount
equal to at least 105% of the outstanding letters of credit. The
obligations under Columbia Transmission's letter of credit facility are
secured by a first priority senior security interest in collateral
consisting of cash and/or cash equivalents in an amount equal to at least
105% of the outstanding letters of credit.
Substantially all of Columbia Transmission's properties have been pledged
to the Corporation as security for debt owed by Columbia Transmission to
the Corporation.
E. COVE POINT LNG TERMINAL. By orders issued July 27, 1994, and September
28, 1994, the FERC determined that the peaking service proposed by the
partnership formed by Columbia LNG Corporation (Columbia LNG) and a
subsidiary of Potomac Electric Power Company (PEPCO) is in the public
interest; however, the proposal to charge market-based rates was denied.
Also, only a portion of Columbia LNG's current rate base was allowed in
the calculation of the cost-based rates.
82
83
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
On December 12, 1994, the FERC certificate to recommission the facility
and offer a peaking service was accepted by the partnership, and the Cove
Point Terminal and pipeline facilities were contributed by Columbia LNG
to the partnership as its initial capital contribution. The PEPCO
subsidiary will contribute up to $25 million in equity and loans for
their half interest in the partnership. It is anticipated that the
peaking service will be operational in the fall of 1995.
Management concluded in 1992 that it was no longer appropriate for
Columbia LNG to continue application of SFAS No. 71. This resulted in an
extraordinary charge of $39.7 million after-tax.
F. OPERATING LEASES. Payments made in connection with operating leases are
charged to operation and maintenance expense as incurred. Such amounts
were $56.6 million in 1994, $55.5 million in 1993 and $57.9 million in
1992. Future minimum rental payments required under operating leases
that have initial or remaining noncancelable lease terms in excess of one
year are:
($ in millions)
--------------------------------------------------------------------------
1995 18.0
--------------------------------------------------------------------------
1996 17.6
--------------------------------------------------------------------------
1997 13.9
--------------------------------------------------------------------------
1998 14.0
--------------------------------------------------------------------------
1999 12.3
--------------------------------------------------------------------------
After 76.2
--------------------------------------------------------------------------
G. ENVIRONMENTAL MATTERS. The Corporation's subsidiaries are subject to
extensive federal, state and local laws and regulations relating to
environmental matters. These laws and regulations, which are constantly
changing, require expenditures for corrective action at various operating
facilities, waste disposal sites and former gas manufacturing sites for
conditions resulting from past practices that have subsequently become
subject to environmental regulation.
Certain subsidiaries have received notice from the United States
Environmental Protection Agency (EPA) that they are among several parties
responsible under federal law for placing wastes at Superfund sites and
may be required to share in the cost of remediation for 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
the Corporation's financial position.
As a result of a 1992 Subpoena and Information Request received from the
EPA for Region III, Columbia Transmission and the EPA reached agreements
in September 1994, that were subsequently approved by the Bankruptcy
Court in November 1994. This agreement gives the agency oversight
responsibility for Columbia Transmission's ongoing environmental
self-assessment and remediation program started in 1990 and has an
effective date of February 23, 1995. The agreement calls for the
remediation work to be done under the Comprehensive Environmental
Response, Compensation and Liability Act. Agreements have also been
reached with two state environmental agencies concerning Columbia
Transmission's environmental remediation programs. In Kentucky, Columbia
Transmission settled all notices of violation issued prior to January 1,
1994, and signed an agreement to reimburse the state for its costs to
oversee the remediation
83
84
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
work under the EPA Order. In Pennsylvania, Columbia Transmission agreed
to reimburse the state for its oversight costs. These agreements have
been approved by the Bankruptcy Court. All environmental agencies have
been declared exempt from the Bar Date established by the Bankruptcy
Court for claims by creditors.
Columbia Transmission initiated a program in 1990 that involved a
comprehensive review of compliance with existing environmental standards,
including review of past operational activities and identification of
potential site problems, through site reviews and the formulation of
remediation programs where necessary. While Columbia Transmission has
made progress in these self-assessment efforts, because of the thousands
of miles of pipeline which it operates, the exceptionally large number of
sites at which it conducts or has conducted operations, and the long
period over which operations have been conducted, it is expected that the
completion of site screenings, characterizations and site-specific
remediations will cover a time frame of approximately 10 to 12 years. A
study previously undertaken for Columbia Transmission which quantified
the scope of future remediation activities is being reviewed by an
independent consultant in light of an EPA order and additional
information accumulated during 1994. The results of this study are not
expected to be available until early to mid-1995. At the present time,
management has no basis to change the previously disclosed estimated
level of environmental expenditures of up to $20 million per year over a
10 to 12 year period. Earnings are charged as costs become probable and
reasonably estimable, regardless of when expenditures are made. Columbia
Transmission's recorded net liability for environmental matters was
approximately $135 million at December 31, 1994. This amount represents
the lower end of a range of reasonable outcomes with the upper end
estimated to total approximately $280 million based on previous studies.
Columbia Transmission received from EPA Region V an Information Request
pursuant to the Resource Conservation and Recovery Act (RCRA) on January
28, 1994. The agency requested Columbia Transmission submit information
and knowledge relating to its generation and management of natural gas
pipeline condensate, used engine oil and similar liquids in the state of
Ohio. Columbia Transmission has submitted the requested information to
EPA Region V and is awaiting a response.
Predecessor companies of Columbia Transmission may have been involved in
the operation of manufactured gas plants. When such plants were
abandoned, material used and created in the process was sometimes buried
at the site. Columbia Transmission is unable at this time to determine
if it will become liable for any characterization or remediation costs at
such sites.
As a result of site characterization studies at various locations during
1993, Columbia Gulf recorded an additional accrual of $6.7 million for
environmental remediation. This accrual is for polychlorinated biphenyl
(PCB) and petroleum hydrocarbon cleanup at certain compressor station
sites and screenings for possible exposure at other locations. Columbia
Gulf continued its site evaluations and remediation activities at various
locations during 1994, and recorded additional accruals of $19.3 million
for environmental matters of which a portion was recovered in current
period revenues. The additional accruals were to remediate newly
discovered contamination at certain compressor station sites, screening
for possible exposure at other locations and for cleanup of various
station sites, pipeline drip sites, and measurement sites. In the event
future screenings identify additional exposure, the costs of remediation
will be quantified, and additional accruals may become necessary.
Distribution's primary environmental issues relate to former manufactured
gas plant sites. Currently, Distribution has identified 13 former gas
plant sites. Environmental investigations are being conducted at five of
these sites which indicate that remedial actions may be required.
Investigations will be conducted at a number of the other sites in the
future. To the extent site investigations have been completed,
remediation plans developed, and any Distribution responsibility for
remedial action established, the appropriate liability has been recorded.
As additional investigations are completed and remediation costs become
probable to which Distribution is determined to be liable, the
appropriate liability will be recorded.
84
85
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Management continues to anticipate recovery of remediation costs through
normal rate proceedings. As of December 31, 1994, the distribution
subsidiaries' had recorded a net liability of $5.6 million.
The eventual total cost of full future environmental compliance for the
Columbia Gas System 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 $146.7 million for the Columbia Gas System at December 31,
1994, which includes the low end of a range for certain expenditures for
the transmission segment previously discussed. As new issues are
identified, additional liabilities will be recorded.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve
mutually acceptable compliance plans. However, there can be no assurance
that fines and penalties will not be incurred.
Management expects most environmental assessment and remediation costs to
be recoverable through rates. Although significant charges to earnings
could be required prior to rate recovery, management does not believe
that environmental expenditures will have a material adverse effect on
the Corporation's financial position, based on known facts, existing laws
and regulations and the period over which expenditures are required.
85
86
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
12. INTEREST INCOME AND OTHER, NET
Year Ended December 31 ($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------------
Interest income 31.8 9.8 13.2
Impairment of other investments (0.9) (10.1) (3.6)
Income from equity investments 12.5 4.8 9.3
Miscellaneous 2.7 2.8 1.6
-----------------------------------------------------------------------------------------------------
TOTAL 46.1 7.3 20.5
-----------------------------------------------------------------------------------------------------
13. INTEREST EXPENSE AND RELATED CHARGES
Year Ended December 31 ($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------------
Interest on debt 0.2 0.2 0.3
Interest on DIP financing 0.5 2.9 4.5
Interest on rate refunds 9.0 8.4 3.5
Interest on prior years' taxes (8.8) 74.5 -
Other interest charges 13.9 15.5 5.4
-----------------------------------------------------------------------------------------------------
TOTAL 14.8 101.5 13.7
-----------------------------------------------------------------------------------------------------
86
87
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
14. BUSINESS SEGMENT INFORMATION
The following tables provide information concerning the Corporation'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.
($ in millions) 1994 1993 1992
-------------------------------------------------------------------------------------------------------
REVENUES
Transmission -Unaffiliated 583.5 1,142.8 954.6
-Intersegment 282.8 642.9 532.9
-------------------------------------------------------------------------------------------------------
TOTAL 866.3 1,785.7 1,487.5
-------------------------------------------------------------------------------------------------------
Distribution -Unaffiliated 1,830.7 1,830.7 1,647.6
-Intersegment - - -
-------------------------------------------------------------------------------------------------------
TOTAL 1,830.7 1,830.7 1,647.6
-------------------------------------------------------------------------------------------------------
Oil and Gas -Unaffiliated 121.7 181.2 184.9
-Intersegment 83.6 41.0 13.8
-------------------------------------------------------------------------------------------------------
TOTAL 205.3 222.2 198.7
-------------------------------------------------------------------------------------------------------
Other energy -Unaffiliated 297.5 236.5 134.9
-Intersegment 67.4 69.9 68.9
-------------------------------------------------------------------------------------------------------
TOTAL 364.9 306.4 203.8
-------------------------------------------------------------------------------------------------------
Adjustments -Unaffiliated - - -
and eliminations -Intersegment (433.8) (753.8) (615.6)
-------------------------------------------------------------------------------------------------------
TOTAL (433.8) (753.8) (615.6)
-------------------------------------------------------------------------------------------------------
CONSOLIDATED 2,833.4 3,391.2 2,922.0
-------------------------------------------------------------------------------------------------------
87
88
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS)
Transmission 205.4 178.7 129.9
Distribution 128.3 146.4 137.7
Oil and gas 30.6 53.6 (101.2)
Other energy 17.5 1.7 6.8
Corporate (8.6) (7.0) (10.3)
-----------------------------------------------------------------------------------------------------
CONSOLIDATED 373.2 373.4 162.9
-----------------------------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
Transmission 103.9 97.8 95.6
Distribution 64.5 62.3 57.6
Oil and gas 86.2 73.8 210.0
Other energy 7.1 5.9 4.9
-----------------------------------------------------------------------------------------------------
CONSOLIDATED 261.7 239.8 368.1
-----------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Transmission 4,138.1 4,156.6 3,897.7
Distribution 2,168.9 2,065.5 1,967.3
Oil and gas 746.4 732.0 734.9
Other energy 128.3 128.6 124.1
Adjustments and eliminations (387.1) (376.3) (388.6)
Corporate and unallocated 370.3 251.5 170.5
-----------------------------------------------------------------------------------------------------
CONSOLIDATED 7,164.9 6,957.9 6,505.9
-----------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Transmission 179.1 137.2 114.2
Distribution 151.4 117.8 99.7
Oil and gas 101.6 95.1 70.8
Other energy 15.1 11.2 15.0
-----------------------------------------------------------------------------------------------------
CONSOLIDATED 447.2 361.3 299.7
-----------------------------------------------------------------------------------------------------
88
89
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data does not always reveal the trend of the System's
business operations due to bankruptcy matters, nonrecurring items and
seasonal weather patterns which affect earnings and related components of
operating revenues and expenses.
First Second Third Fourth
($ in millions except per share data) Quarter Quarter Quarter Quarter
--------------------------------------------------------------------------------------------------------
1994
Operating Revenues 1,157.4 520.5 386.5 769.0
Operating Income 220.7 37.1 17.8 97.6
Income (Loss) before Cumulative
Effect of Accounting Change 140.2 47.8 (15.0) 73.2
Cumulative Effect of
Accounting Change (5.6) - - -
Net Income (Loss) 134.6 (a) 47.8 (b) (15.0) (c) 73.2 (d)
Per Share Amounts
Earnings (Loss) before
Accounting Change 2.77 0.95 (0.30) 1.45
Change in Accounting (0.11) - - -
Earnings (Loss) on Common Stock 2.66 0.95 (0.30) 1.45
---------------------------------------------------------------------------------------------------------
1993
Operating Revenues 1,222.6 592.9 565.5 1,010.2
Operating Income 223.1 1.5 2.5 146.3
Net Income (Loss) 139.8 (e) (2.6) (f) (54.4) (g) 69.4 (h)
Per Share Amounts
Earnings (Loss) on Common Stock 2.77 (0.06) (1.07) 1.37
---------------------------------------------------------------------------------------------------------
(a) Includes an increase in net income of $10.3 million for an
adjustment to the reserve for the IRS settlement and an increase
in net income of $8.3 million for surcharge collections of
certain prior period gas costs. Net income benefited $34.5
million from not recording estimated interest expense on
prepetition debt.
(b) Includes a decrease in net income of $4.3 million for a weather
normalization adjustment resulting from a regulatory settlement
and a decrease in net income of $2.1 million associated with
employee relocation costs, partially offset by an increase in net
income of $3.2 million for an adjustment to a reserve for a
resolution of a royalty dispute. Net income benefited $35.5
million from not recording estimated interest expense on
prepetition debt.
(c) Includes a decrease in net income of $35.4 million resulting from
an increase to a reserve for take-or-pay and other miscellaneous
producer claims. Net income benefited $36.6 million from not
recording estimated interest expense on prepetition debt.
(d) Includes a decrease in net income of $22.8 million for a reserve
established for regulatory issues. Net income benefited $37.6
million from not recording estimated interest expense on
prepetition debt.
(e) Includes an increase in net income of $13.2 million for the
reversal of rate reserves to reflect the outcome of rate cases
related to the transmission segment. Net income benefited $32.9
million from not recording estimated interest expense on
prepetition debt.
(f) Includes a decrease in net income of $37.9 million to record a
writedown in the investment in the Cove Point LNG facility and a
decrease in net income of $7.4 million to record the estimated
loss on the sale of storage inventory. Net income benefited
$33.2 million from not recording estimated interest expense on
prepetition debt.
(g) Includes a decrease in net income of $40.4 million to record the
effect of a preliminary settlement with the IRS, a decrease in
net income of $13.0 million to record a liability for future
environmental remediation costs, a decrease in net income of $9.8
million to reflect the effect of the higher federal corporate tax
rate and a decrease in net income of $9.8 million for several
smaller unusual items. Net income benefited $33.9 million from
not recording estimated interest expense on prepetition debt.
(h) Includes an increase in net income of $13.5 million for gas
inventory charges collected from customers and an increase in net
income of $12.8 million for the WACOG surcharge collected from
customers, partially offset by a decrease in net income of $12.6
million for an adjustment to interest income for pipeline direct
billings. Net income benefited $34.3 million from not recording
estimated interest expense on prepetition debt.
89
90
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
16. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
INTRODUCTION. Reserve information contained in the following tables for
the U.S. properties is management's estimate, which was reviewed by the
independent consulting firm of Ryder Scott Company Petroleum Engineers.
Reserves are reported as net working interest. Gross revenues are
reported after deduction of royalty interest payments.
CAPITALIZED COSTS
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
CAPITALIZED COSTS AT YEAR END
Proved properties 1,185.8 1,129.6 1,111.5
Unproved properties(a) 76.1 79.1 78.9
------------------------------------------------------------------------------------------------
Total capitalized costs 1,261.9 1,208.7 1,190.4
Accumulated depletion (637.6) (600.0) (602.1)
------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS 624.3 608.7 588.3
------------------------------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR(B)
Acquisition
Proved properties - - 0.2
Unproved properties 7.5 7.1 4.6
Exploration 24.3 17.5 25.8
Development 69.0 70.1 39.7
------------------------------------------------------------------------------------------------
COSTS CAPITALIZED 100.8 94.7 70.3
------------------------------------------------------------------------------------------------
(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
$6.4 million in 1994, $6.0 million in 1993 and $5.9 million in
1992.
HISTORICAL RESULTS OF OPERATIONS
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
Gross revenues
Unaffiliated 130.9 181.7 183.9
Affiliated 68.7 40.9 13.2
Production costs 52.0 50.6 50.5
Depletion 85.8 73.5 209.4(a)
Income tax expense 21.6 34.5 (25.0)
------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 40.2 64.0 (37.8)
------------------------------------------------------------------------------------------------
Results of operations for producing activities exclude administrative
and general costs, corporate overhead and interest expense. Income tax
expense is expressed at statutory rates less Section 29 credits.
(a) Includes writedown of the carrying value of $126.4 million for 1992.
90
91
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
OTHER OIL AND GAS PRODUCTION DATA
------------------------------------------------------------------------------------------------
1994 1993 1992
------------------------------------------------------------------------------------------------
Average sales price per Mcf of gas ($) 2.18 2.28 2.02
Average sales price per barrel of oil and
other liquids ($) 15.09 16.17 18.20
Production (lifting) cost per dollar of
gross revenue ($) 0.26 0.23 0.26
Depletion rate per dollar of
gross revenue ($) 0.43 0.33 0.42
------------------------------------------------------------------------------------------------
RESERVE QUANTITY INFORMATION
------------------------------------------------------------------------------------------------
Oil and Other
Gas Liquids
Proved Reserves (Bcf) (000 Bbls)
------------------------------------------------------------------------------------------------
Reserves as of December 31, 1991 808.1 15,568
Revisions of previous estimate (9.1) (946)
Extensions, discoveries and other additions 51.3 3,089
Production (69.2) (3,061)
Sale of reserves-in-place (1.6) -
------------------------------------------------------------------------------------------------
Reserves as of December 31, 1992 779.5 14,650
Revisions of previous estimate (60.1) (589)
Extensions, discoveries and other additions 52.4 2,334
Production (71.5) (3,603)
Sale of reserves-in-place (3.3) -
------------------------------------------------------------------------------------------------
Reserves as of December 31, 1993 697.0 12,792
Revisions of previous estimate (31.3) 1,650
Extensions, discoveries and other additions 81.7 1,386
Production (66.7) (3,611)
Purchase of reserves-in-place 3.6 38
Sale of reserves-in-place (0.5) -
------------------------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1994 683.8 12,255
------------------------------------------------------------------------------------------------
Proved developed reserves as of December 31,
1992 664.4 13,143
1993 573.7 10,793
1994 543.3 11,504
------------------------------------------------------------------------------------------------
91
92
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
Future cash inflows 1,667.3 2,206.4 2,568.9
Future production costs (492.0) (508.0) (562.3)
Future development costs (168.0) (172.0) (162.9)
Future income tax expense (280.6) (463.0) (546.4)
------------------------------------------------------------------------------------------------
Future net cash flows 726.7 1,063.4 1,297.3
Less 10% discount 320.4 512.0 636.2
------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF
DISCOUNTED FUTURE
NET CASH FLOWS 406.3 551.4 661.1
------------------------------------------------------------------------------------------------
Future cash inflows are computed by applying year-end prices to
estimated future production of proved oil and gas reserves. Future
expenditures (based on year-end costs) represent those costs to
be incurred in developing and producing the reserves. Discounted
future net cash flows are derived by applying a 10 percent discount
rate, as required by the Financial Accounting Standards Board, to the
future net cash flows. This data is not intended to reflect the actual
economic value of the Corporation's oil and gas producing properties or
the true present value of estimated future cash flows since many
arbitrary assumptions are used. The data does provide a means of
comparison among companies through the use of standardized measurement
techniques.
92
93
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
A reconciliation of the components resulting in changes in the
standardized measure of discounted cash flows attributable to proved oil
and gas reserves for the three years ending December 31, 1994, follows:
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
Beginning of year 551.4 661.1 567.0
------------------------------------------------------------------------------------------------
Oil and gas sales,
net of production
costs (147.6) (172.0) (146.6)
Net changes in prices
and production costs (236.5) (56.5) 210.4
Change in future
development costs 4.1 (9.2) (5.1)
Extensions, discoveries
and other additions,
net of related costs 68.2 66.9 81.0
Revisions of previous
estimates, net of
related costs (17.3) (71.1) (18.0)
Sales of reserves-in-place (0.5) (4.4) (2.4)
Purchases of reserves-in-place 1.0 - -
Accretion of discount 77.8 92.4 76.9
Net change in income taxes 80.8 36.8 (61.3)
Timing of production
and other changes 24.9 7.4 (40.8)
------------------------------------------------------------------------------------------------
END OF YEAR 406.3 551.4 661.1
------------------------------------------------------------------------------------------------
The estimated discounted future net cash flows decreased during 1994
primarily due to net changes in prices and production costs and
revisions to the economic feasibility of producing certain wells.
Under Order 636, the natural gas pipeline industry is required to
eventually unbundle gathering services from other transportation
services. Columbia Transmission provides transportation services,
including gathering services, for a significant portion of gas produced
from CNR's reserves. If there is a significant increase in gathering
rates as a result of unbundling, certain reserves could be uneconomical
to produce which could have a material adverse effect on CNR's operating
strategies and financial results beginning in 1996. The extent of any
potential asset impairment or increase in operating costs cannot be
quantified at this time.
93
94
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule II
VALUATION AND QUALIFYING ACCOUNTS
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31,
($ in Millions)
Additions - Charged to
------------------------
Beginning Other Deductions Ending
Description Balance Income Accounts (a) (b) Balance
- ----------- --------- ------ ------------- ------------ ---------
Reserves deducted in the balance sheet
from the assets to which they apply:
Allowance for doubtful accounts
1994 11.8 21.5 15.8 37.5 11.6
1993 11.8 17.9 12.6 30.5 11.8
1992 9.7 17.9 9.4 25.2 11.8
(a) Reflects reclassification to a regulatory asset of the uncollectible
accounts related to the Percent of Income Plan (PIP) of Columbia Gas of
Ohio, Inc.
(b) Principally reflects amounts charged off as uncollectible less amounts
recovered.
94
95
ITEM 9.
CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
There has not been a change of accountants nor any disagreements concerning
accounting and financial disclosure within the past two years.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
Information regarding the System's executive officers, who are elected annually
by the directors, is as follows:
JOHN H. CROOM, 62, Chairman of the Board, President and Chief Executive
Officer of the Corporation since August 1984.
DANIEL L. BELL, JR., 65, Senior Vice President and Chief Legal Officer
of the Corporation since January 1989, Corporate Secretary since
January 1988. Senior Vice President of Columbia's Service Corporation
since September 1979.
LOGAN W. WALLINGFORD, 62, Senior Vice President of Columbia Gas System
Service Corporation since March 1989. Senior Vice President of
Planning and Storage for Columbia Transmission from July 1988 to
February 1989, Senior Vice President, Gas Acquisition from July 1987 to
June 1988, Vice President of Planning from March 1985 to June 1987.
RICHARD E. LOWE, 54, Vice President of the Corporation and Columbia Gas
System Service Corporation since September 1988. Vice President and
General Auditor of Columbia Gas System Service Corporation from April
1987 to August 1988. Treasurer of Columbia Gas Development Corporation
from April 1979 to March 1987.
JAMES P. HOLLAND, 46, Chairman and Chief Executive Officer of Columbia
Transmission and Columbia Gulf Transmission Company since September
1990. President of Columbia Transmission from May 1988 to August 1990.
President of Columbia Gulf Transmission Company from October 1989 to
August 1990. Senior Vice President of Marketing of Columbia
Transmission from July 1987 to April 1988, Senior Vice President of Gas
Acquisition from January 1986 to June 1987.
C. RONALD TILLEY, 57, Chairman and Chief Executive Officer of Columbia
Distribution Companies since January 1987.
MICHAEL W. O'DONNELL, 50, Senior Vice President and Chief Financial
Officer of the Corporation since October 1993. Senior Vice President
and Assistant Chief Financial Officer of the Columbia Gas System
Service Corporation since 1989.
95
96
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Exhibits
Reference is made to pages 99 through 103 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 the Corporation or its subsidiaries
have not been included as Exhibits because such debt does not exceed 10% of the
total assets of the Corporation and its subsidiaries on a consolidated basis.
The Corporation agrees to furnish a copy of any such instrument to the SEC upon
request.
Financial Statement Schedules
All of the financial statements and financial statement schedules filed as a
part of the Annual Report on Form 10-K are included in Item 8.
Reports on Form 8-K
A report on Form 8-K was filed on November 17, 1994, discussing the Bankruptcy
Court's approval of the extension of the exclusivity period to the earlier of
April 18, 1995, or 45 days following the District Court's decision on the
Intercompany Complaint. The exclusivity period is the period of time that
Columbia Transmission and the Corporation have the exclusive right to file
Chapter 11 plans or reorganization.
A report on Form 8-K was filed on February 2, 1995, containing a Press Release
published on February 2, 1995, regarding the Corporation's seeking approval of
a shareholder rights plan to protect shareholders' investments in the event of
an unsolicited, inadequate offer for the Corporation's common stock.
A report on Form 8-K was filed on February 10, 1995, containing a Press Release
published on February 9, 1995, regarding the financial and operating results
for the year ended December 31, 1994.
A report on Form 8-K was filed on February 15, 1995, containing a Press Release
published on February 15, 1995, regarding the election of three new members of
the Corporation's Board of Directors. The Press Release also noted that three
current members of the Board are not seeking reelection.
96
97
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
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, the Corporation undertakes the following,
which is incorporated by reference into the registration statements on Form
S-8, Nos. 33-10004 (filed November 26, 1986) and 33-42776 (filed September 13,
1991):
Insofar as indemnification for liabilities arising under the Securities Act of
1933 (Act) may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless in
the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the questions whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
97
98
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 6, 1995
By: /s/ Michael W. O'Donnell
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(Michael W. O'Donnell)
Senior Vice President and
Chief Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
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Signature Title Date
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/s/ Michael W. O'Donnell (Principal March 6, 1995
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(Michael W. O'Donnell) Financial Officer)
John H. Croom Director (Principal March 6, 1995
Executive Officer) ]
Richard E. Lowe Vice President (Principal
Accounting Officer) ] March 6, 1995
Richard F. Albosta Director ]
Robert H. Beeby Director ]
Thomas S. Blair Director ]
Wilson K. Cadman Director ]
John D. Daly Director ]
James P. Heffernan Director ]
Robert H. Hillenmeyer Director ] By: /s/ Michael W. O'Donnell
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Malcolm T. Hopkins Director ] (Michael W. O'Donnell)
Malcolm Jozoff Director ] Attorney-in-Fact
William E. Lavery Director ]
George P. MacNichol, III Director ]
Gerald E. Mayo Director ]
Douglas E. Olesen Director ]
Ernesta G. Procope Director ]
James R. Thomas II Director ]
William R. Wilson Director ]
98
99
EXHIBIT INDEX
Reference is made in the two right-hand columns below to those
exhibits which have heretofore been filed with the Commission. Exhibits so
referred to are incorporated herein by reference.
Reference
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File No. Exhibit
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3-A - Restated Composite Certificate of Incorporation, 1-1098 3-A
as amended to October 19, 1988; corrected
copy as of July 15, 1991.
3-B - By-Laws of the Corporation, as amended to 1-1098 3-B
November 18, 1987.
4-A - Indenture, dated as of June 1, 1961, between 1-1098 2-C
the Corporation and Morgan Guaranty Trust
Company of New York, Trustee, and thirteen
supplemental indentures thereto.
4-B - Fourteenth Supplemental Indenture, dated as 2-38139 2-P
of April 1, 1970, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-C - Fifteenth Supplemental Indenture, dated as of 2-393340 2-D
October 1, 1970, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-D - Sixteenth Supplemental Indenture, dated as of 2-41557 2-E
March 1, 1971, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-E - Indenture, dated as of June 1, 1961, between 1-1098 4-E
the Corporation and Morgan Guaranty Trust
Company of New York, Trustee, and the
Seventeenth through the Twenty-eighth
supplemental indentures thereto.
4-H - Twenty-ninth Supplemental Indenture, dated as 1-1098 4-H
of June 1, 1982, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-I - Thirtieth Supplemental Indenture, dated as of 1-1098 4-I
January 8, 1986, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-J - Thirty-first Supplemental Indenture, dated 1-1098 4-J
August 1, 1986, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-K - Thirty-second Supplemental Indenture, dated 1-1098 4-K
August 1, 1986, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
99
100
EXHIBIT INDEX (Continued)
Reference
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File No. Exhibit
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4-L - Thirty-third Supplemental Indenture, dated 1-1098 4-L
June 1, 1987, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-M - Thirty-fourth Supplemental Indenture, dated 1-1098 4-M
November 1, 1988, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-N - Thirty-fifth Supplement Indenture, dated 1-1098 4-N
August 18, 1989, between the Corporation
and Morgan Guaranty Trust Company of
New York, Trustee.
4-0 - Thirty-sixth Supplemental Indenture, dated 1-1098 4-0
November 30, 1989, between the Corporation
and Morgan Guaranty Trust Company of
New York, Trustee.
4-P - Thirty-seventh Supplemental Indenture, dated 1-1098 4-P
June 6, 1990, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
10-P(a) - Pension Restoration Plan of The Columbia Gas 1-1098 10-P
System, Inc., amended October 9, 1991.
10-Q(a) - Thrift Restoration Plan of The Columbia Gas 1-1098 10-Q
System, Inc. dated January 1, 1989.
10-S - Gas Sales Contract, dated November 15, 1983, 1-1098 10-S
between Tennessee Gas Pipeline Company and
Columbia Gas Transmission Corporation.
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-U - Stipulation dated October 1, 1993, between 1-1098 10-U
Columbia Gas Transmission Corporation and
Tennessee Gas Pipeline Company.
10-V - Stipulation dated August 24, 1993, between 1-1098 10-V
Columbia Gas Transmission Corporation and
Texas Eastern Transmission Corporation.
10-Z - Amendment, dated as of February 4, 1985, 1-1098 10-Z
to Gas Sales Contract, dated November 15,
1983, between Tennessee Gas Pipeline
Company and Columbia Gas Transmission
Corporation.
10-AA* - Stipulation dated December 9, 1994, between Columbia
Gas Transmission Corporation and Ozark Gas Transmission
System.
10-AB* - Stipulation dated May 10, 1994, between Columbia Gas
Gas Transmission Corporation and Trailblazer Pipeline
Company.
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(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
* Filed herewith.
100
101
EXHIBIT INDEX (Continued)
Reference
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File No. Exhibit
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10-AC* - Agreement dated April 26, 1994, between Columbia Gas
Transmission Corporation and Wyoming Interstate Company.
10-AD* - Stipulation dated May 24, 1994, between Columbia Gas
Transmission Corporation and Natural Gas Pipeline
Company of America.
10-AE* - U.S. Environmental Protection Agency Administrative
Order by Consent for Removal Actions for Columbia Gas
Transmission Corporation.
10-AN - Indenture of Mortgage and Deed of Trust by Columbia 1-1098 10-AN
Gas Transmission Corporation to Wilmington Trust
Company, as Trustee, dated August 30, 1985.
10-AZ(a) - The Columbia Gas System, Inc. Long-Term 1-1098 10-AZ
Incentive Plan, amended through January 1,
1987.
10-BB(a) - Annual Incentive Compensation Plan of 1-1098 10-BB
The Columbia Gas System, Inc., dated
November 16, 1988.
10-BD - $750 million Credit Agreement, dated October 5, 1988 1-1098 10-BD
between the Corporation and Morgan Guaranty
Trust Company of New York, as Agent.
10-BG - Letter Agreement, dated February 15,1989, 1-1098 10-BG
between Texas Gas Transmission Corporation
and Columbia Gas Transmission Corporation,
amending the Letter Agreement of
September 12, 1988.
10-BH - Letter Agreement, dated June 15, 1989, between 1-1098 10-BH
Tennessee Gas Pipeline Company and
Columbia Gas Transmission Corporation.
10-BI - $500 million Amended and Restated Credit Agreement, dated 1-1098 10-BI
September 17, 1990, between the Corporation
Morgan Guaranty Trust Company of New York,
as Agent.
10-BJ - Gas Sales Contract, dated September 1, 1989, 1-1098 10-BJ
between Tennessee Gas Pipeline Company and
Columbia Gas Transmission Corporation.
10-BK - Gas Sales Contract, dated January 1,1989, 1-1098 10-BK
between Tennessee Gas Pipeline Company,
and Columbia Gas Transmission Corporation.
10-BL - Service Agreement, dated November 1, 1989, 1-1098 10-BL
between Transcontinental Gas Pipe Line
Corporation and Columbia Gas Transmission
Corporation.
10-BR - Secured Revolving Credit Agreement dated 1-1098 10-BR
September 23, 1991, between The Columbia
Gas System Inc. and Manufacturers Hanover Trust
Company, as Agent.
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.
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(a) Executive Compensation arrangements filed pursuant to Item 14 of Form
10-K.
* Filed herewith.
101
102
EXHIBIT INDEX (Continued)
Reference
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File No. Exhibit
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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 made 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-BZ(a) - Employment Agreements between The Columbia Gas 1-1098 10-BZ
System, Inc. and seven senior executives, each
dated July 19, 1993.
10-CA(a) - The Columbia Gas System, Inc. Retirement Plan 1-1098 10-CA
for Outside Directors, as amended, August 21, 1991.
10-CB - First Amendment, dated as of October 21, 1991, to the 1-1098 10-CB
Secured Revolving Credit Agreement, dated as of
September 23, 1991, among The Columbia Gas System,
Inc., certain banks party thereto and Manufacturers
Hanover Trust Company as Agent for the banks.
10-CC - Second Amendment, dated as of December 11, 1991, to 1-1098 10-CC
the Secured Revolving Credit Agreement, dated as of
September 23, 1991, among The Columbia Gas System,
Inc., certain banks party thereto and Manufacturers
Hanover Trust Company as Agent for the banks.
10-CD - Amended and Restated Secured Revolving Credit Agreement, 1-1098 10-CD
dated April 2, 1992, between Columbia Gas Transmission
Corporation and Manufacturers Hanover Trust Company
as Agent for banks.
10-CE - Settlement Agreement, dated September 17, 1992, among 1-1098 10-CE
The Columbia Gas System, Inc., Columbia LNG Corporation,
Shell LNG Company, Shell Oil Company, R. J. Pusanik,
L. L. Smith, J. B. Edrington and D. E. Cannon, in
settlement of Columbia LNG., et al. v. Shell LNG Co.,
et. al., Civil Action No. 12663 in the Court of
Chancery of the State of Delaware.
10-CF - Amended and Restated Security Agreement, dated as of 1-1098 10-CF
April 2, 1992, between Columbia Gas Transmission
Corporation and Manufacturers Hanover Trust Company.
10-CG - Third Amendment, dated June 15, 1992, to the Secured 1-1098 10-CG
Revolving Credit Agreement, dated as of September 23, 1991
(as therefore amended), among The Columbia Gas System, Inc.,
certain banks party thereto and Manufacturers Hanover Trust
Company, as Agent for the banks.
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(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
102
103
EXHIBIT INDEX (Continued)
Reference
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File No. Exhibit
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10-CH - First Amendment, dated as of January 8, 1993, to the 1-1098 10-CH
Amended and Restated Secured Revolving Credit Agreement,
dated as of April 2, 1992 between Columbia Gas Transmission
Corporation and Chemical Bank.
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-CK - Fourth Amendment, dated April 26, 1993, the Secured Revolving 1-1098 10-CK
Credit Agreement, dated as of September 23, 1991 (as therefore
amended), among The Columbia Gas System, Inc., certain bank parties
thereto and Chemical Bank successor by merger to Manufacturers
Hanover Trust Company as agent for the banks.
10-CL - Second Amendment, dated December 9, 1993, to the Amended and 1-1098 10-CL
Restated Secured Revolving Credit Agreement, dated as of
April 2, 1992 between Columbia Gas Transmission Corporation
and Chemical Bank.
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.
10-CN* - Amended and Restated Secured Revolving Credit Agreement dated as of
September 15, 1994, between The Columbia Gas System, Inc., and
Chemical Bank of New York.
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 February 3, 1995, and the written
consent to the filing and use of information contained
in such letter report, Reports and Registration Statements
filed during 1995, of Ryder Scott Company Petroleum Engineers,
independent petroleum and natural gas consultants.
23-B* - Written consent of Arthur Andersen LLP,
independent public accountants, to the
incorporation by reference of their report
included in the 1994 Annual Report on Form
10-K of The Columbia Gas System, Inc. and
their report included in The Columbia Gas
System, Inc.'s 1994 Annual Report to Shareholders
in the registration statements on Form S-8
(File No. 33-10004), and Form S-8
(File No. 33-42776).
24* - Powers of attorney and certified copy of board
resolution authorizing execution of Form 10-K
by power of attorney.
27* - Financial Data Schedule for the period ended
December 31, 1994.
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*Filed herewith.
103