<PAGE> 1
Commission File No. 1-1098
As filed with the Securities and Exchange Commission on March 6, 1995.
================================================================================
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)
<TABLE>
<S> <C>
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
- ------------------------------------------------------------------------ ------------------------------------
(Address of principal executive offices) (Zip Code)
</TABLE>
Registrant's telephone number, including area code (302) 429-5000
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<S> <C>
Name of Each Exchange
Title of Each Class on Which Registered
------------------- --------------------
Common Stock, $10 Par Value . . . . . . . . . . . . . New York Stock Exchange
</TABLE>
Debentures
<TABLE>
<S> <C> <C>
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
</TABLE>
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.
<PAGE> 2
CONTENTS
<TABLE>
<CAPTION>
Page
Part I No.
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<S> <C>
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
</TABLE>
<PAGE> 3
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.
3
<PAGE> 4
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
4
<PAGE> 5
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.
5
<PAGE> 6
ITEM 2. PROPERTIES (Continued)
OIL AND GAS DATA
Acreage - At December 31, 1994
<TABLE>
<CAPTION>
Developed Acreage Undeveloped Acreage
---------------------------- -------------------------------
Gross Net Gross Net
--------- ------- ---------- -------
<S> <C> <C> <C> <C>
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
=========== ========== =========== ===========
</TABLE>
Net Wells Completed - 12 Months Ended December 31
<TABLE>
<CAPTION>
Exploratory Development Total
----------------------------- ------------------------------ -----------------------
Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- -----
<S> <C> <C> <C> <C> <C> <C>
1994 . . . . 3 9 78 14 81(a) 23
1993 . . . . 2 10 91 18 93(a) 28
1992 . . . . 9 14 37 7 46(a) 21
</TABLE>
Productive and Drilling Wells - At December 31, 1994
<TABLE>
<CAPTION>
Production Wells
---------------------------------------------
Gross(b) Net Wells Drilling
-------------- ------------------ ---------------
Gas Oil Gas Oil Gross Net
------ ----- --- --- ----- ---
<S> <C> <C> <C> <C> <C>
6,512 662 5,836 361 25 11
</TABLE>
(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.
6
<PAGE> 7
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1994
<TABLE>
<CAPTION>
Miles of Pipeline Compressor Stations
Underground ------------------------------- -------------------
Storage Gathering Installed
--------------- and Trans- Distri- Capacity
Subsidiaries State Acreage Wells Storage mission mission Number (hp)
- -------------------------------------------- ----- ------- ----- --------- ------- ------- ------ ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
======== ======= ========= ========= ========= ======= =========
</TABLE>
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
7
<PAGE> 8
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
8
<PAGE> 9
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
9
<PAGE> 10
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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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 $26. On June 19, 1991, the
Corporation suspended the dividend on its common stock. Management cannot
determine at this time when dividends will again be paid.
See Item 7 on page 27 for additional information regarding the Corporation's
common stock prices and dividends.
17
<PAGE> 18
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
($ in millions except per share amounts) 1994* 1993* 1992* 1991* 1990
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
Index Page
- --------------------------------------------------------------------------
<S> <C>
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
- --------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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 $4 billion of liabilities subject to the Chapter 11 proceedings
of the Corporation and Columbia Transmission as follows:
<TABLE>
<CAPTION>
($ in millions)
- ---------------------------------------------------------------------
<S> <C>
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
- ---------------------------------------------------------------------
</TABLE>
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.
20
<PAGE> 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
21
<PAGE> 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.
22
<PAGE> 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
<PAGE> 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.
24
<PAGE> 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 $160.4 million. The impact of lower oil and gas
prices, warmer weather and higher operating costs for the distribution segment
were offset by interest earned on cash accumulated during bankruptcy and
improved results for the transmission segment due in part to the full year
effect of FERC Order No. 636 (Order 636).
Unusual and Bankruptcy Related Items
After-Tax Effect on Net Income
<TABLE>
<CAPTION>
($ in millions) 1994 1993
- ---------------------------------------------------------------------------------------------------
<S> <C> <C>
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)
===== =====
</TABLE>
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.
25
<PAGE> 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.
26
<PAGE> 27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF COMMON STOCK PRICES AND DIVIDENDS
<TABLE>
<CAPTION>
Market Price
------------------------------- Quarterly
Quarter Ended High Low Close Dividends Paid
- ----------------------------------------------------------------------------
$ $ $ CENT
<S> <C> <C> <C> <C>
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 -
- ----------------------------------------------------------------------------
</TABLE>
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.
27
<PAGE> 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
<TABLE>
<CAPTION>
(in millions) 1995 1994 1993
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
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
- ----------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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).
29
<PAGE> 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
30
<PAGE> 31
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.
31
<PAGE> 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
32
<PAGE> 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
33
<PAGE> 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.
34
<PAGE> 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.
35
<PAGE> 36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------
</TABLE>
TRANSMISSION OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------
</TABLE>
36
<PAGE> 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.
37
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 42
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1994 1993 1992
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------
</TABLE>
42
<PAGE> 43
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS*
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------
</TABLE>
* Includes Columbia Gas of New York, Inc. through March 31, 1991.
** Reflects volumes under purchase contracts of less than one year.
43
<PAGE> 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
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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 $(101.2)
- -------------------------------------------------------------------------------------------------------------
</TABLE>
OIL AND GAS OPERATING HIGHLIGHTS*
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
CAPITAL EXPENDITURES ($ 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
- -------------------------------------------------------------------------------------------------------------
</TABLE>
* Years 1991 and 1990 include results from Canadian operations that were sold
effective December 31, 1991.
46
<PAGE> 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
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
OTHER ENERGY OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------
</TABLE>
49
<PAGE> 50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
Index Page
- -------------------------------------------------------------------------------
<S> <C>
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
- -------------------------------------------------------------------------------
</TABLE>
50
<PAGE> 51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
COMPARATIVE GAS OPERATIONS DATA
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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)
- ------------------------------------------------------------------------------------------------------------
</TABLE>
*Certain amounts in prior periods have been reclassified to conform with the
current presentation.
51
<PAGE> 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
<PAGE> 53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31 (in millions except per share amounts) 1994* 1993* 1992*
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------
</TABLE>
*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
<PAGE> 54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
ASSETS as of December 31 (in millions) 1994* 1993*
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------
</TABLE>
* 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
<PAGE> 55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES as of December 31 (in millions) 1994* 1993*
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------
</TABLE>
55
<PAGE> 56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31 (in millions) 1994* 1993* 1992*
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------------------------------------
</TABLE>
* 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
<PAGE> 57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
The Columbia Gas System, Inc. and Subsidiaries
<TABLE>
<CAPTION>
Common Stock*
--------------------------- Additional Unearned
(In millions except Shares Par Paid In Retained Employee
for share amounts) Outstanding(000) Value Capital Earnings Compensation
<S> <C> <C> <C> <C> <C>
- -------------------------------------------------------------------------------------------------------------------
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)
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
*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
<PAGE> 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
<PAGE> 59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
At December 31 ($ in millions) 1994 1993
--------------------------------------------------------------------------------
<S> <C> <C>
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
--------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The accompanying Consolidated Balance Sheets include approximately $4
billion of liabilities subject to the Chapter 11 proceedings of the
Corporation and Columbia Transmission as follows:
<TABLE>
<CAPTION>
($ in millions) 1994 1993
----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
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
----------------------------------------------------------------------------------------------------------------
</TABLE>
62
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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:
<TABLE>
<CAPTION>
($ in millions) 1994 1993 1992
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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)
---------------------------------------------------------------------------------------------------
</TABLE>
68
<PAGE> 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:
<TABLE>
<CAPTION>
Corporation Columbia Transmission
----------------------- ----------------------
($ in millions) 1994 1993 1994 1993
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
-----------------------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 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 $5.6 million.
72
<PAGE> 73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
6. INCOME TAXES
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
------------------------------------------------------------------------------------------------
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1994 1993 1992
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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%
-------------------------------------------------------------------------------------------------------
</TABLE>
73
<PAGE> 74
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Deferred tax balances are as follows:
<TABLE>
<CAPTION>
At December 31 ($ in millions) 1994 1993
--------------------------------------------------------------------------------------------
<S> <C> <C>
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
--------------------------------------------------------------------------------------------
</TABLE>
Deferred income taxes result from temporary differences between the
financial statement carrying amounts and the tax basis of existing
assets and liabilities. The source of these differences and tax
effect of each is as follows:
<TABLE>
<CAPTION>
At December 31 ($ in millions) 1994 1993
--------------------------------------------------------------------------------------------
<S> <C> <C>
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
--------------------------------------------------------------------------------------------
</TABLE>
74
<PAGE> 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:
<TABLE>
<CAPTION>
PENSION COSTS ($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
-----------------------------------------------------------------------------------------------
</TABLE>
75
<PAGE> 76
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The following table reconciles plan assets and liabilities to the
funded status of the plan:
<TABLE>
<CAPTION>
PLAN ASSETS AND OBLIGATIONS at December 31 ($ in millions) 1994 1993
-----------------------------------------------------------------------------------------------
<S> <C> <C>
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%
-----------------------------------------------------------------------------------------------
</TABLE>
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 $188.8 million, respectively.
76
<PAGE> 77
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
B. OTHER POSTRETIREMENT BENEFITS
The Corporation's subsidiaries also provide medical coverage and life
insurance to retirees. Essentially all active employees are eligible for
benefits upon retirement after completing ten consecutive years of
service after age 45. Normally, spouses and dependents of retirees are
also eligible for medical benefits. The following table shows
components of other postretirement costs for each of the three years
ended December 31, 1994:
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT COSTS ($ in millions) 1994 1993 1992
----------------------------------------------------------------------------------------
<S> <C> <C> <C>
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%
----------------------------------------------------------------------------------------
</TABLE>
*One of the several established medical trusts is subject to taxation
which results in an after-tax asset earnings rate that is less than
9.0%.
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:
<TABLE>
<CAPTION>
PLAN ASSETS AND OBLIGATIONS AT DECEMBER 31 ($ in millions) 1994 1993
-----------------------------------------------------------------------------------------
<S> <C> <C>
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%
-----------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 79
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Transactions for the three years ended December 31, 1994, are as follows:
<TABLE>
<CAPTION>
Options
---------------------------
Without Stock With Stock Option
Appreciation Appreciation Price
Rights Rights Range
---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
---------------------------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 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 $1,556.0 million for 1993)
primarily represents accounts payable, accrued liabilities and other
liabilities. As discussed in Note 2, these liabilities are subject to
adjustment at the direction of the Bankruptcy Court. In addition, the
timing of the ultimate payment of these liabilities, as well as interest,
if any, is also subject to determination by the Bankruptcy Court.
Accordingly, it is not practicable to determine the fair value of these
liabilities.
<TABLE>
<CAPTION>
1994 1993
--------------------- ----------------------
Carrying Fair Carrying Fair
At December 31 ($ in millions) Amount Value Amount Value
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Long-term investments for which it is:
Practicable to estimate fair value 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 -
------------------------------------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 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 $57.9 million in
1992. Future minimum rental payments required under operating leases
that have initial or remaining noncancelable lease terms in excess of one
year are:
<TABLE>
<S> <C>
($ in millions)
--------------------------------------------------------------------------
1995 18.0
--------------------------------------------------------------------------
1996 17.6
--------------------------------------------------------------------------
1997 13.9
--------------------------------------------------------------------------
1998 14.0
--------------------------------------------------------------------------
1999 12.3
--------------------------------------------------------------------------
After 76.2
--------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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
<PAGE> 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 $146.7 million for the Columbia Gas System at December 31,
1994, which includes the low end of a range for certain expenditures for
the transmission segment previously discussed. As new issues are
identified, additional liabilities will be recorded.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve
mutually acceptable compliance plans. However, there can be no assurance
that fines and penalties will not be incurred.
Management expects most environmental assessment and remediation costs to
be recoverable through rates. Although significant charges to earnings
could be required prior to rate recovery, management does not believe
that environmental expenditures will have a material adverse effect on
the Corporation's financial position, based on known facts, existing laws
and regulations and the period over which expenditures are required.
85
<PAGE> 86
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
12. INTEREST INCOME AND OTHER, NET
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
-----------------------------------------------------------------------------------------------------
</TABLE>
13. INTEREST EXPENSE AND RELATED CHARGES
<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
-----------------------------------------------------------------------------------------------------
</TABLE>
86
<PAGE> 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.
<TABLE>
<CAPTION>
($ in millions) 1994 1993 1992
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
-------------------------------------------------------------------------------------------------------
</TABLE>
87
<PAGE> 88
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
($ in millions) 1994 1993 1992
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
-----------------------------------------------------------------------------------------------------
</TABLE>
88
<PAGE> 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.
<TABLE>
<CAPTION>
First Second Third Fourth
($ in millions except per share data) Quarter Quarter Quarter Quarter
--------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
---------------------------------------------------------------------------------------------------------
</TABLE>
(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 $34.3 million from not recording
estimated interest expense on prepetition debt.
89
<PAGE> 90
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
16. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
INTRODUCTION. Reserve information contained in the following tables for
the U.S. properties is management's estimate, which was reviewed by the
independent consulting firm of Ryder Scott Company Petroleum Engineers.
Reserves are reported as net working interest. Gross revenues are
reported after deduction of royalty interest payments.
<TABLE>
<CAPTION>
CAPITALIZED COSTS
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
------------------------------------------------------------------------------------------------
</TABLE>
(a) Represents expenditures associated with properties on which
evaluations have not been completed.
(b) Includes internal costs capitalized pursuant to the accounting
policy described in Note 1 to Consolidated Financial Statements of
$6.4 million in 1994, $6.0 million in 1993 and $5.9 million in
1992.
<TABLE>
<CAPTION>
HISTORICAL RESULTS OF OPERATIONS
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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)
------------------------------------------------------------------------------------------------
</TABLE>
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 $126.4 million for 1992.
90
<PAGE> 91
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
OTHER OIL AND GAS PRODUCTION DATA
------------------------------------------------------------------------------------------------
1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Average sales price per Mcf of gas ($) 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 ($) 0.43 0.33 0.42
------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
RESERVE QUANTITY INFORMATION
------------------------------------------------------------------------------------------------
Oil and Other
Gas Liquids
Proved Reserves (Bcf) (000 Bbls)
------------------------------------------------------------------------------------------------
<S> <C> <C>
Reserves as of December 31, 1991 808.1 15,568
Revisions of previous estimate (9.1) (946)
Extensions, discoveries and other additions 51.3 3,089
Production (69.2) (3,061)
Sale of reserves-in-place (1.6) -
------------------------------------------------------------------------------------------------
Reserves as of December 31, 1992 779.5 14,650
Revisions of previous estimate (60.1) (589)
Extensions, discoveries and other additions 52.4 2,334
Production (71.5) (3,603)
Sale of reserves-in-place (3.3) -
------------------------------------------------------------------------------------------------
Reserves as of December 31, 1993 697.0 12,792
Revisions of previous estimate (31.3) 1,650
Extensions, discoveries and other additions 81.7 1,386
Production (66.7) (3,611)
Purchase of reserves-in-place 3.6 38
Sale of reserves-in-place (0.5) -
------------------------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1994 683.8 12,255
------------------------------------------------------------------------------------------------
Proved developed reserves as of December 31,
1992 664.4 13,143
1993 573.7 10,793
1994 543.3 11,504
------------------------------------------------------------------------------------------------
</TABLE>
91
<PAGE> 92
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
------------------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
($ in millions) 1994 1993 1992
------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
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
------------------------------------------------------------------------------------------------
</TABLE>
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
<PAGE> 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)
<TABLE>
<CAPTION>
Additions - Charged to
------------------------
Beginning Other Deductions Ending
Description Balance Income Accounts (a) (b) Balance
- ----------- --------- ------ ------------- ------------ ---------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
(a) Reflects reclassification to a regulatory asset of the uncollectible
accounts related to the Percent of Income Plan (PIP) of Columbia Gas of
Ohio, Inc.
(b) Principally reflects amounts charged off as uncollectible less amounts
recovered.
94
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
-----------------------------------
(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.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Signature Title Date
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
/s/ Michael W. O'Donnell (Principal March 6, 1995
- --------------------------------
(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
----------------------------
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 ]
</TABLE>
98
<PAGE> 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.
<TABLE>
<CAPTION>
Reference
-------------------
File No. Exhibit
-------- -------
<S> <C> <C> <C> <C>
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.
</TABLE>
99
<PAGE> 100
EXHIBIT INDEX (Continued)
<TABLE>
<CAPTION>
Reference
-------------------
File No. Exhibit
-------- -------
<S> <C> <C> <C> <C>
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.
</TABLE>
- ---------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
* Filed herewith.
100
<PAGE> 101
EXHIBIT INDEX (Continued)
<TABLE>
<CAPTION>
Reference
-------------------
File No. Exhibit
-------- -------
<S> <C> <C> <C> <C>
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.
</TABLE>
- -------------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form
10-K.
* Filed herewith.
101
<PAGE> 102
EXHIBIT INDEX (Continued)
<TABLE>
<CAPTION>
Reference
-------------------
File No. Exhibit
-------- -------
<S> <C> <C> <C> <C>
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.
</TABLE>
- ---------------------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
102
<PAGE> 103
EXHIBIT INDEX (Continued)
<TABLE>
<CAPTION>
Reference
-------------------
File No. Exhibit
-------- -------
<S> <C> <C> <C> <C>
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.
</TABLE>
- --------------------------
*Filed herewith.
103
<PAGE> 1
EXHIBIT 10-AA
IN THE UNITED STATES BANKRUPTCY COURT
FOR THE DISTRICT OF DELAWARE
IN RE THE COLUMBIA GAS SYSTEM, INC. AND
COLUMBIA GAS TRANSMISSION CORPORATION,
DEBTORS. CASE NOS. 91-803
91-804
STIPULATION
WHEREAS, Ozark Gas Transmission System (Ozark) and Columbia Gas
Transmission Corporation (TCO) are parties to a certain agreement, as amended,
as follows (Contract):
<TABLE>
<CAPTION>
Contract Dth/Day Contract Date
------------ ------- -------------
<S> <C> <C>
MS-27534-AR 85,000 March 1, 1982
</TABLE>
WHEREAS, on April 8, 1992, the Federal Energy Regulatory Commission (FERC)
issued Order No. 636, as amended by subsequent Commission orders (Order No.
636) requiring, inter alia, restructuring of interstate pipeline rates and
services; and
WHEREAS, Ozark commenced implementation of Order No. 636 on its system on
October 1, 1993; and
WHEREAS, TCO implemented restructured services under Order No. 636 on
November 1, 1993 and does not require the contract with Ozark for firm
transportation and has been unable to permanently assign any of the capacity
associated with the Contract to its customers or other parties; and
WHEREAS, TCO and Ozark wish to terminate the Contract in consideration of
the agreements set out herein; and
<PAGE> 2
WHEREAS, TCO and Ozark agree that the term "Excess Capacity" shall mean
the total amount of permanently unassigned capacity not required under the
Contract as of the effective date of this Stipulation, pursuant to Paragraph 9
herein; and
WHEREAS, TCO and Ozark have agreed to an exit fee (as has been
contemplated by Order No. 636) to be calculated as specified below (the "Exit
Fee") in consideration of TCO's and Ozark's abandonment of the Excess Capacity,
which capacity is not required by TCO or its customers as a result of TCO's
implementation of Order No. 636; and
WHEREAS, TCO will use its Transportation Cost Rate Adjustment mechanism
(TCRA) to fully recover the Exit Fee from its customers pursuant to Order No.
636, which mechanism for such recovery was approved by the FERC by orders
issued on July 14, 1993 and September 29, 1993, in Docket Nos. RS92-5, et al.;
and
WHEREAS, on March 18, 1992, Ozark filed certain interim proofs of claim
against TCO, to-wit:
a. Proof of Claim No. 12161 in the amount of $1,236,445.68 plus
interest, costs and attorneys' fees to the extent allowable, which
relates to certain pre-petition imbalances due Ozark under the
Contract in connection with the transportation of natural gas;
b. Proof of Claim No. 12164 in the amount of $1,817,107.00 plus
interest, costs and attorneys' fees to the extent allowable, which
relates to certain pre-petition charges due Ozark under the
Contract for the transportation of natural gas during June and July
1991;
2
<PAGE> 3
c. Proof of Claim No. 12162 in an unknown amount, plus interest, costs
and attorneys' fees to the extent allowable, which relates to
certain post-petition imbalances due Ozark under the Contract
in connection with the transportation of natural gas;
d. Proof of Claim No. 12163 in the amount of $21,661,582.00, plus
interest, costs and attorneys' fees to the extent allowable, which
relates to contingent Contract rejection damages under the terms of
the Contract.
WHEREAS, Ozark has further made a post-petition claim for reimbursement of
construction costs associated with certain delivery point facilities to
Arkla/MRT at Searcy in the amount of $336,194.
WHEREAS, Ozark owes TCO certain excess deferred income taxes in the amount
of $1,723,629 due to be refunded through February 28, 1997, the termination
date of the Contract. Of this amount $898,046 is due to be refunded through
September 30, 1994. Ozark has alleged a right of setoff for its pre-petition
transportation expense claim against the refund of excess deferred taxes.
WHEREAS, TCO and Ozark have agreed to settle the amount of transportation
expense under Claim No. 12164 in the amount of $1,723,629 as a setoff claim,
which amount will be paid by TCO within ten (10) business days after the
approval of this Stipulation by the Bankruptcy Court, in exchange for Ozark's
withdrawal of all other claims against TCO for the period prior to October 1,
1994, subject to reinstatement as provided in paragraph 9 herein; and
3
<PAGE> 4
WHEREAS, pursuant to the Bankruptcy Court's orders of September 20, 1991
and October 3, 1991, TCO is authorized to remedy pre-petition gas imbalances
under transportation and exchange agreements in the ordinary course of business
and TCO and Ozark will remedy any pre- and post-petition gas imbalances under
transportation and exchange agreements in the ordinary course of business;
IT IS THEREFORE STIPULATED AND AGREED by the parties hereto as follows:
1. The Contract shall be terminated by agreement of the parties 70 days
after the effective date of this Stipulation pursuant to paragraph 9 herein,
subject to reinstatement as provided in said paragraph 9; provided, however,
that within 10 business days after the effective date, TCO shall pay to Ozark
the Exit Fee in satisfaction of its contractual obligations and no further
demand charge payment, other than demand charges accrued to the effective date,
shall be owed by TCO for the 70-day period after the effective date and prior
to the Contract termination date, subject to reinstatement pursuant to the
provisions of paragraph 9 herein. Ozark shall, within the 70-day period, pay
the Series A and Series C notes in full and obtain a defeasance of rights
thereunder. The 70-day period may be shortened by the parties if all
imbalances between the parties have been rectified, accrued demand charges
shall have been paid by TCO, and Ozark shall have paid the balance of the Ozark
indenture in full and received a defeasance of rights pursuant thereto. This
provision shall not be construed to relieve TCO from its contractual
obligations prior to Contract termination, it being understood between the
parties that payment of the Exit Fee satisfies such contractual obligations.
Other than as provided for in this Stipulation, each party hereby waives any
claim, rights or damages thereunder for services rendered prior to the
effective
4
<PAGE> 5
date, except for (1) claims with respect to imbalances which shall be remedied
in the ordinary course of business pursuant to the Bankruptcy Court's orders of
September 20, 1991 and October 3, 1991 authorizing TCO to remedy gas
imbalances; (2) post-petition unpaid invoice claims for billing periods
subsequent to September 30, 1994 which shall be satisfied in the ordinary
course of business as administrative expense claims under Section 503 of the
Bankruptcy Code; (3) the right of Ozark to recover from TCO costs which have
been authorized by the FERC for service periods predating the effective date of
this Stipulation pursuant to Paragraph 9 herein; and (4) the right of TCO to
refunds, excluding excess deferred taxes which are dealt with herein, from
Ozark for overpayments made to Ozark, as determined by the FERC, for services
rendered to TCO by Ozark during periods which predate the effective date of
this Stipulation pursuant to Paragraph 9 herein.
2. Prior to the effective date of this Stipulation pursuant to Paragraph
9 herein, the Contract will be permanently assignable to TCO's customers and to
other parties in accordance with Order No. 636, as it may be amended, modified
or superseded, and Ozark's and TCO's approved FERC Gas Tariff, and subject to
applicable laws, rules, regulations, and orders of applicable regulatory
authorities. Without limiting the foregoing, TCO shall have the right prior to
the date this Stipulation becomes effective to assign all or a portion of the
firm transportation capacity underlying the Contract, on a permanent basis in
connection with TCO's and/or Ozark's restructuring under Order No. 636 to one
or more of TCO's customers or other parties which would be eligible to receive
service under Ozark's Tariff and Ozark agrees that any permanent full or
partial assignment(s) of capacity to an eligible shipper,
5
<PAGE> 6
which complies in all respects with Ozark's tariff, shall constitute an
assignment of the underlying Contract pursuant to 11 U.S.C. Section 365(f).
Accordingly, upon permanent assumption and assignment of capacity by TCO to
such customers or other parties, TCO shall not, consistent with the provisions
of 11 U.S.C. Section 365(k), have any liability for "breach of such Contract
occurring after such assignment" with respect to the assigned capacity;
provided, however, that nothing herein shall affect (1) the right of Ozark to
recover from TCO costs (a) which have been authorized by the FERC for service
periods predating the effective date of assignment of the underlying Contract,
and (b) which are recoverable by Ozark from TCO, consistent with the terms of a
FERC order, during that portion of the FERC-approved recovery period predating
the effective date of assignment of the underlying Contract; and (2) the right
of TCO to refunds from Ozark for overpayments made to Ozark, as determined by
the FERC, for services rendered to TCO by Ozark during periods which pre-date
the effective date of assignment of the underlying Contract except for excess
deferred taxes which are dealt with herein.
3. Without limiting in any respect the provisions of Paragraph 2, TCO
shall, until the effective date of this Stipulation pursuant to Paragraph 9
herein, be entitled to the same rights and subject to the same obligations
under Ozark's tariff and FERC orders as all other customers of Ozark under the
same Rate Schedule, including the right to participate in Ozark's capacity
release and assignment program.
4. Within ten (10) business days after this Stipulation is approved by
the Bankruptcy Court, Ozark shall at its option, either refund the amount of
$1,723,629, representing the total amount of excess deferred taxes due to be
refunded to TCO through
6
<PAGE> 7
February 28, 1997, the termination date of the Contract, or refund the amount
of $898,046, representing the amount of excess deferred taxes due to be
refunded to TCO through September 30, 1994, and thereafter refund, with
interest on the unpaid balance accruing at the applicable FERC interest rate
from the effective date of this Stipulation, the balance of the excess deferred
taxes as the taxes actually become due until the principal amount of $1,723,629
is paid. Nothing herein shall be construed to prohibit Ozark from paying the
outstanding balance with accrued interest to date at any time with no further
interest obligation. The total amount of $1,723,629 plus any interest due will
be paid no later than February 28, 1997.
5. Within ten (10) business days after this Stipulation is approved by
the Bankruptcy Court, TCO shall pay Ozark $1,723,629, without interest, in
satisfaction of Ozark's Claim No. 12164 for pre-petition transportation
expenses and any right of setoff by Ozark under Section 553 of the Bankruptcy
Code. In consideration of such payment, all of Ozark's proofs of claim against
TCO, with the exception of Proof of Claim No. 12163, which shall be deemed
withdrawn upon payment of the Exit Fee contemplated in paragraph 6 herein,
subject to reinstatement pursuant to paragraph 9 herein, shall be deemed
withdrawn with prejudice on the tenth day after the date of approval by the
Bankruptcy Court and Ozark shall file no other claims in TCO's bankruptcy for
the period prior to October 1, 1994; provided, however, such claims are subject
to reinstatement by Ozark to the extent provided under Paragraph 9, as well as
TCO's concomitant right to assert any objections to such claims.
6. Within ten (10) business days after the date the Stipulation becomes
effective pursuant to Paragraph 9 herein, TCO shall pay Ozark the Exit Fee in
consideration of the
7
<PAGE> 8
termination of the Contract. Proof of Claim No. 12163 shall be deemed
withdrawn upon payment of the Exit Fee, subject to reinstatement as provided in
paragraph 9 herein. The Exit Fee amount shall be calculated using the formula
on Attachment A and using the Excess Capacity that exists as of the date the
Stipulation becomes effective pursuant to Paragraph 9 herein. In order to
determine the Exit Fee, the remaining term of the Contract shall commence on
the effective date pursuant to Paragraph 9.(1)
7. TCO shall continue to make payments billed by Ozark relating to the
Contract up to the effective date of this Stipulation, pursuant to Paragraph 9
herein. A partial month shall be pro-rated to the effective date.
8. This Stipulation shall not be deemed an admission of any fact or
proposition of law, and shall not be used for any purpose other than to enforce
the terms of this Stipulation and the orders entered approving this Stipulation
as described in Paragraph 9. Notwithstanding the prior sentence, the parties
hereto shall be free to refer to and discuss this Stipulation for informational
purposes in any proceedings before the FERC or other courts and regulatory
bodies and in related discussions and negotiations.
9. This Stipulation shall not be effective until it is approved,
executed and entered by the Bankruptcy Court and until FERC issues a final
order, no longer subject to rehearing, approving this Stipulation, including,
specifically, authorization for TCO to fully recover the Exit Fee, with
interest at the applicable FERC interest rate, from its customers pursuant to
the
- ----------------------------------
(1) Assuming an October 1, 1994 effective date and 85,000 Dth per day of
Excess Capacity, the Exit Fee would be $13.5 million in accordance with
the Schedule on Attachment A. Assuming an April 1, 1995 effective date
and 85,000 Dth per day of Excess Capacity, the Exit Fee would be
$10,864,792.
8
<PAGE> 9
TCRA. A FERC order relating to the Exit Fee which contains any provisions or
condition which would have a material adverse effect on Ozark's rates as a
result of termination of the Contract shall not satisfy the prior sentence
unless Ozark consents to such order as constituting an order approving the
Stipulation. TCO and Ozark agree to use reasonable, good faith efforts to
obtain approval from the Bankruptcy Court and FERC where such approvals are
required and to take all reasonable steps necessary to assist the other in
obtaining such approvals. Without limitation of the prior sentence, Ozark
agrees that it will support, or not oppose TCO in its filing to recover the
Exit Fee costs from its customers and TCO agrees that it will support , or not
oppose Ozark before FERC with respect to issues arising as a result of
terminating the Contract and payment of the Exit Fee. If any court should
reverse in whole or in part the order of the Bankruptcy Court or the final
order of the FERC approving this Stipulation, unless the parties agree in
writing to the contrary, all monies paid by TCO or Ozark pursuant to this
Agreement, plus interest at the applicable FERC interest rate, shall be
returned to the other, the status quo ante shall be restored, the Contract
reinstated and TCO and Ozark agree to pay all amounts due (e.g., demand
charges, excess deferred taxes, etc.) between the effective date of this
Stipulation and the date of reversal. In the event of a reversal in whole or
in part of the order of the Bankruptcy Court or the final order of the FERC
approving this Stipulation, Ozark may set off all amounts paid by TCO, except
for amounts paid by TCO representing pre-petition claims, against all amounts
due from TCO for post-petition contractual obligations between the effective
date and the date of reversal. TCO and Ozark retain all rights to assert
claims, objections and other rights that are to be resolved by this settlement,
and no party can use this settlement as
9
<PAGE> 10
evidence against TCO or Ozark. If, forty-five (45) days prior to the date
first set for the hearing on the confirmation of a plan of reorganization for
TCO (which plan has been distributed for voting purposes) (the "Notification
Date"), the Bankruptcy Court has entered an order and the FERC has issued a
final order approving this Stipulation no longer subject to rehearing, but
either or both of such orders are subject to review on appeal, TCO may elect to
assume the obligations arising under this Stipulation and the Contract, by
notifying Ozark of its decision in writing within five (5) business days
following the Notification Date. In the event TCO does not exercise the option
described above in the time prescribed herein, this Stipulation shall be
treated as if either the order of the Bankruptcy Court or the final order of
FERC approving this Stipulation has been reversed on appeal and the parties
shall be returned to the status quo ante. Ozark and TCO shall have all of
their respective rights under the Bankruptcy Code and other applicable law,
including, without limitation, TCO's right to seek rejection of the Contract
and Ozark's right to oppose such rejection and to file claims arising out of
any rejection of the Contract and to seek allowance and payment of such claims.
10. If this Stipulation has not been approved on or before April 30, 1995
by the Bankruptcy Court and by the FERC by final orders, no longer subject to
rehearing, this Stipulation may be terminated by either party by giving ten
(10) business days prior written notice.
Dated: December 9th, 1994
OZARK GAS TRANSMISSION SYSTEM
By: /s/ Charles R. Evans
----------------------------
10
<PAGE> 11
Charles R. Evans
Its: President
COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ B. D. Perine
-------------------------------
B. D. Perine
Its: Sr. Vice President
11
<PAGE> 1
EXHIBIT 10-AB
IN THE UNITED STATES BANKRUPTCY COURT
FOR THE DISTRICT OF DELAWARE
In re THE COLUMBIA GAS SYSTEM, INC. and
COLUMBIA GAS TRANSMISSION CORPORATION
Debtors. Case Nos. 91-803
91-804
Chapter 11
STIPULATION
WHEREAS, Trailblazer Pipeline Company (Trailblazer) and Columbia Gas
Transmission Corporation (TCO) are parties to certain agreements, as amended,
as follows (Contracts):
<TABLE>
<CAPTION>
Contract No. Mcf/Day Contract Date
- ------------ ------- -------------
<S> <C> <C>
WH-33404-GN 69,500 October 8, 1982
WH-23597-GN 175,000 September 20, 1979
</TABLE>
WHEREAS, on April 8, 1992, the Federal Energy Regulatory Commission (FERC)
issued Order No. 636, as amended by subsequent Commission orders (Order No.
636) requiring inter alia, restructuring of interstate pipeline rates and
services; and
WHEREAS, Trailblazer commenced implementation of Order No. 636 on its
system on December 1, 1993; and
WHEREAS, TCO implemented restructured services under Order No. 636 on
November 1, 1993 and does not require the Contracts and has been unable to
assign any of the capacity associated with Contract No. WH-33404-GN, a 69,500
Mcf per day firm transportation contract, to its customers or other parties;
and
<PAGE> 2
WHEREAS, TCO and Trailblazer wish to terminate the Contracts in
consideration of the agreements set out herein; and
WHEREAS, TCO and Trailblazer agree that the term "Excess Capacity"
Shall mean the total amount of unassigned or capacity not required under
Contract No. WH-33404-GN as of the first day of the month following the
effective date of this Stipulation pursuant to Paragraph 10 herein; and
WHEREAS, TCO and Trailblazer have agreed to an exit fee (as has been
contemplated by Order No. 636) to be calculated as specified below (Exit Fee)
in consideration of TCO's abandonment of the Excess Capacity, which capacity is
not required as a result of TCO's implementation of Order No. 636; and
WHEREAS, TCO will use its Transportation Cost Rate Adjustment mechanism
(TCRA) to fully recover the Exit Fee from its customers pursuant to Order No.
636, which mechanism for such recovery was approved by the FERC by orders
issued on July 14, 1993 and September 29, 1993, in Docket Nos. RS92-5, et
al.; and
WHEREAS, Trailblazer filed proofs of claim against TCO on March 12, 1992,
Claim No. 8629, for $583,519.91 for transportation expense and on March 9,
1992, Claim No. 7984, a duplicate of Claim No. 8629, and which was disallowed
by the Bankruptcy Court by Order issued July 13, 1993; and
WHEREAS, TCO and Trailblazer have agreed that the amount of transportation
expense under Claim No. 8629 is $589,267.45, which amount will be paid within
ten (10) days after the approval of this Stipulation by the Bankruptcy Court;
and
2
<PAGE> 3
WHEREAS, pursuant to the Bankruptcy Court's orders of September 20,
1991 and October 3, 1991, TCO is authorized to remedy pre-petition gas
imbalances under transportation and exchange agreements in the ordinary course
of business and TCO and Trailblazer will remedy any pre- and post-petition gas
imbalances under transportation and exchange agreements in the ordinary course
of business; and
WHEREAS, a settlement filed by Trailblazer with FERC on October 23,
1990 and approved by FERC order dated April 9, 1991, in Docket Nos. RP84-94,
et al., provides for the annual refund by Trailblazer of certain excess
deferred taxes related to the period January 1, 1983 through June 30, 1987 of
which TCO claims entitlement in an amount totalling approximately $3.4 million,
against which Trailblazer has an alleged right of setoff for its pre-petition
transportation expense claim.
WHEREAS, TCO supplied line pack gas to Trailblazer under the Contracts
in the amount of 248,558 Dth which TCO agrees to transfer to Trailblazer upon
termination of the Contracts for the payment of $1.77 per Dth.
IT IS THEREFORE STIPULATED AND AGREED by the parties hereto as follows:
1. The Contracts are hereby terminated by agreement of the parties upon
the effective date of this Stipulation pursuant to Paragraph 10; provided
however, that such Contracts shall continue for a period not to exceed sixty
(60) days solely to enable the paries to rectify any imbalances (it being
understood that the Exit
3
<PAGE> 4
Fee will commence notwithstanding such continuation of the Contracts and that
no demand payment shall be owed by TCO for any such period). Other than as
provided for in this Stipulation, each party hereby waives any claim for
damages thereunder for services rendered prior to the termination date, except
for (1) claims with respect to imbalances which shall be remedied in the
ordinary course of business pursuant to the Bankruptcy Court's orders of
September 20, 1991 and October 3, 1991 authorizing TCO to remedy gas
imbalances; (2) post-petition unpaid invoice claims which shall be satisfied in
the ordinary course of business as administrative expense claims under Section
503 of the Bankruptcy Code; (3) the right of Trailblazer to recover from TCO
costs which have been authorized by the FERC for service periods predating the
effective date of this Stipulation pursuant to Paragraph 10 herein; and (4) the
right of TCO to refunds, including refunds of excess deferred taxes from
Trailblazer for overpayments made to Trailblazer, as determined by the FERC,
for services rendered to TCO by Trailblazer during periods which predate the
effective date of this Stipulation pursuant to Paragraph 10 herein.
2. Prior to the effective date of this Stipulation pursuant to
Paragraph 10 herein, the Contracts will be fully or partially assignable to
TCO's customers and to other parties in accordance with Order No. 636, as it
may be amended, modified or superseded, and Trailblazer's and TCO's approved
FERC Gas Tariff, and subject to applicable laws, rules, regulations, and orders
of applicable regulatory authorities. Without limiting the foregoing, TCO
shall
4
<PAGE> 5
have the right prior to the date this Stipulation becomes effective to assign
all or a portion of the firm transportation capacity underlying the Contracts,
on a permanent basis in connection with TCO's and/or Trailblazer's
restructuring under Order No. 636 to one or more of TCO's customers or other
parties which would be eligible to receive service under Trailblazer's Tariff
and Trailblazer agrees that any permanent full or partial assignment(s) of
capacity to an eligible shipper shall constitute an assignment of the
underlying Contracts pursuant to 11 U.S.C. Section 365(f). Accordingly, upon
permanent assignment of capacity by TCO to such customers or other parties, TCO
shall not, consistent with the provisions of 11 U.S.C. Section 365(k), have
any liability for "breach of such [contracts] occurring after such
assignment(s)" with respect to the assigned capacity; provided, however, that
nothing herein shall affect (1) the right of Trailblazer to recover from TCO
costs (a) which have been authorized by the FERC for service periods predating
the effective date of assignment of the underlying contract(s), and (b) which
are recoverable by Trailblazer from TCO, consistent with the terms of a FERC
order, during that portion of the FERC-approved recovery period predating the
effective date of assignment of the underlying contracts; and (2) the right of
TCO to refunds from Trailblazer for overpayments made to Trailblazer, as
determined by the FERC, for services rendered to TCO by Trailblazer during
periods which pre-date the effective date of assignment of the underlying
contract(s).
5
<PAGE> 6
3. Without limiting in any respect the provisions of Paragraph 2, TCO
shall, until the effective date of this Stipulation pursuant to Paragraph 10
herein, be entitled to the same rights and subject to the same obligations
under Trailblazer's tariff and FERC orders as all other customers of
Trailblazer under the same Rate Schedule, including the right to participate in
Trailblazer's capacity release program.
4. Trailblazer shall make excess deferred tax refunds to TCO in
Docket Nos. RP84-94, et al., as they become due and payable, which refunds
shall continued to be made after the effective date of this Stipulation
pursuant to Paragraph 10 herein; provided, however, that refunds which became
due and payable prior to the effective date of this Stipulation but which have
not yet been paid by Trailblazer shall be paid within ten (10) days after the
effective date of this Stipulation.
5. Within ten (10) days after all amounts payable by TCO hereunder to
Trailblazer have been paid, Trailblazer shall pay TCO $439,947, plus interest
from the effective date of this Stipulation pursuant to Paragraph 10 herein at
the applicable FERC interest rate, for transfer of title to the line pack gas
in the amount of 248,558 Dth which TCO supplied under the Contracts.
6. Within ten (10) days after this Stipulation is approved by the
Bankruptcy Court TCO shall pay Trailblazer $589,267, without interest, in
satisfaction of Trailblazer's Claim No. 8629 for pre-petition transportation
expenses and any right of setoff by Trailblazer under Section 553 of the
Bankruptcy Code. In
6
<PAGE> 7
consideration of such payment, all of Trailblazer's proofs of claim against TCO
shall be deemed withdrawn with prejudice on the tenth day after the date of
approval by the Bankruptcy Court; provided, however, such proofs of claim are
subject to reinstatement by Trailblazer to the extent provided under Paragraph
10, as well as TCO concomitant right to assert any objections to such proofs of
claim.
7. Beginning the first day of the month following the date the
Stipulation becomes effective pursuant to Paragraph 10 herein, TCO shall pay
Trailblazer the Exit Fee, plus interest from the effective date of this
Stipulation pursuant to Paragraph 10 herein at the applicable FERC interest
rate on the remaining outstanding balance of the Exit Fee, based on a payment
schedule corresponding to TCO's collection of the Exit Fee, plus the aforesaid
interest, from its customers pursuant to the TCRA in consideration of the
termination of Contract WH-33404-GN. The Exit Fee principal amount shall be
calculated using the formula on Attachment A and using the Excess Capacity that
exists as of the first dy of the month following the date the Stipulation
becomes effective pursuant to Paragraph 10 herein. (1)
8. TCO shall continue to make payments billed by Trailblazer relating
to the Contracts up to the effective date of this Stipulation pursuant to
Paragraph 10 herein.
- ----------------------------------
(1) Assuming a January 1, 1994 effective date and 69,500 Mcf per day of
Excess Capacity, the Exit Fee would be $18,800,000 in accordance with the
Schedule on Attachment A. Assuming a January 1, 1995 effective date and 69,500
Mcf per day of Excess Capacity, the Exit Fee would be $17,175,306.
7
<PAGE> 8
9. This Stipulation shall not be deemed an admission of any fact or
proposition of law, and shall not be used for any purpose other than to enforce
the terms of this Stipulation and the orders entered approving this Stipulation
as described in Paragraph 10. Notwithstanding the prior sentence, the parties
hereto shall be free to refer to and discuss this Stipulation for informational
purposes in any proceedings before the FERC or other courts and regulatory
bodies and in related discussions and negotiations.
10. This Stipulation shall not be effective until it is approved,
executed and entered by the Bankruptcy Court and until FERC issues a final
order, no longer subject to rehearing, approving this Stipulation, including,
specifically, authorization for TCO to fully recover the Exit Fee, with
interest, from its customers. A FERC order relating to the Exit Fee which
contains any provision or condition which would have a material adverse effect
on Trailblazer's ability to adjust its rates to reflect termination of the
Contracts shall not satisfy the prior sentence unless Trailblazer consents to
such order as constituting an order approving the Stipulation. TCO and
Trailblazer agree to use reasonable, good faith efforts to obtain approval from
the Bankruptcy Court and FERC where such approvals are required and to take all
reasonable steps necessary to assist the other in obtaining such approvals.
Without limitation of the prior sentence, Trailblazer agrees that it will
actively support TCO inn its filing to recover the Exit Fee costs from its
customers (which filing may be in the form of a joint filing for approval of
the
8
<PAGE> 9
Stipulation) and TCO agrees that it will not take any position in Trailblazer's
proceedings before FERC which is adverse to Trailblazer with respect to
disposition of the amounts received by Trailblazer for the Exit Fee,
Trailblazer's ability to adjust its rates to reflect termination of the
Contracts or adjustment of the volumes used in the design of Trailblazer's
rates to reflect termination of the Contracts. If any Court should reverse in
whole or in part the order of the Bankruptcy Court or the final order of the
FERC approving this Stipulation, unless the parties agree in writing to the
contrary, all monies paid by TCO to Trailblazer under Paragraphs 6 and 7, plus
interest, shall be returned to TCO, the status quo ante shall be restored and
TCO and Trailblazer agree to pay all amounts due (e.g., demand charges, etc.)
between the effective date and the date of reversal, and TCO and Trailblazer
retain all rights to assert claims, objections and other rights that are to be
resolved by this settlement, and no party can use this settlement as evidence
against TCO and Trailblazer. If, forty-five (45) days prior to the date first
set for hearing on the confirmation of a plan of reorganization for TCO (which
plan has been distributed to voting purposes) (the "Notification Date"), the
Bankruptcy Court has entered an order and the FERC has issued a final order
approving this Stipulation, no longer subject to rehearing, but either or both
of such orders are subject to review on appeal, TCO may elect to assume the
obligations arising under this Stipulation and the Contracts, post-confirmation
by notifying Trailblazer of its decision in writing within five (5) business
9
<PAGE> 10
days following the Notification Date. In the event TCO does not exercise the
option described above in the time prescribed herein, this Stipulation shall be
treated as if either the order of the Bankruptcy Court or the final order of
FERC approving this Stipulation has been reversed on appeal and the parties
shall be returned to the status quo ante. Trailblazer and TCO shall have all
of their respective rights under the Bankruptcy Code and other applicable law,
including, without limitation, TCO's right to reject the Contracts and
Trailblazer's right to file claims arising out of any rejection of the
Contracts and to seek allowance and payment of such claims.
Dated: May 10, 1994.
-------------
TRAILBLAZER PIPELINE COMPANY COLUMBIA GAS TRANSMISSION
CORPORATION
By: /s/ James A. Brett By: /s/ B. D. Perine
------------------------- ----------------------
Its: Vice President Its: Senior Vice President
---------------------- -------------------------
10
<PAGE> 1
EXHIBIT 10-AC
WIC / Columbia Exit Fee Agreement
This Agreement is entered into by Wyoming Interstate Company, Ltd.
("WIC") and Columbia Gas Transmission Corporation ("TCO").
WHEREAS: WIC and TCO are parties to a Transportation Service Agreement
dated August 15, 1983 pursuant to which WIC provides firm transportation
service for TCO under WIC's FERC Rate Schedule T. Said agreement has a
termination date of January 1, 2004; AND
WHEREAS: TCO has restructured its services pursuant to the Federal Energy
Regulatory Commission's (FERC) Order No. 636 and no longer has need for the
firm transportation service available under said agreement; AND
WHEREAS: TCO has sought to assign some or all of its capacity on WIC to
its customers consistent with Order No. 636, and has posted the availability of
said capacity on its Electronic Bulletin Board (EBB) as well as on WIC's EBB,
and has been unsuccessful in finding any party or parties desirous of taking
over TCO's entitlement; AND
WHEREAS: WIC is holding refunds related to past service for TCO as a
result of the settlement of WIC's rate case in FERC Docket No. RP85- 39 for the
period June 1, 1985 through August 31, 1991 which total approximately $15.4
million (including interest as of November 1, 1993); AND
WHEREAS: On March 17, 1994, WIC made a compliance filing pursuant to a
FERC order dated March 2, 1994 in Docket No. RP85-39-015 to flow back excess
deferred income tax amounts through monthly
<PAGE> 2
reservation charge credits to customer's invoices beginning with the March 1994
production month, based upon the historical throughput for the period 1982
through June 1987; AND
WHEREAS: TCO has not fully paid WIC's bills for the months of May, June
and July of 1991; AND
WHEREAS: WIC has filed a proof of claim against TCO in Case No. 91-804
pending in the United States Bankruptcy Court for the District of Delaware
(Claim No. 12097); and
WHEREAS: WIC has a gas imbalance with TCO which the parties agree is
71,623 MMBtu as of October 31, 1993, and which WIC will satisfy in the ordinary
course of business by paying for the gas at the rate of $1.71 per MMBtu, for a
total amount of $122,475.33.
IT IS HEREBY AGREED AS FOLLOWS:
1. WIC shall relieve TCO of its remaining contractual obligations
under the aforementioned Transportation Service Agreement in consideration of
the payment by TCO of $11,200,000 as an "Exit Fee" pursuant to FERC Order No.
636. TCO shall pay the Exit Fee, with interest commencing July 1, 1994 on the
net amount due after deducting the gross amount of the demand charges
referenced in Paragraph 5 below and the Exit Fee installments made pursuant to
this paragraph. TCO shall pay the Exit Fee over a period of no greater than one
year, which is the period over which TCO will propose to collect such amount
from its customers. Such payments shall commence at the time TCO commences
2
<PAGE> 3
recovery from its customers which shall be no later than 60 days after the
Approval Date. The "Approval Date" shall mean the date upon which this
Agreement is approved as to all of its terms, including specifically TCO's
right to fully recover the Exit Fee, with interest, from its customers, without
amendment or condition by both final FERC order(s), no longer subject to
rehearing, and by an order of the Bankruptcy Court. Such orders are referred
to herein as the "Approval Orders". Provided, however, that should any order
change, amend or condition this Agreement, the party adversely affected thereby
shall have the exclusive right to accept in writing any such change, amendment
or condition so that such order shall constitute an Approval Order and this
Agreement shall be given full force and effect.
2. TCO shall pay to WIC within ten (10) days after this Agreement
is approved by the Bankruptcy Court the amount of $810,537.34, without
interest, in final resolution of the dispute regarding service for the months
of May, June and July 1991 and any right of setoff for this amount under
Section 553 of the Bankruptcy Code. This amount is based upon the rates
actually billed for May, June and July of 1991. In the refund referenced in
Paragraph 4 below, the May, June and July invoices shall be treated as if paid
timely and in full. WIC's proof of claim (Claim No. 12097) shall be deemed
withdrawn without prejudice on the tenth day after the date of approval by the
Bankruptcy Court. WIC shall file no other claims in TCO's bankruptcy for the
period prior to November 1, 1993.
3
<PAGE> 4
3. WIC shall pay to TCO in the ordinary course of business within
ten (10) days after this Agreement is executed the amount of $122,475.33 for
resolution of the imbalances owed by WIC to TCO. Any other imbalances crated
after October 31, 1993, shall be handled in the ordinary course of business.
4. WIC shall pay to TCO within ten (10) days after the Approval
Date a refund, with interest, in Docket No. RP85-39, in an amount as finally
determined by FERC. Accordingly, also within ten (10) days after the Approval
Date, WIC's motion for relief from stay and to escrow funds shall be withdrawn
as moot.
5. For each production month beginning March 1994, WIC shall pay to
TCO the refunds of excess deferred income taxes as they become due and payable
in the amount and by the methods determined by FERC in Docket No. RP85-39-015,
et al. (including any recalculation, and refund, relating to the flowback of
deferred state income taxes subject to the outcome of the hearing in Docket No.
RP85-39-009). Provided, however, that within ten (10) days after the Approval
Date, WIC shall pay to TCO the then remaining amount of refunds of excess
deferred income taxes still due TCO in a lump sum with interest in the amount
as determined by final FERC order(s), no longer subject to rehearing or appeal,
in Docket No. RP85-39-015, et al. If the FERC order(s) in Docket No.
RP85-39-015, et al. are subject to rehearing or appeal as of the Approval Date,
WIC shall pay to TCO the remaining amount of refunds of excess deferred income
taxes still due TCO as finally determined by
4
<PAGE> 5
FERC in a lump sum with interest within ten (10) days after such order(s) are
final and not subject to further review.
6. TCO shall continue to make full and timely payment of the demand
charges due to WIC during the period that this Agreement is pending review as
set forth below. All sums submitted as demand charge payments (prior to
consideration of any amounts reflected as credits against demand charge
payments for excess deferred income taxes) beginning with payments for the
November 1993 billing month shall be credited to the amounts due WIC (including
interest from July 1, 1994) as the Exit Fee.
7. Except as set forth in this Agreement, WIC and TCO release and
waive any claims either party may have against the other relating to the period
prior to November 1, 1993.
8. This shall be a whole agreement and no provision, except for
Paragraphs 3 and 5, shall be severable from the totality of this Agreement.
9. This Agreement shall be effective as of the date of full
execution by both parties. Both parties shall use reasonable, good faith
efforts to obtain approvals from the Bankruptcy Court and FERC where such
approvals are required. This Agreement shall be of no other force and effect
(excepting also the provisions of Paragraphs 3 and 5) unless approved as to all
of its terms, without change, amendment or condition (unless any change,
amendment or condition is waived in writing by the party adversely affected
thereby), by Approval Orders. If any Court should reverse in whole or in part
an Approval Order, unless the parties agree in
5
<PAGE> 6
writing to the contrary, all monies paid by TCO to WIC under Paragraphs 1 and 2
and by WIC to TCO under Paragraph 4 (excepting also Paragraphs 3 and 5), plus
interest, shall be returned to TCO and WIC, respectively, the status quo ante
shall be restored and TCO shall pay to WIC all demand charges due for the
period after the Approval Date up to the date of reversal, and TCO and WIC
retain all rights to assert claims, objections and other rights to be resolved
by this Agreement.
10. Interest on all payments under this Agreement which require
interest shall be determined pursuant to the FERC's regulations at 18 C.F.R.
Section 154.102.
11. This Agreement shall be subject to approval by the Board of
Directors of CIG Gas Supply Company, the general partner of WIC.
12. This Agreement shall not be deemed an admission of any fact or
proposition of law, and shall not be used for any purpose other than to enforce
the terms of this Agreement.
ACCEPTED AND AGREED To this ACCEPTED AND AGREED To this
21st day of April, 1994. 26th day of April, 1994.
------------- ------------
COLUMBIA GAS TRANSMISSION WYOMING INTERSTATE COMPANY LTD.
CORPORATION
By: CIG GAS SUPPLY COMPANY,
General Partner
By: /s/ B. D. Perine
-----------------------
Senior Vice President
By: /s/ J. R. Whitney
------------------------
Vice President
6
<PAGE> 1
EXHIBIT 10-AD
IN THE UNITED STATES BANKRUPTCY COURT
FOR THE DISTRICT OF DELAWARE
In re THE COLUMBIA GAS SYSTEM, INC. and
COLUMBIA GAS TRANSMISSION CORPORATION,
Debtors. Case Nos. 91-803
91-804
Chapter 11
STIPULATION
WHEREAS, Natural Gas Pipeline Company of America (NGPL) and Columbia Gas
Transmission Corporation (TCO) are parties to certain agreements, as amended,
as listed on Exhibit A; and
WHEREAS, on April 8, 1992, the Federal Energy Regulatory Commission (FERC)
issued Order No. 636, as amended by subsequent Commission orders (Order No.
636) requiring, inter alia, restructuring of interstate pipeline rates and
services; and
WHEREAS, NGPL commenced implementation of Order No. 636 on its system on
December 1, 1993; and
WHEREAS, TCO implemented restructured services under Order No. 636 on
November 1, 1993 and does not require the Contracts and has been unable to
assign any of the capacity associated with Contract No. MS-27864-GN, a 56,500
MMBtu per day firm transportation contract, to its customers or other parties;
and
WHEREAS, TCO and NGPL wish to terminate the Contracts in consideration of
the agreements set out herein; and
WHEREAS, TCO and NGPL agree that the term "Excess Capacity" shall mean the
total amount of unassigned or capacity not required under Contract No.
MS-27864-GN as of the first day of the month following the effective date of
this
<PAGE> 2
Stipulation pursuant to Paragraph 8 herein; and
WHEREAS, TCO and NGPL have agreed to an exit fee (as has been contemplated
by Order No. 636) to be calculated as specified below (Exit Fee) in
consideration of TCO's abandonment of the Excess Capacity, which capacity is
not required as a result of TCO's implementation of Order No. 636; and
WHEREAS, TCO will use its Transportation Cost Rate Adjustment mechanism
(TCRA) to fully recover the Exit Fee from its customers pursuant to Order No.
636, which mechanism for such recovery was approved by the FERC by orders
issued on July 14, 1993 and September 29, 1993, in Docket Nos. RS92-5, et al.;
and
WHEREAS, NGPL filed a proof of claim against TCO on March 9, 1992, Claim
No. 8004, for $6,295,630.81 for transportation expense and gas imbalances,
which it amended on September 2, 1993, Claim No. 14488, for transportation
expense in the amount of $816,203.56. Claim No. 14494 is a duplicate of Claim
No. 14488.
WHEREAS, TCO and NGPL have agreed that the amount of transportation
expense under Claim No. 14488 is $816,203 which amount shall be an allowed
unsecured claim; and
WHEREAS, pursuant to the Bankruptcy Court's orders of September 20, 1991
and October 3, 1991, TCO is authorized to remedy pre-petition gas imbalances
under transportation and exchange agreements in the ordinary course of business
and TCO and NGPL will remedy any pre- and post- petition gas imbalances under
transportation and exchange agreements in the ordinary course of business; and
IT IS THEREFORE STIPULATED AND AGREED by the parties hereto as follows:
1. The Contracts are hereby terminated by agreement of the parties upon
the effective date of this Stipulation pursuant to Paragraph 8 herein, subject
to reinstatement as provided in said Paragraph 8; provided, however, that such
Contracts shall continue for a period not to exceed sixty (60) days solely to
2
<PAGE> 3
enable the parties to rectify any imbalances (it being understood that the Exit
Fee will commence notwithstanding such continuation of the Contracts and that
no demand payment shall be owed by TCO for any such period). Other than as
provided for in this Stipulation, each party hereby waives any claim for
damages thereunder for services rendered prior to the termination date, except
for (1) claims with respect to imbalances which shall be remedied in the
ordinary course of business pursuant to the Bankruptcy Court's orders of
September 20, 1991 and October 3, 1991 authorizing TCO to remedy gas
imbalances; (2) post-petition unpaid invoice claims which shall be satisfied in
the ordinary course of business as administrative expense claims under Section
503 of the Bankruptcy Code; (3) the right of NGPL to recover from TCO costs
which have been authorized by the FERC for service periods predating the
effective date of this Stipulation pursuant to Paragraph 8 herein; and (4) the
right of TCO to refunds from NGPL for overpayments made to NGPL, as determined
by the FERC, for services rendered to TCO by NGPL during periods which predate
the effective date of this Stipulation pursuant to Paragraph 8 herein.
2. Prior to the effective date of this Stipulation pursuant to Paragraph
8 herein, the Contracts will be fully or partially assignable to TCO's
customers and to other parties in accordance with Order No. 636, as it may be
amended, modified or superseded, and NGPL's and TCO's approved FERC Gas Tariff,
and subject to applicable laws, rules, regulations, and orders of applicable
regulatory authorities. Without limiting the foregoing, TCO shall have the
right prior to the date this Stipulation becomes effective to assign all or a
portion of the firm transportation capacity underlying the Contracts, on a
permanent basis in connection with TCO's and/or NGPL's restructuring under
Order No. 636 to one or more of TCO's customers or other parties which would be
eligible to
3
<PAGE> 4
receive service under NGPL's Tariff and NGPL agrees that any permanent full or
partial assignment(s) of capacity to an eligible shipper shall constitute an
assignment of the underlying Contracts pursuant to 11 U.S.C. Section 365(f).
Accordingly, upon permanent assignment of capacity by TCO to such customers or
other parties, TCO shall not, consistent with the provisions of 11 U.S.C.
Section 365(k), have any liability for "breach of such [contracts] occurring
after such assignment(s)" with respect to the assigned capacity; provided,
however, that nothing herein shall affect (1) the right of NGPL to recover from
TCO costs (a) which have been authorized by the FERC for service periods
predating the effective date of assignment of the underlying contract(s), and
(b) which are recoverable by NGPL from TCO, consistent with the terms of a FERC
order, during that portion of the FERC-approved recovery period predating the
effective date of assignment of the underlying contracts; and (2) the right of
TCO to refunds from NGPL for overpayments made to NGPL, as determined by the
FERC, for services rendered to TCO by NGPL during periods which pre-date the
effective date of assignment of the underlying contract(s).
3. Without limiting in any respect the provisions of Paragraph 2, TCO
shall, until the effective date of this Stipulation pursuant to Paragraph 8
herein, be entitled to the same rights and subject to the same obligations
under NGPL's tariff and FERC orders as all other customers of NGPL under the
same Rate Schedule.
4. NGPL shall have an allowed unsecured claim of $816,203 for Claim No.
14488, for pre-petition transportation expenses. NGPL's proofs of claim
against TCO (Claim Nos. 8004 and 14494) shall be deemed withdrawn and expunged
from the Claims Register, with prejudice, on the tenth day after the date of
approval by the Bankruptcy Court; provided, however, such proofs of claim are
subject to
4
<PAGE> 5
reinstatement by NGPL to the extent provided under Paragraph 8, as well as
TCO's concomitant rights to assert any objections to such proofs of claim.
5. Beginning the first day of the month following the date the
Stipulation becomes effective pursuant to Paragraph 8 herein, TCO shall pay
NGPL the Exit Fee, plus interest from the effective date of this Stipulation
pursuant to Paragraph 8 herein at the applicable FERC interest rate on the
remaining outstanding balance of the Exit Fee, based on a payment schedule
corresponding to TCO's collection of the Exit Fee, plus the aforesaid interest,
from its customers pursuant to the TCRA in consideration of the termination of
Contract MS-27864-GN. The Exit Fee principal amount shall be calculated using
the formula on Attachment A and using the Excess Capacity that exists as of the
first day of the month following the date the Stipulation becomes effective
pursuant to Paragraph 8 herein.(1)
6. TCO shall continue to make payments billed by NGPL relating to the
Contracts up to the effective date of this Stipulation pursuant to Paragraph 8
herein.
7. This Stipulation shall not be deemed an admission of any fact or
proposition of law, and shall not be used for any purpose other than to enforce
the terms of this Stipulation and the orders entered approving this Stipulation
as described in Paragraph 8. Notwithstanding the prior sentence, the parties
hereto shall be free to refer to and discuss this Stipulation for informational
purposes in any proceedings before the FERC or other courts and regulatory
bodies and in related discussions and negotiations.
- ----------------------------------
(1) Assuming a January 1, 1994 effective date and 56,500 MMBtu per
day of Excess Capacity, the Exit Fee would be $27,740,000 in
accordance with the Schedule on Attachment A. Assuming a January 1,
1995 effective date and 56,500 MMBtu per day of Excess Capacity, the
Exit Fee would be $25,457,071.
5
<PAGE> 6
8. This Stipulation shall not be effective until it is approved,
executed and entered by the Bankruptcy Court and until FERC issues a final
order, no longer subject to rehearing, approving this Stipulation, including,
specifically, authorization for TCO to fully recover the Exit Fee, with
interest, from its customers. A FERC order relating to the Exit Fee which
contains any provision or condition which would have a material adverse effect
on NGPL's ability to adjust its rates to reflect termination of Contract No.
MS-27864-GN shall not satisfy the prior sentence unless NGPL consents to such
order as constituting an order approving the Stipulation. TCO and NGPL agree
to use reasonable, good faith efforts to obtain approval from the Bankruptcy
Court and FERC where such approvals are required and to take all reasonable
steps necessary to assist the other in obtaining such approvals. Without
limitation of the prior sentence, NGPL agrees that it will actively support TCO
in its filing to recover the Exit Fee costs from its customers (which filing
may be in the form of a joint filing for approval of the Stipulation) and TCO
agrees that it will not take any position in NGPL's proceedings before FERC
which is adverse to NGPL with respect to disposition of the amounts received by
NGPL for the Exit Fee, NGPL's ability to adjust its rates to reflect
termination of the Contracts or adjustment of the volumes used in the design of
NGPL's rates to reflect termination of the Contracts. If any Court should
reverse in whole or in part the order of the Bankruptcy Court or the final
order of the FERC approving this Stipulation, unless the parties agree in
writing to the contrary, all monies paid by TCO to NGPL under Paragraph 5, plus
interest, shall be returned to TCO, the status quo ante shall be restored and
TCO and NGPL agree to pay all amounts due (e.g., demand charges, etc.) between
the effective date and the date of reversal, and TCO and NGPL retain all rights
to assert claims, objections and other rights are
6
<PAGE> 7
are to be resolved by this settlement, and no party can use this settlement as
evidence against TCO or NGPL. If, forty-five (45) days prior to the date first
set for the hearing on the confirmation of a plan of reorganization for TCO
(which plan has been distributed for voting purposes) (the "Notification
Date"), the Bankruptcy Court has entered an order and the FERC has issued a
final order approving this Stipulation, no longer subject to rehearing, but
either or both of such orders are subject to review on appeal, TCO may elect to
assume the obligations arising under this Stipulation and the Contracts
post-confirmation by notifying NGPL of its decision in writing within five (5)
business days following the Notification Date. In the event TCO does not
exercise the option described above in the time prescribed herein, this
Stipulation shall be treated as if either the order of the Bankruptcy Court or
the final order of FERC approving this Stipulation has been reversed on appeal
and the parties shall be returned to the status quo ante. NGPL and TCO shall
have all of their respective rights under the Bankruptcy Code and other
applicable law, including, without limitation, TCO's right to reject the
Contracts and NGPL's right to file claims arising out of any rejection of the
Contracts and to seek allowance and payment of such claims.
Dated: May 24, 1994
------------------------
NATURAL GAS PIPELINE COMPANY COLUMBIA GAS TRANSMISSION
OF AMERICA CORPORATION
By: /s/ James A. Brett By: /s/ B. D. Perine
------------------------- ----------------------
Its: Vice President Its: Senior Vice President
------------------------ ----------------------
7
<PAGE> 1
EXHIBIT 10-AE
CERCLA
ORDER
<PAGE> 2
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGIONS II, III, IV, and V
IN THE MATTER OF: :
:
COLUMBIA GAS PIPELINE :
:
Columbia Gas Transmission :
Corporation, : Docket No.
:
Respondent : III-94-35-DC
:
:
Proceeding Under Sections 104, :
106(a), and 122(a) of the :
Comprehensive Environmental :
Response, Compensation, and :
Liability Act of 1980, as amended :
by the Superfund Amendments and :
Reauthorization Act of 1986, :
42 U.S.C. sections 9604, 9606(a), :
and 9622(a) :
ADMINISTRATIVE ORDER BY CONSENT
FOR REMOVAL ACTIONS
<PAGE> 3
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGIONS II, III, IV, and V
IN THE MATTER OF: :
:
COLUMBIA GAS PIPELINE :
:
Columbia Gas Transmission :
Corporation, : Docket No.
:
Respondent : III-94-35-DC
:
:
Proceeding Under Sections 104, :
106(a), and 122(a) of the :
Comprehensive Environmental :
Response, Compensation, and :
Liability Act of 1980, as amended :
by the Superfund Amendments and :
Reauthorization Act of 1986, :
42 U.S.C. sections 9604, 9606(a), :
and 9622(a) :
ADMINISTRATIVE ORDER ON CONSENT
FOR REMOVAL ACTIONS
The parties to this Administrative Order on Consent ["Consent Order"],
Columbia Gas Transmission Corporation ["Respondent"] and the United States
Environmental Protection Agency ["EPA"], having agreed to the entry of this
Consent Order, it is therefore Ordered, that:
I. JURISDICTION/GENERAL PROVISIONS/DEFINITIONS
1.1 This Consent Order is issued pursuant to the authority vested in the
President of the United States by sections 104, 106(a), and 122(a) of
the Comprehensive Environmental Response, Compensation, and Liability
Act of 1980, as amended by the Superfund Amendments and
Reauthorization Act of 1986 ["CERCLA"], 42 U.S.C. sections 9604,
9606(a), and 9622(a), delegated to the Administrator of EPA by
Executive Order No. 12580, 52 Fed. Reg. 2923 (January 29, 1987), and
further delegated to the Regional Administrators of EPA. This Consent
Order pertains to numerous properties associated with Respondent's
natural gas pipeline system in Ohio, Kentucky, Pennsylvania, Virginia,
West Virginia, New York, North Carolina, Maryland, New Jersey, and
Delaware. For purposes of this Consent Order, the relevant properties
will hereinafter be referred to as the "Site" and are further
identified in Section 3.3 of this Consent Order.
<PAGE> 4
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 2
1.2 This Consent Order is entered into by EPA and by Respondent a Debtor
in Possession. Except as expressly provided in Section 24.1 of this
Consent Order, Respondent's obligations under this Consent Order are
conditioned upon a grant of authority to Respondent by the United
States Bankruptcy Court for the District of Delaware (Case No.
91-804). The Order of the United States Bankruptcy Court granting
Respondent such authority will be appended hereto as Appendix A to
this Consent Order.
1.3 The Respondent agrees to undertake all actions required by, and comply
with all requirements of, this Consent Order, including any
modifications hereto.
1.4 All work performed pursuant to this Consent Order must be consistent
with CERCLA and the National Oil and Hazardous Substances Pollution
Contingency Plan, as amended ["NCP"], 40 C.F.R. Part 300.
1.5 The Respondent consents to and will not contest EPA's authority or
jurisdiction to issue or to enforce this Consent Order. Respondent
further agrees that it will not contest the basis or validity of this
Consent Order or its terms.
1.6 Definitions. Unless otherwise expressly provided herein, terms used
in this Consent Order which are defined in CERCLA or the NCP shall
have the meaning assigned to them in CERCLA or the NCP. Whenever the
terms identified below are used in this Consent Order or in any
appendix attached hereto, the following definitions shall apply:
(a) "Business Days" shall mean every day of the week except
Saturdays, Sundays and federal holidays.
(b) "Calendar Days" shall mean every day of the week, including
Saturdays, Sundays and federal holidays.
(c) "Days" shall mean "calendar days" unless specified otherwise.
(d) "Columbia Gas Pipeline Site" or "Site" shall mean those
locations described in Section 3.3 of this Consent Order.
(e) "Characterization Report" shall mean the report to be
submitted for EPA approval for each location included in the
Work Scope List pursuant to Section 8.6 of this Consent Order.
(f) "Characterization Work Plan" or "CWP" shall mean the plan,
developed pursuant to Section 8.6(b) of this Consent Order,
which describes the manner in which each
<PAGE> 5
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 3
and every Characterization Report required by this consent
Order will be prepared.
(g) "EPA" shall mean Regions II, III, IV, and V of the United
States Environmental Protection Agency. EPA Region III shall
act for EPA in all matters regarding this Consent Order.
(h) "Response Action Work Plan" or "RAWP" shall mean
the plan, developed pursuant to Section 8.8(b) of this Consent
Order, which describes the manner in which the response action
selected by EPA for implementation under this Consent Order at
a particular location included in the Work Scope List will be
performed.
(i) "Work Scope List" shall mean the EPA-approved list, developed
pursuant to Section 8.2 of this Consent Order, of locations
within the Columbia Gas Pipeline Site for which
Characterization Reports must be submitted for EPA approval
and, where appropriate, response actions selected by EPA must
be performed by Respondent.
II. STATEMENT OF PURPOSE
2.1 In entering into this Consent Order, the mutual objectives of EPA and
Respondent are to conduct removal actions, as defined in section
101(23) of CERCLA, 42 U.S.C. section 9601(23), to abate, mitigate,
and/or eliminate the release, or threat of release, of hazardous
substances, pollutants, and contaminants at the Site by (a)
characterizing the nature and extent of such hazardous substances,
pollutants, and contaminants, and (b) performing such actions as EPA
deems necessary to prevent actual and threatened releases of such
hazardous substances, pollutants, and contaminants into the
environment from the Site.
2.2 Respondent operates an interstate natural gas pipeline system subject
to the jurisdiction of the Federal Energy Regulatory Commission under
the Natural Gas Act, 15 U.S.C. section 717 et seq., and maintains that
it has various public service responsibilities and commitments
pursuant to this statute. Subject to EPA approval, Respondent intends
to conduct the work required by this Consent Order in a manner that
will avoid impeding its ability to operate and maintain its pipeline
system in the normal course of its business and avoid interruption or
diminishment of its operational ability to deliver natural gas to its
customers, and enable it to continue or expand its normal business
operations to meet its operational and contractual requirements
through actions including, without limitation, installation of new
pipelines; operation and
<PAGE> 6
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 4
maintenance; repair, removal, or replacement of pipe and equipment;
and other activities related to operation of the pipeline system.
Notwithstanding the above, nothing in this provision shall relieve
Respondent from performing any action required by this Consent Order.
III. EPA'S FINDINGS OF FACT
Columbia Gas Pipeline & the
Columbia Gas Pipeline Site
3.1 Respondent Columbia Gas Transmission Corporation is a corporation
incorporated under the laws of the State of Delaware.
3.2 Respondent and/or its predecessors have operated a natural gas
pipeline system in the northeastern quadrant of the United States
since the 1890's. Respondent currently operates approximately 19,000
miles of pipeline and approximately 225 active or retired compressor
stations in Pennsylvania, New York, North Carolina, New Jersey,
Maryland, Kentucky, Ohio, Virginia, West Virginia, and Delaware.
Respondent's pipeline is interconnected with other natural gas
transmission pipelines and has been used in the past to transport
natural gas owned by other companies as well as natural gas owned by
Respondent.
3.3 (a) For purposes of this Consent Order, the Columbia Gas Pipeline
Site includes all locations described in this subparagraph
that are further described in subparagraph (b):
(1) the natural gas pipeline;
(2) compressor stations, including compressed air systems;
(3) liquid removal points along the natural gas pipeline
system (i.e., all locations where pipeline liquids
are removed);
(4) current and former mercury metering stations;
(5) storage wells and related operations;
(6) natural gas flare sites;
(7) drum storage areas;
(8) vent stacks;
<PAGE> 7
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 5
(9) maintenance facilities;
(10) lubricating oil storage tanks, including loading and
unloading areas;
(11) natural gas scrubbers;
(12) electrical equipment that has at any time been filled
with oil;
(13) roads that were or may have been sprayed with oil for
dust suppression;
(14) fence lines that were or may have been sprayed with
oil for weed control; and
(15) other locations not described in (1) - (14), above.
(b) For purposes of this Consent Order, the Columbia Gas Pipeline
Site consists of all locations described in subparagraph (a)
of this Section that are:
(1) presently owned or operated by Respondent in
Pennsylvania, New York, North Carolina, New Jersey,
Maryland, Kentucky, Ohio, Virginia, West Virginia and
Delaware, and
(2) are required to be identified by Respondent pursuant
to Section 8.2 of this Consent Order.
(c) For purposes of this Consent Order, Respondent maintains that
its past operating practices as hereinafter described were
consistent with industry practices at the time of their
occurrence.
Natural Gas Compressors, Liquid Removal Points,
Storage Tanks, and Trash Disposal/Burn Areas
3.4 Natural gas compressors are and have been used in Respondent's
pipeline to increase pressure within the pipeline to facilitate
transportation of natural gas to Respondent's customers.
3.5 Lubricating oil is and has been used in natural gas compressors at
Respondent's pipeline as well as at other pipelines to which
Respondent's pipeline is connected. During the course of ordinary
operation of the pipeline, lubricating oil has migrated into
Respondent's pipeline.
3.6 Prior to 1976, polychlorinated biphenyls (PCBs) were widely used by
industry in lubricating oils for electrical equipment and hydraulic
systems. PCBs were used as insulating fluids
<PAGE> 8
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 6
because of their exceptional heat transfer characteristics.
3.7 Portions of Respondent's pipeline, including natural gas compressors,
have become contaminated with PCBs. Respondent maintains that these
PCBs have been introduced into its pipeline system as a result of
interconnections with natural gas transmission pipelines of other
companies that used lubricating oil containing PCBs. Respondent
maintains that it did not use PCB lubricating oils in its natural gas
compressors.
3.8 As a result of normal pressure and temperature changes within
Respondent's pipeline, constituents contained in natural gas can
condense into a liquid form within the pipeline. This liquid, or
condensate, may contain, among other things, benzene, toluene, and
xylene. The condensate may additionally contain PCB-contaminated
lubricants that have entered the pipeline. Condensates must be
removed to avoid damage to the gas compressors.
3.9 Condensate is and has been removed from Respondent's pipeline through
numerous liquid removal points at various locations along the pipeline
system. The most common type of liquid removal point consists of a
liquid trap attached to the pipeline and a length of small-diameter
pipe with an aboveground valve. Respondent's pipeline includes
approximately 15,000 liquid removal points where condensates are
currently being removed or were removed in the past.
3.10 An unknown volume of condensate, including PCB-contaminated
condensate, removed from Respondent's pipeline was disposed by
Respondent onto the ground at liquid removal points at various
locations along the pipeline system. As a result of this practice, an
unknown volume of soils at one or more locations along the pipeline
system has likely become contaminated with, among other things, PCBs,
benzene, toluene, and xylene.
3.11 An unknown volume of condensate, including PCB-contaminated
condensate, removed from Respondent's pipeline was stored by
Respondent in aboveground and underground storage tanks at various
locations along the pipeline system. As a result of spillage and
leakage of such condensate during handling, an unknown volume of soils
at one or more locations along the pipeline system in the vicinity of
these aboveground and underground storage tanks has become
contaminated with, among other things, PCBs, benzene, toluene, and
xylene.
3.12 An unknown volume of condensate, including PCB-contaminated
condensate, removed from Respondent's pipeline was disposed of by
Respondent in trash disposal and burn areas at one or more locations
along the pipeline system. As a result of this
<PAGE> 9
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 7
practice an unknown volume of soils in the vicinity of certain of
these trash disposal and burn areas has become contaminated with,
among other things, PCBs, benzene, toluene, and xylene.
Air Compressors
3.13 Air compressor systems are and have been used at Respondent's
pipeline to supply starting and instrument air to control valves,
switches, and other devices. Lubricating oil is and was used in these
air compressor systems. In the past, Respondent used lubricating oil
containing PCBs in a number of such air compressors.
3.14 During Respondent's ordinary operation of a number of the air
compressor systems, PCB-contaminated lubricating oil migrated into air
receiving tanks together with condensed water vapor and compressed
air. This liquid was removed from the air receiving tanks by
Respondent from time to time through drainage valves located
underneath the tanks. An unknown quantity of liquid, including PCB-
contaminated oil, was released from air compressor systems at various
locations along Respondent's pipeline system directly onto the ground
by Respondent. This activity has caused an unknown volume of soil in
the vicinity of some of Respondent's air compressor systems to become
contaminated with PCBs.
Mercury-Filled Instruments
3.15 There are approximately 3,000 locations along Respondent's pipeline
where mercury-filled metering devices are or were used to measure
pipeline flow and pressure. Routine maintenance activities performed
on these devices has resulted in drips and spills of mercury from a
number of these devices onto the ground in the vicinity of these
devices. An unknown volume of soil in the vicinity of a number of
these instruments has become contaminated with mercury.
Previous Site Assessments
3.16 Respondent has commenced assessments at numerous active and former
compressor stations and other locations along its pipeline in several
states. These assessments, some of which have been performed under
agreement with states in which the stations are located, are intended
to characterize the extent of contamination along Respondent's
pipeline. Respondent has provided EPA with numerous assessments of
such locations. Respondent believes these assessments are
representative of many locations to be included within the
EPA-approved Work Scope List described in Section 8.2 of this Consent
Order and that similar contamination will likely be found at various
<PAGE> 10
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 8
concentrations at many of the locations included in that list.
Assessments provided to EPA by Respondent reveal, among other things,
the following:
(a) Downingtown Compressor Station (PA - 1992 Data) - PCBs at
21.25 and 84.5 ppm were discovered in soil samples in Surplus
Material Storage Area #2. Mercury at 14 ppm was discovered in
a soil sample in the Meter Building. In addition, Petroleum
Hydrocarbon contamination and low level PCB contamination was
found in soils in other areas of the station.
(b) Donegal Compressor Station (PA - 1992 Data) - Mercury at
levels of 150 ppm and 1100 ppm was discovered in the soil at
the entrances to the Meter Building. Petroleum Hydrocarbons
were found in the North and South Former Disposal Pits and
PCBs were found at 0.24 ppm in the North Former Disposal Pit.
According to the assessment, the Respondent's on-site
geologist noticed a strong petroleum odor at the 8 foot depth
in the South Pit.
(c) Boldman Compressor Station (KY - 1989 Data) - PCBs at 20,500
ppm were discovered in the pipe chase of the auxiliary
building. Outdoor soil samples showed PCBs at 39 ppm. The
facility also used PCBs in the air compressor systems above 50
ppm and this use has resulted in instances of surface
contamination in the auxiliary building and soil contamination
near the air receiver tanks.
(d) Gala Compressor Station (VA - 1991 Data) - PCBs at 235,000 ppm
were discovered in the soil in a pit where the air compressor
systems were blown down. The assessment claims these
compressors (which were contaminated with PCBs) were blown
down to the ground every three to four hours. PCBs at 76.5
ppm were discovered in the sediment of the auxiliary building
sump.
(e) Guernsey Compressor Station (OH - 1991 Data) - Sampling at the
station indicated PCBs at levels of 210,000 ppm in the soil in
the engine room sump drainage area. PCBs at 1,020 ppm were
also discovered in soil near a drain pipe discharge. The soil
beneath the air compressor blowdown showed 1,090 ppm PCBs,
and a soil sample in the waste oil storage tank showed 454
ppm.
(f) Wellington Compressor Station (OH - 1991 Data) - Sediment
samples in the sumps of the Main and Auxiliary Buildings
showed PCB levels of 28 ppm, 14,300 ppm and 95,500 ppm. Soil
samples in the areas of the air compressor blowdowns
<PAGE> 11
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 9
showed 174 ppm and 11,300 ppm PCBs. A soil sample near a
drainline overflow showed 13 ppm PCBs.
(g) Terra Alta Compressor Station (WV - 1991 Data) - Sediment
samples in the sumps of the compressor and auxiliary buildings
showed PCB levels of 16,500 ppm and 5,200 ppm. Soil samples
adjacent to the Cistern and the gas compressor exhaust vents
showed PCB levels of 46,500 ppm and 33,200 ppm.
(h) Cleveland Compressor Station. (WV - 1990 Data) - Sampling at
the station indicated PCBs in use in an air compressor at
levels above 50 ppm. Soil samples in the auxiliary building
showed PCB levels of 1120 ppm to 8500 ppm. Other outdoor soil
samples showed PCB levels of 29 ppm, 34 ppm, 148 ppm, 219 ppm,
and 631 ppm.
(i) Flat Top Compressor Station (WV - 1992 Data) - Sampling at the
station indicated PCBs in use in two air compressors at levels
of 2.8 ppm and 1.1 ppm. Liquids in the Air Receiver Tanks had
PCBs at 162 ppm and 108 ppm. PCBs were also found at 556 ppm
and 17,500 ppm in the auxiliary building pipe chase. PCBs
were found at 55,900 ppm and 99,500 ppm in the soil below both
Air Receiver Tanks. PCBs were found at 261 ppm, 11 ppm, 300
ppm, and 16 ppm in the soil/sediment near the pond area. PCBs
were found in the marsh area in soil at 520 ppm. Historical
use of a Burn Pit was reported. Soil samples provided the
following:
- 2 to 3' depth - 7 ppm;
- 3 to 4' depth - 2 ppm and 46 ppm
- 4 to 5' depth - 4 ppm
- 5 to 6' depth - < 2 ppm
- 6 to 7' depth - 690 ppm
- 7 to 8' depth - 44 ppm
- 8 to 9' depth - 20 ppm
(j) South Point Compressor Station (RETIRED) (OH - 1991 and 1992
Data) - Assessment stated that the facility was decommissioned
in 1976. Two burn pits and three Underground Storage Tanks
were used at the site and remain there. The two burn pits (4'
x 10' x 3' deep) were used to incinerate waste oil, oil soaked
trash, general garbage, and pipeline fluids. Respondent
discontinued use of these burn pits in the late 1960's. Wipe
samples detected PCBs on surfaces in the Auxiliary building.
Floor drain sediment showed 142 ppm PCBs. In the outdoor
areas, soil samples showed PCBs at the following levels: 0.51
ppm near 2000 gal UST, 31.7 ppm near old Air Receiver Tank,
6.43 ppm near former
<PAGE> 12
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 10
scrubber, 17.6 ppm near former drum storage area, and 28,200
ppm near former burn pit.
3.17 Benzene, toluene, xylene, mercury, and PCBs are hazardous substances
that may have adverse effects on human health and the environment and
are listed at 40 C.F.R. section 302.4.
3.18 Based on the information set forth in this Section, EPA hereby
determines that a threat to public health, welfare, and the
environment exists due to the actual or threatened release of
hazardous substances, pollutants, or contaminants into the environment
from the compressor stations identified in section 3.14 of this
Consent Order. EPA hereby additionally determines that the actual
and/or threatened release of hazardous substances from the compressor
stations identified in Section 3.16 and the Columbia Gas Pipeline Site
may present an imminent and substantial endangerment to the public
health or welfare or the environment.
IV. CONCLUSIONS OF LAW
4.1 For purposes of this Consent Order, the Columbia Gas Pipeline Site is
a "facility" as defined by section 101(9) of CERCLA, 42 U.S.C.
section 9601(9).
4.2 The Respondent is a "person" as defined by section 101(21) of CERCLA,
42 U.S.C. section 9601(21).
4.3 PCBs, mercury, benzene, toluene, and xylene are hazardous substances
within the meaning of section 101(14) of CERCLA, 42 U.S.C. section
9601(14), and are listed at 40 C.F.R. section 302.4.
4.4 "Hazardous substances," as defined in section 101(14) of CERCLA, 42
U.S.C. section 9601(14), have been disposed of at various locations
along the Site and are currently present there.
4.5 The presence of hazardous substances at various locations along the
Site and the past, present, and/or potential migration of hazardous
substances from the Site constitutes an actual and/or threatened
"release" as defined in section 101(22) of CERCLA, 42 U.S.C. section
9601(22).
4.6 Respondent is an "owner" and/or "operator" of a "vessel or a facility"
(the Site) within the meaning of section 107(a)(1) of CERCLA, 42
U.S.C. section 9607(a)(1), from which there is a release and/or a
threat of a release of hazardous substances into the environment
within the meaning of section 107(a) of CERCLA, 42 U.S.C. section
9607(a).
<PAGE> 13
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 11
V. DETERMINATIONS
Based on the Findings of Fact and Conclusions of Law set forth above,
and upon EPA's review of information, including that furnished by Respondent,
EPA has determined that:
5.1 The actual and/or threatened release of hazardous substances from the
Site may present an imminent and substantial endangerment to the
public health or welfare or the environment.
5.2 The work required by this Consent Order is necessary to protect the
public health and welfare and the environment.
5.3 Because there is a threat to public health or welfare or the
environment, a removal action is appropriate to abate, minimize,
stabilize, mitigate, or eliminate the release or threat of release of
hazardous substances at or from the Site.
VI. PARTIES BOUND
6.1 This Consent Order shall apply to and be binding upon EPA and its
successors and agents, and upon Respondent and its agents, successors,
and assigns. Neither a change in ownership or corporate or
partnership status of the Respondent, nor a change in ownership or
control of all or any portion of the Site, shall in any way alter
Respondent's responsibilities under this Consent Order.
6.2 In the event of any change in ownership or control of the real
property, or of any temporary building or structure, or portion
thereof, included on the Work Scope List developed pursuant to Section
VIII of this Consent order or removed from the Work Scope List
pursuant to Section 8.7 of this Consent Order, Respondent shall notify
EPA in writing at least thirty (30) calendar days in advance of such
change and shall provide a copy of this Consent Order to the
transferee in interest of such property prior to any agreement for
transfer.
6.3 The Respondent shall provide a copy of this Consent Order to all
contractors, laboratories, and consultants retained by Respondent to
conduct any portion of the work to be performed by Respondent pursuant
to this Consent Order. Respondent shall require in any and all
contracts related to this Site that the work that is the subject of
such contract be performed within the time and in the manner set forth
in this Consent Order.
6.4 The undersigned representative of Respondent certifies that he or she
is fully authorized to enter into the terms of this
<PAGE> 14
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 12
Consent Order and to execute and legally bind Respondent to this
Consent Order.
VII. NOTICE TO THE STATES
7.1 Notice of issuance of this Consent Order has been given by EPA to the
Commonwealths of Pennsylvania, Virginia, and Kentucky, and the States
of New York, North Carolina, New Jersey, Maryland, Ohio, West Virginia
and Delaware pursuant to section 106(a) of CERCLA, 42 U.S.C. section
9606(a).
VIII. WORK TO BE PERFORMED
8.1 Respondent shall commence and complete performance of the following
work as specified herein. Respondent and EPA presently anticipate,
subject to EPA approval of schedules and plans to be submitted
pursuant to this Consent Order, that the work to be performed under
this Section VIII may require approximately twelve years from the
effective date of this Consent Order to complete. Respondent
presently estimates that such work will entail expenditures of
approximately $15 million to $20 million annually.
8.2 Delineation of Work Scope.
(a) For purposes of this Consent Order, the Columbia Gas Pipeline
Site shall include all locations which are required to be
identified by Respondent pursuant to this Section. Respondent
may voluntarily recommend for EPA approval other locations to
be included.
(b) Within thirty (30) days after the effective date of this
Consent Order, Respondent shall submit to EPA for approval in
accordance with Section IX of this Consent Order a list of all
locations identified in Section 3.3(a) of this Consent Order
which are required herein to be identified under this Consent
Order. Respondent may identify specific locations by address
or by delineating categories (e.g., all liquid removal points
within the Commonwealth of Pennsylvania). Respondent is
required to identify in such list the following:
(1) all compressor stations identified in Section 3.16 of
this Consent Order, as well as all compressor
stations, liquid removal points, current and former
mercury metering stations, and other locations
identified in Section 3.3(a) of this Consent Order
where Respondent has documented the release or
threatened release of hazardous substances, pol-
<PAGE> 15
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 13
lutants, or contaminants into the environment through
data collection efforts commenced prior to the
effective date of this Consent Order; and
(2) all compressor stations, liquid removal points,
current and former mercury metering stations, and
other locations identified in Section 3.3(a) of this
Consent Order where Respondent has reason to believe
that hazardous substances, pollutants, or
contaminants have been, or may be, released into the
environment.
For purposes of Paragraph (b)(1) of this section,
documentation of a release or threatened release of hazardous
substances, pollutants, or contaminants into the environment
shall be presumed if Respondent has documented contamination
at or above levels identified for the appropriate category
(e.g., worker soil ingestion, resident soil ingestion) in the
removal guidelines appended hereto as Appendix B of this
Consent Order, but shall not be limited to such instances.
For each location that Respondent does not identify for
inclusion under this Consent Order because it has documented
contamination above detection limits but below the levels
corresponding to the Appendix B category used in its
evaluation, Respondent shall identify and justify the category
used. In the event EPA determines that Respondent's selection
of an Appendix B category was inappropriate for a particular
location, EPA may require that Respondent use a different
category in evaluating such location for inclusion under this
Consent Order.
(c) The list submitted pursuant to Section 8.2(b) which is
approved by EPA shall be referred to as the "Work Scope List"
and shall be enforceable under the terms of this Consent
Order. Approval by EPA of the Work Scope List shall not
constitute a waiver of EPA's rights, including the right to
seek penalties and to otherwise enforce this Consent Order,
for Respondent's failure to identify a location identified in
Section 3.3(a) of this Consent Order where Respondent has
either documented the release or threatened release of
hazardous substances, pollutants, or contaminants into the
environment or has reason to believe such a release or
threatened release may exist.
(d) EPA and Respondent may modify the Work Scope List at any time.
Any such modification shall be in writing, shall be signed by
the Project Coordinators for EPA and Respondent, and shall
have as its effective date the date on which such modification
is signed by the EPA Project
<PAGE> 16
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 14
Coordinator.
8.3 Use of Existing Data. Data or information collected prior to the
effective date of this Consent Order may be submitted by Respondent in
an effort to satisfy any requirement of this Consent Order. Any such
data or information shall be certified in accordance with Section 8.12
of this Consent Order. EPA reserves the right to disapprove any
document submitted or work performed under this Consent Order if,
among other reasons, EPA determines, in its sole discretion, that (1)
the document or work relied in any way on data or information
collected prior to the effective date of this Consent Order, and (2)
that such data or information is invalid, inaccurate, incomplete, or
otherwise deficient. In any such event, the data may be supplemented,
augmented, or otherwise amended in accordance with procedures agreed
to by Respondent and EPA.
8.4 Passive Screening Assessments (Based on Existing Data).
(a) Within one hundred and eighty (180) days after EPA has
approved the Work Scope List, Respondent shall provide to EPA
for approval an assessment, based on information and data
obtained prior to the effective date of this Consent Order, of
each location, or group of locations as specified in paragraph
(c) of this Section, identified in the Work Scope List for
which Respondent contends that no further investigation or
cleanup is warranted under this Consent Order. Each
assessment shall be certified in accordance with Section 8.12
of this Consent Order. Respondent shall not submit an
assessment under this Section for any location where
Respondent has documented contamination at or above the
removal guidelines set forth for the appropriate category in
Appendix B of this consent Order and taken no action to
respond to such contamination.
(b) EPA will determine, based on each such submission, whether
further investigation or cleanup under this Consent Order is
warranted for each location, or group of locations, identified
by Respondent pursuant to Section 8.4(a) of this Consent
Order. In the event EPA agrees that a particular location or
group does not warrant further investigation or cleanup under
this Consent Order, such location or group will be removed
from the Work Scope List and Respondent shall not be obligated
by this Consent Order to take any further action with respect
to such location or group.
(c) For purposes of this Section 8.4, Respondent may group two or
more liquid removal points in an assessment, two or more
mercury metering stations in an assessment, and
<PAGE> 17
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 15
two or more storage well locations in an assessment, provided
that Respondent identifies the methodology and rationale used
in grouping such locations together. Respondent may not group
any other locations for purposes of complying with this
Section. EPA reserves the right to disapprove any grouping.
8.5 Active Screening Assessments (For Liquid Removal Points,
Mercury Metering Stations, and Storage Well Locations).
(a) Respondent shall submit to EPA for approval an Active
Screening Assessment Report for each liquid removal point (or
group of liquid removal points), current and former mercury
metering station (or group of stations), and storage well
location (or group of storage well locations) on the Work
Scope List, and which is not removed from the Work Scope List
by EPA pursuant to Section 8.4 of this Consent Order, for
which Respondent contends that no further investigation or
cleanup is warranted under this Consent order. Each such
Active Screening Assessment Report shall be prepared within
the time and in the manner set forth in this Section.
Respondent may group two or more liquid removal points in a
report, two or more mercury metering stations in a report, and
two or more storage well locations in a report, provided that
Respondent identifies the methodology and rationale used in
grouping such locations together. EPA reserves the right to
disapprove any such grouping. Respondent anticipates that
completion of all work required by this Section 8.5 will
require approximately eighteen (18) months from the effective
date of this Consent Order.
(b) Active Screening Assessment Work Plan.
(1) Contractor Selection. Within seven (7) days of the
effective date of this Consent Order, Respondent
shall notify EPA in writing of the identity and
qualifications of the contractor selected by
Respondent to prepare the Active Screening Assessment
Work Plan ["ASAWP"]. EPA will notify Respondent in
writing of EPA's acceptance or disapproval of
Respondent's selected contractor as soon as
practicable following receipt of Respondent's
selection. In the event EPA disapproves Respondent's
selection, Respondent shall, within seven (7) days of
its receipt of such notice, notify EPA of the
identity and qualifications of the contractor who
will replace the contractor that has been disapproved
by EPA. Acceptance/disapproval of Respondent's
selected replacement contractor(s) shall be governed
by the preceding two sentences. Respon-
<PAGE> 18
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 16
dent shall additionally notify EPA of the identity
and qualifications of any additional contractors and.
all subcontractors and supervisory personnel that
will be used to prepare the ASAWP not less than seven
(7) days before any such contractor, subcontractor,
or supervisory personnel is scheduled to perform such
work. EPA may at any time disapprove the use of any
contractor, subcontractor, or supervisory personnel
EPA considers to be unqualified or otherwise unable
to perform the work, or to continue to perform the
work, required by this Consent Order. In the event
of any such disapproval, Respondent shall, within
seven (7) days following receipt of such notice,
notify EPA of the identity and qualifications of the
contractor, subcontractor, or supervisory personnel
that will replace the one(s) EPA has disapproved.
(2) Active Screening Assessment Work Plan Development.
Within sixty (60) days following EPA acceptance of
the contractor who will prepare the ASAWP, Respondent
shall submit for EPA approval an ASAWP that sets
forth the manner in which Respondent will assess each
location, or group of locations, for which Respondent
contends that no further investigation or cleanup is
warranted under this Consent Order. The ASAWP shall
include, but shall not be limited to:
(a) the methodology and rationale that will be
used by Respondent to group liquid removal
points, current and former mercury metering
stations, and storage well locations for
purposes of preparing Active Screening
Assessment Reports;
(b) a strategy for collection of the data
(including visual observation at each and
every individual location to be included
within the Active Screening Assessment Report
and sampling data) to be included in the
Active Screening Assessment Reports and for
identification of all ecological zones and
receptors actually or potentially affected by
contamination at each location, or group of
locations, and the laboratory testing methods
to be used to evaluate impacts to biological
systems;
(c) a general sampling and analysis plan
(including a Field Sampling Plan, a Quality
Assurance Project Plan, and a plan to sample
all
<PAGE> 19
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 17
drinking water wells that are potentially
impacted by contamination at each location)
that (1) describes the manner in which
Respondent will obtain data for each liquid
removal point, mercury metering station, and
storage well location that will be sampled
(e.g., sampling techniques and analytical
methodologies), and (2) provides a protocol
for addressing unique conditions not covered
by the general plan;
(d) a health and safety plan to protect the
health and safety of workers, other
personnel, and the public from the hazardous
substances and work-related health and safety
hazards during performance of the work
required by this Consent Order and which
provides for proper decontamination of
personnel and equipment, monitoring and
control of off-site migration of hazardous
substances from the Site, and protection of
public health from overexposure to hazardous
substances during the performance of
activities at the Site pursuant to this
Consent Order. Applicable sections of the
plan shall be at least as stringent as the
occupational Safety and Health Administration
and EPA requirements including those set
forth in 29 C.F.R. section 1910.120;
(e) a preliminary listing and discussion of
applicable and relevant and appropriate
requirements ["ARARs"]; other advisories,
criteria, and guidance to be considered
pursuant to section 300.400(g)(3) of the NCP,
40 C.F.R. section 300.400(g)(3) ["TBCs"];
and such other Federal and State cleanup
standards as may be applicable at the time;
and
(f) a schedule for expeditious completion of an
Active Screening Assessment Report for each
location, or group of locations, Respondent
seeks to eliminate from the Work Scope List
under this Section.
(c) Active Screening Assessment Work Plan Implementation.
(1) Contractor Selection. Within seven (7) days of EPA
approval of all or a discrete portion of the ASAWP,
Respondent shall notify EPA in writing of the
identity and qualifications of the contractor
selected by Respondent to implement the ASAWP. EPA
will
<PAGE> 20
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 18
notify Respondent in writing of EPA's acceptance or
disapproval of Respondent's selected contractor as
soon as practicable following receipt of Respondent's
selection. In the event EPA disapproves Respondent's
selection, Respondent shall, within seven (7) days of
its receipt of such notice, notify EPA of the
identity and qualifications of the contractor who
will replace the contractor that has been disapproved
by EPA. Acceptance/disapproval of Respondent's
selected replacement contractor(s) shall be governed
by the preceding two sentences. Respondent shall
additionally notify EPA of the identity and
qualifications of any additional contractors and all
subcontractors and supervisory personnel that will be
used to implement the ASAWP not less than seven (7)
days before any such contractor, subcontractor, or
supervisory personnel is scheduled to perform such
work. EPA may at any time disapprove the use of any
contractor, subcontractor, or supervisory personnel
EPA considers to be unqualified or otherwise unable
to perform the work, or to continue to perform the
work, required by this Consent Order. In the event
of any such disapproval, Respondent shall, within
seven (7) days following receipt of such notice,
notify EPA of the identity and qualifications of the
contractor, subcontractor, or supervisory personnel
that will replace the one(s) EPA has disapproved.
(2) Within seven (7) days following EPA acceptance of the
contractor who will implement the ASAWP, Respondent
shall commence implementation of the ASAWP and shall
complete implementation of the ASAWP according to its
approved terms, conditions, and schedules. For each
location, or group of locations, included on the
approved Work Scope List for which Respondent
contends no further investigation or cleanup is
warranted under this Consent Order, Respondent shall
submit to EPA for approval an Active Screening
Assessment Report that includes, but is not limited
to, the following:
(a) map(s) which identify the location of all
liquid removal points, mercury metering
stations, and storage well locations included
in the Report as well as topographic features
in and around such locations;
(b) photographs showing the layout of each liquid
removal point, mercury metering station, and
<PAGE> 21
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 19
storage well location included in the Report;
(c) a description of each liquid removal point,
mercury metering station, and storage well
location where Respondent's visual inspection
or sampling efforts revealed actual or
potential contamination, noting, among other
things, all affected ecological zones and
receptors, soil discoloration, stressed
vegetation, petroleum odor, and visible oil
and/or grease;
(d) photographs showing all visual evidence of
potential contamination (including, but not
limited to, soil discoloration, stressed
vegetation, and visible oil and/or grease)
found by Respondent at each liquid removal
point, mercury metering station, and storage
well location included in the Report;
(e) all chemical concentration data collected
during sampling performed pursuant to this
Consent Order (including data collection
methods, maps of sample locations, summary
data tables, and a copy of chemical data in a
computer-readable format) and any data
obtained prior to the effective date of this
Consent Order; and
(f) copies of all hazardous waste manifests
(including copies of all hazardous waste
manifests signed upon receipt of the
hazardous wastes by a licensed treatment,
storage, or disposal facility) pertaining to
all hazardous wastes shipped in the course of
preparing the Report, if any.
(d) EPA will determine, based on each Active Screening Assessment
Report, whether further investigation or cleanup under this
Consent Order is warranted for each location, or group of
locations, covered by such report. In the event EPA agrees
that a particular location or group does not warrant further
investigation or cleanup under this Consent Order, such
location or group will be removed from the Work Scope List and
Respondent shall not be obligated by this Consent Order to
take any further action with respect to such location or
group. For each location or group for which EPA concludes
that further investigation or cleanup under this Consent Order
is warranted, Respondent shall prepare a Characterization
Report pursuant to Section 8.6 of this Consent Order.
<PAGE> 22
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 20
8.6 Characterization.
(a) Respondent shall characterize the nature and extent of
contamination at each location included in the approved Work
Scope List, and which is not removed from the Work Scope List
by EPA pursuant to Sections 8.4 and 8.5 of this Consent Order,
and shall develop recommendations for cleanup of such
contamination, in accordance with this Section.
(b) Characterization Work Plan.
(1) Contractor Selection. Within seven (7) days of the
effective date of this Consent Order, Respondent
shall notify EPA in writing of the identity and
qualifications of the contractor selected by
Respondent to prepare the Characterization Work Plan
["CWP"]. EPA will notify Respondent in writing of
EPA's acceptance or disapproval of Respondent's
selected contractor as soon as practicable following
receipt of Respondent's selection. In the event EPA
disapproves Respondent's selection, Respondent shall,
within seven (7) days of its receipt of such notice,
notify EPA of the identity and qualifications of the
contractor who will replace the contractor that has
been disapproved by EPA. Acceptance/disapproval of
Respondent's selected replacement contractor(s) shall
be governed by the preceding two sentences.
Respondent shall additionally notify EPA of the
identity and qualifications of any additional
contractors and all subcontractors and supervisory
personnel that will be used to prepare the CWP not
less than seven (7) days before any such contractor,
subcontractor, or supervisory personnel is scheduled
to perform such work. EPA may at any time disapprove
the use of any contractor, subcontractor, or
supervisory personnel EPA considers to be unqualified
or otherwise unable to perform the work, or to
continue to perform the work, required by this
Consent Order. In the event of any such disapproval,
Respondent shall, within seven (7) days following
receipt of such notice, notify EPA of the identity
and qualifications of the contractor, subcontractor,
or supervisory personnel that will replace the one(s)
EPA has disapproved.
(2) Characterization Work Plan Development. Within
ninety (90) days following EPA acceptance of the
contractor who will prepare the CWP, Respondent shall
submit to EPA for approval a CWP that sets
<PAGE> 23
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 21
forth the manner in which Respondent will (i)
characterize the nature and extent of contamination
at all locations included in the work Scope List
approved by EPA, and (ii) develop recommendations for
response actions to abate threats to public health
and welfare and the environment presented by such
contamination. Respondent may submit data obtained
for purposes of preparing an Active Screening
Assessment Report in an effort to satisfy the
requirement to characterize the nature and extent of
contamination at any location. The CWP must be
consistent with CERCLA, the NCP, and with all
relevant EPA guidance and regulations. The CWP shall
include, but not be limited to:
(a) methodologies and logistics for obtaining
information in order to meet the objectives
of the characterizations;
(b) data quality objectives;
(c) for liquid removal points, mercury metering
stations, and storage well locations, a
general sampling and analysis plan (including
a Field Sampling Plan, a Quality Assurance
Project Plan, and a plan to sample all
drinking water wells that are potentially
impacted by contamination at each location)
that (1) describes the manner in which
Respondent will obtain data for each liquid
removal point, mercury metering station, and
storage well location that will be sampled
(e.g., sampling techniques and analytical
methodologies), and (2) provides a protocol
for addressing unique conditions not covered
by the general plan;
(d) a schedule for submission of
location-specific sampling and analysis plans
(including Field Sampling Plans, Quality
Assurance Project Plan, and plans to sample
all drinking water wells that are potentially
impacted by contamination at each location)
which describes the manner in which
Respondent will obtain data for each
compressor station and each of the other
locations included on the Work Scope List
except liquid removal points, mercury
metering stations, and storage well locations
Respondent shall commence to characterize
during the first year following approval of
the CWP (this schedule is to be updated in
<PAGE> 24
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 22
accordance with Section 8.9(g) of this
Consent Order);
(e) a health and safety plan to protect the
health and safety of workers, other
personnel, and the public from the hazardous
substances and work-related health and safety
hazards during performance of the work
required by this Consent Order and which
provides for proper decontamination of
personnel and equipment, monitoring and
control of off-site migration of hazardous
substances from the Site, and protection of
public health from overexposure to hazardous
substances during the performance of
activities at the Site pursuant to this
Consent Order. Applicable sections of the
plan shall be at least as stringent as the
occupational Safety and Health Administration
and EPA requirements including those
requirements found at 29 C.F.R. section
1910.120;
(f) a general plan for identifying and
characterizing all ecological zones and
receptors actually or potentially affected by
contamination, and the laboratory testing
methods to be used to evaluate impacts to
biological systems;
(g) a preliminary listing and discussion of
applicable and relevant and appropriate
requirements ["ARARs"]; other advisories,
criteria, and guidance to be considered
pursuant to section 300.400(g)(3) of the NCP,
40 C.F.R. section 300.400(g) (3) ["TBCS"] ;
and such other Federal and State cleanup
standards as may be applicable at the time;
and a plan for refinement of ARARS, TBCs, and
other cleanup level standards throughout the
characterization process, including proposed
clean-up levels; and
(h) a schedule for expeditious completion of all
Characterization Reports which shall include,
but not be limited to, projected start-up,
delivery dates for milestone field work,
written reports required by this Section, and
for meetings with EPA to present progress
information about the site. In preparing
this schedule, Respondent shall plan to first
characterize those locations where Respondent
knows or suspects contamination to be most
<PAGE> 25
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 23
severe and/or where sensitive receptors are
likely to be most significantly impacted.
EPA and Respondent may agree at any time to modify
the CWP to permit Respondent to submit a general
sampling and analysis plan for two or more compressor
stations and other locations included on the Work
Scope List in lieu of a location-specific plan for
each such location.
(c) Characterization Work Plan Implementation.
(1) Contractor Selection. Within seven (7) days of EPA
approval of all or a discrete portion of the CWP,
Respondent shall notify EPA in writing of the
identity and qualifications of the contractor(s)
selected by Respondent to implement the CWP. EPA
will notify Respondent in writing of EPA's acceptance
or disapproval of Respondent's selected contractor(s)
as soon as practicable following receipt of
Respondent's selection. In the event EPA disapproves
Respondent's selection(s), Respondent shall, within
seven (7) days of its receipt of such notice, notify
EPA of the identity and qualifications of the
contractor(s) who will replace the contractor(s) that
have been disapproved by EPA. Acceptance/disapproval
of Respondent's selected replacement contractor(s)
shall be governed by the preceding two sentences.
Respondent shall additionally notify EPA of the
identity and qualifications of any additional
contractors and all subcontractors and supervisory
personnel that will be used to implement the CWP not
less than seven (7) days before any such contractor,
subcontractor, or supervisory personnel is scheduled
to perform such work. EPA may at any time disapprove
the use of any contractor, subcontractor, or
supervisory personnel EPA considers to be unqualified
or otherwise unable to perform the work, or to
continue to perform the work, required by this
Consent Order. In the event of any such disapproval,
Respondent shall, within seven (7) days following
receipt of such notice, notify EPA of the identity
and qualifications of the contractor, subcontractor,
or' supervisory personnel that will replace the
one(s) EPA has disapproved.
(2) Within seven (7) days following EPA acceptance of the
contractor(s) who will implement the CWP, Respondent
shall commence implementation of the CWP and shall
complete implementation of the CWP
<PAGE> 26
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 24
according to its approved terms, conditions, and
schedules. For each location included on the
approved Work Scope List, Respondent shall prepare
and submit to EPA for approval a Characterization
Report that includes, but is not limited to, the
following:
(a) a map of the location, including the property
boundary, all fence lines, significant
surface impoundments (including, but not
limited to, all buildings, tanks, drum
storage areas, truck loading areas, pig
receivers/launchers, sumps, diffuser tanks,
all above-ground and known and reasonably
ascertainable underground pipelines
(including drainlines), debris piles, and any
area of present or past disposal activity),
nearby surface water, affected drinking water
wells, and locations of all ground water
monitoring wells. Overlay maps can be
employed to show areas of potential
contamination, water supplies (public and
private) , potentially affected
mines/quarries, surrounding land use and
population density, topography, and other
relevant features;
(b) A geological map showing the location in the
center and surrounding land area and
population density. The map should be based
on United States Geological Survey 7.5 minute
series topographical maps and should identify
all major landmarks including, but not
limited to, roads, highways, and major
buildings;
(c) a description of the location and history of
operations and releases there;
(d) a summary of previous investigations and
clean-up actions at that location;
(e) a description of the location setting
(including physical setting, climate, surface
water hydrology and quality, geology, soils,
hydrogeology and groundwater quality,
fractures and groundwater movement, and
ecology) which may be obtained from published
sources;
(f) all chemical concentration data collected
during sampling performed at the location,
including sampling performed in accordance
with the sampling plan approved by EPA for
such location (including data collection
<PAGE> 27
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 25
methods, maps of sample locations, summary
data tables, and a copy of chemical data in a
computer-readable format);
(g) a summary of all groundwater monitoring data
obtained by Respondent from the location;
(h) a summary of potentially exposed populations
(including locations, current land uses,
alternative future land uses, activity
patterns, and subpopulations of potential
concern) which may be obtained from published
sources;
(i) a description of the affected ecological
zones and receptors;
(j) copies of all hazardous waste manifests
(including copies of all hazardous waste
manifests signed upon receipt of the
hazardous wastes by a licensed treatment,
storage, or disposal facility) pertaining to
all hazardous wastes shipped in the course of
preparing the Characterization Report, if
any; and
(k) recommendations for response actions which
will abate threats to public health and
welfare and the environment presented by
contamination at such location. Such
recommendations shall include, but not be
limited to, proposed cleanup levels that meet
or exceed all applicable or relevant and
appropriate requirements within the meaning
of section 121 of CERCLA, 42 U.S.C. section
9621, or such other Federal and State cleanup
standards as may be applicable; waste
management options that are consistent with
CERCLA and the NCP; and plans for performance
of treatability studies where such studies
are deemed appropriate by EPA. Respondent
may, in addition, recommend groups of liquid
removal points, mercury metering stations,
storage well locations, and compressor
stations which should be considered by EPA
for concurrent response action selection
pursuant to Section 8.7 of this Consent
Order.
8.7 Selection of Response Actions. For each location included in the
approved Work Scope List for which Respondent has submitted a
Characterization Report in accordance with Section 8.6 of this Consent
Order, EPA will either (a) select a
<PAGE> 28
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 26
response action for implementation at such location under this Consent
Order; (b) determine that such location, or a portion of such
location, is more appropriately addressed under EPA's remedial
response action authority or other authorities; or (c) both of the
above. Where practicable, and to the extent EPA determines that such
practice will not unduly delay cleanup, EPA will select response
actions concurrently for liquid removal points, mercury metering
stations, storage well locations, and compressor stations recommended
for concurrent response action selection by Respondent. EPA reserves
the right to hold public meetings, rely on public comment, and
otherwise solicit public participation in selecting a response action
for implementation under this Consent Order. In selecting a response
action for implementation under this Consent Order, EPA shall not be
limited to the action recommended by Respondent in the
Characterization Report. EPA will notify Respondent of its decision
in writing. Respondent shall implement all response actions selected
by EPA for implementation under this Consent Order in accordance with
the requirements of Section 8.8 of this Consent Order. In the event
EPA determines that a location, or portion of a location, is more
appropriately addressed under remedial response action authority or
other authorities, that particular location, or portion of such
location, shall be removed from the Work Scope List and Respondent
shall not be obligated under this Consent Order to take further action
at such location or portion of such location.
8.8 Implementation of Response Actions Selected by EPA for Implementation
Under this Consent Order.
(a) Respondent shall perform all response actions selected by EPA
for implementation under this Consent Order in accordance with
this Section.
(b) Response Action Work Plan.
(1) Contractor Selection. Within thirty (30) days after
EPA has selected a response action for implementation
under this Consent Order at a particular location or
group of locations, Respondent shall notify EPA in
writing of the identity and qualifications of the
contractor selected by Respondent to prepare a
Response Action Work Plan ["RAWP"] for that location
or group of locations. EPA will notify Respondent in
writing of EPA's acceptance or disapproval of
Respondent's selected contractor as soon as
practicable following receipt of Respondent's
selection. In the event EPA disapproves Respondent's
selection, Respondent shall, within fifteen (15) days
of its
<PAGE> 29
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 27
receipt of such notice, notify EPA of the identity
and qualifications of the contractor who will replace
the contractor that has been disapproved by EPA.
Acceptance/disapproval of Respondent's selected
replacement contractor(s) shall be governed by the
preceding two sentences. Respondent shall
additionally notify EPA of the identity and
qualifications of any additional contractors and all
subcontractors and supervisory personnel that will be
used to prepare the RAWP not less than seven (7) days
before any such contractor, subcontractor, or
supervisory personnel is scheduled to perform such
work. EPA may at any time disapprove the use of any
contractor, subcontractor, or supervisory personnel
EPA considers to be unqualified or otherwise unable
to perform the work, or to continue to perform the
work, required by this Consent Order. In the event
of any such disapproval, Respondent shall, within
fifteen (15) days following receipt of such notice,
notify EPA of the identity and qualifications of the
contractor, subcontractor, or supervisory personnel
that will replace the one(s) EPA has disapproved.
(2) Response Action Work Plan Development. Within thirty
(30) days following EPA acceptance of the contractor
who will be responsible for implementing the response
action selected by EPA for a particular location or
group of locations, Respondent shall submit to EPA
for approval a RAWP that sets forth the manner in
which Respondent will perform that response action.
The RAWP shall be consistent with CERCLA and the NCP
and shall include, at a minimum:
(a) a map of the location, including the property
boundary, all fence lines, significant
surface impoundments (including, but not
limited to, all buildings, tanks, drum
storage areas, truck loading areas, pig
receivers/launchers, sumps, diffuser tanks,
all above-ground and known and reasonably
ascertainable underground pipelines
(including drainlines), debris piles, and any
area of present or past disposal activity),
nearby surface water, affected drinking water
wells, and locations of all ground water
monitoring wells. Overlay maps can be
employed to show areas of potential
contamination, water supplies (public and
private), mines/quarries, surrounding land
use and population density,
<PAGE> 30
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 28
topography, and other relevant features.
(b) A geological map showing the location in the
center and surrounding land area and
population density. The map should be based
on United States Geological Survey 7.5 minute
series topographical maps and should identify
all major landmarks including, but not
limited to, roads, highways, and major
buildings.
(c) A description of the location and operations
conducted there, and a description of the
adjacent land within one thousand feet of the
property boundary and its current use.
(d) A detailed description of the response action
selected by EPA to be taken at that location,
and an expeditious schedule for completion of
such work.
(e) Sampling plan(s) to verify the effectiveness
of the response action, with data quality
objectives, and to perform any additional
sampling Respondent intends to perform.
Respondent may submit maps and other information
previously provided to EPA in Characterization
Reports to the extent such maps and other information
are accurate at the time submitted.
(c) Response Action Work Plan Implementation.
(1) Contractor Selection. No later than thirty (30) days
after EPA has approved all or a discrete portion of
the RAWP for a particular location or group of
locations, Respondent shall notify EPA in writing of
the identity and qualifications of the contractor
selected by Respondent to implement the RAWP at that
location or group of locations. Respondent may
propose contractor(s) to implement RAWPs at more than
one location in a single notice, provided each
location is identified. EPA will notify Respondent
in writing of EPA's acceptance or disapproval of
Respondent's selected contractor(s) as soon as
practicable following receipt of Respondent's
selection(s). In the event EPA disapproves
Respondent's selection(s), Respondent shall, within
fifteen (15) days of its receipt of such notice,
notify EPA of the identity and qualifications of the
contractor(s) who will replace the contractor(s)
that has been disapproved
<PAGE> 31
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 29
by EPA. Acceptance/disapproval of Respondent's
selected replacement contractor(s) shall be governed
by the preceding two sentences. Respondent shall
additionally notify EPA of the identity and
qualifications of any additional contractors and all
subcontractors and supervisory personnel that will be
used to implement each approved RAWP not less than
seven (7) days before any such contractor,
subcontractor, or supervisory personnel is scheduled
to perform such work. EPA may at any time disapprove
the use of any contractor, subcontractor, or
supervisory personnel EPA considers to be unqualified
or otherwise unable to perform the work, or to
continue to perform the work, required by this
Consent Order. In the event of any such disapproval,
Respondent shall, within fifteen (15) days following
receipt of such notice, notify EPA of the identity
and qualifications of the contractor, subcontractor,
or supervisory personnel that will replace the
one(s) EPA has disapproved.
(2) Within thirty (30) days following EPA acceptance of
the contractor who will implement the RAWP at a
location, Respondent shall commence implementation of
the RAWP and shall complete implementation of the
RAWP according to its approved terms, conditions, and
schedules.
(d) Response Action Completion/Final Report. Within sixty (60)
days following the date Respondent concludes it has completed
implementation of the RAWP approved by EPA for a particular
location or group of locations, Respondent shall submit a
written Final Report to EPA for approval so notifying EPA.
The written report shall, at a minimum, (1) detail the work
undertaken to implement the RAWP, (2) include all data
obtained by Respondent to verify the effectiveness of the
response action, (3) include all hazardous waste manifests
(including copies of all hazardous waste manifests signed upon
receipt of the hazardous wastes by a licensed treatment,
storage, or disposal facility) pertaining to all hazardous
wastes shipped from the location pursuant to Section 8.8 of
this Consent Order, if any, and (4) be certified by Respondent
in accordance with Section 8.12 of this Consent Order. EPA
will review the adequacy of Respondent's implementation of the
RAWP and will notify Respondent, in writing, of any
discrepancies in the Final Report or deficiencies in the
execution of the RAWP. In addition, EPA may identify actions
required to correct such discrepancies or deficiencies.
Within thirty (30)
<PAGE> 32
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 30
business days of receipt of notification by EPA or as
otherwise specified by EPA, Respondent shall amend the Final
Report, develop an additional plan, or amend the existing RAWP
to address such discrepancies or deficiencies. Respondent
shall perform such corrective actions in a manner consistent
with CERCLA and the NCP and all applicable Federal laws and
regulations. Any additional plan or amendment to the RAWP
will be subject to EPA approval pursuant to Section IX of
this Consent Order.
8.9 Reporting and Document Availability.
(a) On the first business day of the second month following the
month in which EPA approves all or a portion of the Active
Screening Assessment Work Plan or the Characterization Work
Plan, whichever is earlier, and an the first business day of
every month thereafter during the pendency of this Consent
Order, Respondent shall provide EPA with a progress report for
each preceding calendar month. At a minimum, these progress
reports shall include:
1. a description of the actions, that have been taken
toward achieving compliance with this Consent Order;
2. a description of all analytical work performed
pursuant to this Consent Order during the reporting
period which, for any reason, has failed to satisfy
the Quality Assurance/Quality Control requirements
set forth in Section XI of this Consent Order;
3. activities scheduled for the next month including,
but not limited to, the date of sampling activity for
each location to be sampled in the following month;
4. a description of any problems encountered, any
actions taken or to be taken to remedy or mitigate
such problems, and a schedule of when such actions
will be taken;
5. the identity of treatment, storage, and/or disposal
facilities used during the reporting period;
6. the identity of transporters used to transport
hazardous wastes to treatment, storage, and/or
disposal facilities during the reporting period;
<PAGE> 33
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 31
7. the identity of any contractors, subcontractors, and
supervisory personnel used during the reporting
period that have not been previously identified to
EPA; and
8. all modifications to work plans made in accordance
with Section XXIII of this Consent Order during the
reporting period.
(b) In addition to the information required pursuant to Section
8.9(a), Respondent shall notify EPA within twenty-four (24)
hours following Respondent's receipt of data showing the
presence of any contaminant in drinking water in excess of the
emergency removal guideline concentration for drinking water
set forth in Appendix B. Such notice shall identify, at a
minimum, the location of the well(s) from which the data was
obtained; the contaminant(s) found in excess of such level(s);
and the identity, if known, of all persons served by such
well(s).
(c) In the event Respondent knows or suspects that the schedule
for a particular sampling event may be changed, Respondent
shall notify the EPA Project Coordinator no less than
twenty-four (24) hours before the date such sampling activity
was originally scheduled.
(d) Respondent shall compile and retain, as appropriate, monthly
reports on analytical services pursuant to OSWER Directive No.
9240.0-2B ("Extending the Tracking of Analytical Services to
Potentially Responsible Party-Lead Superfund Sites" (July 6,
1992)).
(e) Upon written request from EPA, Respondent shall provide,
within ten (10) days of such request or such longer time as
EPA may specify, any and all information and documents in its
possession, custody, or control resulting from and/or
pertaining to work performed by Respondent pursuant to this
Consent Order including, but not limited to, analytical data
(including raw data); Site safety data; Site monitoring data;
operational logs; information and documents concerning
Respondent's compliance with Quality Assurance and Quality
Control requirements of this Consent Order; information and
documents relating to Respondent's efforts to secure access;
and information and documents relating to any project delays.
Nothing herein shall be interpreted as limiting the inspection
and information-gathering authority of EPA under Federal law.
<PAGE> 34
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 32
(f) Unless otherwise provided herein, all documents, including
plans, reports, sampling results, and other correspondence to
be submitted pursuant to this Consent Order shall be sent by
certified or overnight mail to the EPA Project Coordinator
designated pursuant to Section X of this Consent Order. EPA
and Respondent may agree to an alternative method of document
delivery on a document-by-document basis.
(g) Commencing one year from the effective date of this consent
Order, and continuing on an annual basis until
characterizations at each compressor station and all other
locations included on the Work Scope List except liquid
removal points, mercury metering stations, and storage well
locations have commenced pursuant to Section 8.6 of this
Consent Order, Respondent shall submit to EPA for approval a
schedule for submission of location-specific sampling and
analysis plans (including Field Sampling Plans, Quality
Assurance Project Plan, and plans to sample all drinking water
wells that are potentially impacted by contamination at each
location) which describes the manner in which Respondent will
obtain data for each compressor station and each of the other
locations included on the Work Scope List except liquid
removal points, mercury metering stations, and storage well
locations, that Respondent shall commence to characterize
during that year.
8.10 EPA reserves its right to disapprove of work performed by the
Respondent if not performed to EPA's satisfaction in accordance with
this Consent Order and reserves its right to request that Respondent
perform response actions in addition to those required by, or as
modified in the approved work plans, if EPA determines that such
actions are necessary and that Respondent is qualified and can carry
out such actions properly and promptly. In the event that Respondent
declines to perform such additional and/or modified actions, EPA
reserves the right to undertake such action(s) and to seek
reimbursement of its costs and/or to seek any other appropriate
relief.
8.11 EPA reserves the right to undertake removal and/or remedial actions at
any time that such actions are appropriate under CERCLA and the NCP,
and to seek reimbursement for any costs incurred or seek any other
appropriate relief.
8.12 Certifications. All certifications required by this Consent Order
shall be made in accordance with the requirements of this Section.
<PAGE> 35
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 33
1. A "responsible official" of Respondent, or his/her duly
authorized representative participating in the oversight of
activities required by this Consent Order, shall sign each
certification in accordance with the requirements of this
provision.
2. For a corporation, a "responsible official" means a president,
secretary, treasurer, vice president in charge of a principal
business function, other person who performs similar policy or
decision-making functions for the corporation, or, if
authority to sign documents has been assigned or delegated to
him/her in accordance with corporate procedures, the gar of
one or more manufacturing, production or operating facilities
employing more than 250 persons or having gross annual sales
or expenditures exceeding $35 million (in 1987 dollars when
the Consumer Price Index was 345.3). For a partnership or sole
proprietorship, "responsible official" means a general partner
or the proprietor, respectively.
3. A person is a "duly authorized representative" within the
meaning of this subsection only if:
(a) The authorization is made in writing by a responsible
corporate-official, and
(b) The authorization specifies either an individual or a
position within the Respondent's organization
responsible for overseeing performance of the work
required by this Consent Order, and
(c) The written authorization has been approved by EPA
prior to the certification.
4. The certification required by this provision shall be in the
following form:
"Except as provided below, I certify that the
information contained in or accompanying this [type of
submission] is true, accurate, and complete to the best of my
information, knowledge, and belief and that this [type of
submission] and all attachments were prepared at my direction
and with my review, in accordance with a system designed to
assure that qualified personnel gather and evaluate the
information submitted. Based on my inquiry of the person or
persons who manage the system, or those persons directly
responsible for gathering the information, the information
submitted is true, accurate, and complete to the best of my
knowledge, information, and belief.
<PAGE> 36
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 34
"This certification shall not apply to information
contained herein that was inserted into this [type of
submission] by EPA, or was required by EPA to be inserted into
this [type of submission], over my objection."
8.13 EPA Takeover of Work. In the event EPA elects to perform all or any
portion of the work required by this Consent Order or to oversee
performance of such work by a party other than Respondent, EPA shall
so notify Respondent in writing. Such notification ["Takeover
Notice"] shall identify the work required by this Consent Order which
Respondent shall not perform ["Takeover Work"]. Upon receipt of any
such Takeover Notice from EPA, Respondent shall be released from any
further obligation under this Consent Order to complete such Takeover
Work. Respondent shall not be released, however, from any other
obligations under this Consent Order and shall specifically remain
liable for, among other things,:
(a) stipulated penalties for violations of this Consent Order
which occurred prior to Respondent's receipt of any such
Takeover Notice; provided, however, that stipulated penalties
for violations of this Consent Order relating to Takeover Work
shall continue to accrue only until (1) EPA, or another party
pursuant to an agreement with or order by EPA, commences
performance of such work, or (2) sixty (60) days from the date
of Respondent's receipt of the Takeover Notice, whichever is
less; and
(b) oversight costs incurred prior to Respondent's receipt of the
Takeover Notice.
Unless otherwise provided in the Takeover Notice, Respondent shall not
be released from its obligations under this Consent Order to perform
any work required by this Consent Order other than the Takeover Work
and shall remain subject to stipulated penalties and responsible for
reimbursement of all costs, including oversight costs, relating to all
such work.
8.14 Shipment of Hazardous Substances. Except as provided in this Section
8.14, Respondent shall, prior to any off-site shipment of hazardous
substances from any location included in the EPA-approved Work Scope
List to an out-of-state waste management facility, provide written
notification to the appropriate state environmental official in the
receiving state and to the EPA Project Coordinator of such shipment of
hazardous substances. This paragraph shall not require Respondent to
notify a particular State when the total volume of shipments from all
locations included within the EPA-approved Work Scope List to that
State will not exceed ten (10) cubic yards.
<PAGE> 37
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 35
(a) The notification shall be in writing, and shall include the
following information, where available: (1) the name and
location of the facility to which the hazardous substances are
to be shipped; (2) the type and quantity of the hazardous
substances to be shipped; (3) the expected schedule for the
shipment of the hazardous substances; and (4) the method of
transportation. Respondent shall notify the receiving state
of major changes in the shipment plane such as a decision to
ship the hazardous substances to another facility within the
same state, or to a facility in another state.
(b) The identity of the receiving facility and state will be
determined by Respondent. Respondent shall provide all
relevant information on the off-site shipments, including
information described in Section 8.14 (a) of this Consent
order, as soon as practicable but no later than one (1)
business day before the hazardous substances are actually
shipped.
8.15 Respondent shall not handle or remove any hazardous substances from
the Site except in conformance with the terms of this Consent Order
and all applicable Federal, State, and local laws and regulations, as
required by the NCP. Any hazardous substance, pollutant, or
contaminant transferred for disposal off-site as a result of this
Consent Order must be taken to a facility acceptable under EPA's Off-
Site Policy (58 Fed. Reg. 49200 (September 22, 1993)) in accordance
with section 121(d)(3) of CERCLA, 42 U.S.C. section 9621(d)(3).
8.16 Respondent shall not commence any work required by this Consent Order
except in conformance with the terms of this Consent Order.
8.17 Respondent shall notify the EPA Project Coordinator at the same time
and in the same manner as other persons to whom notice is required to
be given by law in connection with any action or occurrence during the
pendency of this Consent Order which causes or threatens to cause an
additional release of hazardous substances, pollutants, or
contaminants on, at, or from the Site, or which may create a danger to
public health, welfare, or the environment.
8.18 In the event that EPA determines that response actions or other
current activities at the Site by the Respondent are causing a release
or potential release of hazardous substances, or are a threat to
public health or welfare or to the environment, EPA may, at its
discretion, immediately halt or modify such response actions or other
activities to eliminate or mitigate such actual or potential release
or threat.
<PAGE> 38
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 36
IX. SUBMISSIONS REQUIRING EPA APPROVAL
9.1 Any plan, report, or other document required to be submitted for EPA
approval pursuant to this Consent order ["Submission"] shall be
submitted to the EPA Project Coordinator designated pursuant to
Section X of this Consent Order. After review of any Submission, EPA
may: (1) approve, in whole or in part, the Submission; (2) approve the
Submission upon specified conditions; (3) direct Respondent to modify
the Submission; (4) disapprove, in whole or in part, the Submission;
(5) disapprove the Submission as substantially deficient; or (6) any
combination of the above. EPA intends to identify deficiencies in
Submissions in the notice of disapproval except where EPA disapproves
a Submission as substantially deficient. Where practicable, and to
the extent that EPA determines that such practice will not unduly
delay performance of the work, EPA will provide Respondent one
opportunity to cure all deficiencies in a Submission prior to
approving a portion of the Submission; provided, however, that EPA
need provide no such opportunity to cure prior to approving a portion
of any Response Action Work Plan submitted for two or more locations,
where such portion approved relates to all work to be implemented at a
particular location under such plan.
9 .2 In the event EPA approves the Submission in whole, Respondent shall
take all actions required by the Submission. In all other cases,
Respondent shall take all actions required by portions of the
Submission which are approved by EPA.
9.3 Except as otherwise provided in Section 9.4 of this Consent Order,
Respondent shall, upon receipt of a notice of disapproval or notice
requiring modification of the Submission, correct the deficiencies and
resubmit the Submission for approval within fifteen (15) days of such
receipt or such longer time as may be specified by EPA in its
discretion. Exercise of EPA's discretion with respect to such period
shall not be subject to dispute resolution under this Consent Order.
9.4 In the event that (1) any Submission is disapproved by EPA as
substantially deficient, or (2) a resubmitted Submission, or portion
thereof, is disapproved by EPA, Respondent shall be in violation of
this Consent Order. EPA may, under such circumstances, conduct all or
any portion of the work required by this Consent Order pursuant to
Section 8.12 herein, and seek reimbursement of its costs; take any
action described in Section 9.1 of this Consent Order; and/or seek any
other appropriate relief.
9.5 All Submissions, or portions thereof, shall, upon approval by EPA, be
enforceable as requirements of this Consent Order. In the event of a
conflict between this Consent Order and any
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document attached hereto or enforceable hereunder, the provisions of
this Consent Order shall control. Respondent shall immediately notify
EPA in the event Respondent becomes aware of a conflict between a
requirement of this Consent Order and a requirement of a document
attached hereto or enforceable hereunder. Respondent shall not be
required to take any action which EPA agrees will conflict with any
requirement of this Consent Order until such time this Consent Order
or the document is modified, provided Respondent provides notice to
EPA as set forth in this paragraph. Respondent shall continue to
implement this Consent Order until notified by EPA under this Section
9.5 that EPA agrees that a conflict exists.
9.6 No failure by EPA to approve, disapprove, or otherwise respond to a
Submission shall be construed as an approval of such Submission.
X. DESIGNATED PROJECT COORDINATORS
10.1 Respondent shall designate a Project Coordinator and shall notify EPA
of its designated Project Coordinator no later than five (5) calendar
days after the effective date of this Consent Order. Designation of a
Project Coordinator shall not relieve Respondent of its obligations to
comply with the requirements of the Order. The Respondent's Project
Coordinator shall be a technical and/or managerial representative of
the Respondent and may be a contractor and/or consultant; provided,
however, the Respondent's Project Coordinator shall not be its legal
representative in this matter. The Project Coordinator for EPA
designated pursuant to this Section and the Project Coordinator for
the Respondent shall be responsible for overseeing work required by
this Consent Order. To the maximum extent possible, communications
between the Respondent and EPA and all documents concerning
the activities performed pursuant to the terms and conditions of this
Consent Order, including plans, reports, approvals, and other
correspondence, shall be directed to the Project Coordinators.
10.2 The Project Coordinator for EPA is:
James Cashel (3AT31)
Project Coordinator
U.S. Environmental Protection Agency
841 Chestnut Building
Philadelphia, PA 19107
(215) 597-1260
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EPA Docket No. III-94-35-DC 38
10.3 Respondent shall have the right to change its Project Coordinator.
Such a change shall be accomplished by notifying the EPA Project
Coordinator in writing at least five (5) calendar days prior to the
change or otherwise as soon as practicable.
10.4 EPA shall have the right to change its Project Coordinator at any time
without prior notice to Respondent. EPA's intent is to notify the
Respondent as soon as practicable following any such change of its
Project Coordinator.
10.5 The absence of the EPA Project Coordinator from the Site shall not be
cause for the stoppage or delay of work except when such stoppage or
delay is specifically required by EPA.
10.6 The EPA Project Coordinator shall have the authority to halt or modify
work required by this Consent Order or other activities performed by
Respondent at the Site to eliminate a release or threat of release of
hazardous substances. Such direction by the EPA Project Coordinator
may be given verbally or in writing, If such direction is given
verbally, the EPA Project Coordinator will later memorialize such
direction in writing as soon as practicable.
XI. QUALITY ASSURANCE
11.1 The Respondent shall use quality assurance, quality control, and chain
of custody procedures in accordance with the following documents while
conducting all sample collection and analysis activities required by
this Consent Order:
(a) "EPA NEIC Policies and Procedures Manual" (EPA Document
330/9-78-001-R (revised November 1984));
(b) "Interim Guidelines and Specifications for Preparing Quality
Assurance Project Plans," (QAMS-005/80 (December 1980)); and
(c) "QA/QC Guidance for Removal Activities," (EPA/540/G-90/004
(April 1990)).
The Respondent shall use a laboratory(s) which has a documented
Quality Assurance Program that complies with EPA guidance document
QAMS-005/80, or such other laboratories as may be approved by EPA.
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XII. ACCESS
12.1 As of the effective date of this Consent Order, Respondent shall
provide to EPA and its employees, agents, consultants, contractors,
and other authorized and/or designated representatives, for the
purposes of conducting and/or overseeing the work required by this
Consent Order, access to all property owned or controlled by
Respondent wherein work required by this Consent Order must be
undertaken. Such access shall permit EPA and its employees, agents,
consultants, contractors, and other authorized and designated
representatives to conduct all activities described in Section 12.3 of
this Consent Order. EPA will furnish copies of insurance certificates
provided to EPA by contractors retained by EPA to oversee or perform
work at the Site in connection with this Consent Order.
12.2 To the extent that property wherein work required by this Consent
Order must be undertaken is owned or controlled by persons other than
the Respondent, the Respondent shall use reasonable efforts to obtain
access agreements from the present owners. Such access agreements
shall be finalized as soon as practicable but no later than fourteen
(14) days prior to the date such work is scheduled to begin. Such
agreements shall provide reasonable access for the Respondent and its
employees, agents, consultants, contractors, and other authorized and
designated representatives to conduct the work, and for EPA and its
designated representatives to conduct the activities outlined in
Section 12.3 of this Consent Order. In the event that any property
owner refuses to provide such access or access agreements are not
obtained within the time designated above, whichever occurs sooner,
the Respondent shall notify EPA at that time, in writing, of all
efforts to obtain access and the circumstances of the failure to
obtain such access. EPA may then take steps to provide such access.
Reasonable efforts shall include, but not be limited to, agreement to
reasonable conditions for access and/or the payment of reasonable
fees.
12.3 EPA and its employees, agents, contractors, consultants and other
authorized and designated representatives shall have the authority to
enter and freely move about the locations where the response actions
and/or work is being performed at all reasonable times for the purpose
of, inter alia, inspecting work; inspecting records, operating logs,
and contracts related to the Site; reviewing the progress of the
Respondent in carrying out the terms of this Consent Order; conducting
such tests as EPA deems necessary; using a camera, sound recording, or
other documentary type equipment for purposes of monitoring activities
to be performed pursuant to this Consent Order; and verifying the data
submitted to EPA by the
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Respondent. The Respondent shall permit such persons to inspect and
copy all sampling and monitoring data and all nonprivileged records,
files, photographs, documents, and other writings in any way
pertaining to the work required by this Consent Order. Where
practicable, EPA will notify Respondent in advance of any sampling
performed at the Site by EPA in connection with this Consent Order and
will, at the request of Respondent, provide Respondent with an
opportunity to split samples. EPA intends to comply with all
applicable Federal health and safety laws while on Respondent's
property. EPA further intends to review relevant health and safety
plans provided by Respondent and to comply with such plans to the
extent practicable.
12.4 Except as provided in Section 12.6 of this Consent Order, Respondent
may make a claim of business confidentiality for information submitted
pursuant to this Consent Order in the manner described in 40 C.F.R.
section 2.203(b). Such an assertion shall be adequately substantiated
in accordance with 40 C.F.R. section 2.204(e)(4) at the time the
assertion is made. Information subject to a confidentiality claim
shall be made available to the public by EPA only in accordance with
the procedures set forth in 40 C. F. R. Part 2, Subpart B. If no such
claim of business confidentiality accompanies the information when it
is submitted or made available to EPA, such information may be made
available to the public by EPA without further notice to Respondent.
12.5 Except as provided in Section 12.6 of this Consent Order, Respondent
may withhold any documents covered by any privilege or protection
under federal law applied by federal courts in actions commenced by
the United States. For purposes of this Consent Order, EPA agrees
that it will not maintain that Respondent has waived any privilege or
protection otherwise applicable solely on the basis that Respondent
has provided information to insurers. In the event that the
Respondent withholds a document as privileged, the Respondent shall
provide EPA with the title of the document, the date of the document,
the name(s) of the author(s), and addressee(s)/recipient(s), a
description of the nature of the document, and identification of the
privilege asserted at the time any such document is due to be provided
to EPA under this Consent Order or as soon as practicable following
any request by EPA for access to such documents.
12.6 No claim of confidentiality or privilege shall be made regarding any
data required to be submitted pursuant to this Consent Order
including, but not limited to sampling, analytical, monitoring,
hydrogeologic, scientific, chemical, or engineering data, or documents
or information evidencing conditions at or around the Site. Nor shall
such claims be
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made for analytical data; Site safety data; Site monitoring data;
operational logs; hazardous waste manifests; identities of treatment,
storage, and/or disposal facilities used; identities of transporters
used; identities of any contractors or subcontractors used.
12.7 Notwithstanding any provision of this Consent Order, EPA retains all
of its access and information-gathering authorities and rights under
CERCLA and any other applicable statute and regulation.
XIII. DISPUTE RESOLUTION
13.1 The resolution of any dispute between EPA and Respondent concerning
this Consent Order shall be conducted in accordance with this Section.
13.2 (a) Except as otherwise provided herein, if Respondent objects to
any EPA notification or action under this Consent Order, the
Respondent shall notify the EPA Project Coordinator in
writing of its objection(s) within fourteen (14) days of such
action or receipt of such EPA notification.
(b) The written notification of objections from Respondent
referred to in Section 13.2(a) of this Consent order ["Notice
of Dispute"] shall identify the issue(s) in dispute, the
position Respondent maintains should be adopted by EPA, the
basis for Respondent's position, and any matters Respondent
considers necessary for EPA's determination.
(c) Except as provided herein, EPA and the Respondent shall have
fourteen (14) days from EPA's receipt of the Notice of Dispute
to resolve the dispute. As to any issue for which agreement
is not reached during this period, EPA will provide a written
statement of its decision to Respondent ["EPA Resolution
Notice"]. Except as to disputes concerning selection of a
response action pursuant to Section 8.7 of this Consent Order,
the EPA Resolution Notice shall be signed by the Chief of the
Region III Toxics and Pesticides Branch or his/her designee.
The EPA Resolution Notice issued for any dispute concerning
selection of a response action pursuant to Section 8.7 of this
Consent Order shall be signed by the Director of the Region
III Air, Radiation, and Toxics Division or his/her designee.
EPA may extend the fourteen (14) day period up to an
additional fourteen (14) days if EPA determines that more time
is necessary for resolution. Respondent shall not invoke this
Section
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to object to a EPA Resolution Notice.
(d) Following resolution of the dispute by agreement (in the event
the dispute has been resolved by agreement) or Respondent's
receipt of the EPA Resolution Notice (in the event EPA and
Respondent are unable to reach agreement), Respondent shall
perform the work that was the subject of the dispute in
accordance with the agreement (if applicable) or the EPA
Resolution Notice.
13.3 Notwithstanding any other provisions of this Consent Order, no action
or decision by EPA pursuant to this Consent Order shall constitute
final agency action giving rise to any right to judicial review prior
to EPA's initiation of judicial action to compel compliance with this
Consent Order.
13.4 Neither invocation of the procedures set forth in this Section, nor
EPA's consideration of matters placed into dispute, shall excuse, toll
or suspend any compliance obligation or deadline required pursuant to
this Consent Order during the pendency of the dispute resolution
process.
13.5 The existence of a dispute under this Section shall not by itself
expand the time frame for completing any work under this Consent
Order. Any task that is the subject of a dispute must be completed in
the remaining amount of time originally specified in the Consent Order
unless the time frame is formally modified by EPA. Any such
modifications to this Consent Order shall be made in accordance with
Section XXIII of this Consent Order. In the event Respondent does not
prevail in the dispute, Respondent may request modification of the
timeframe for completion of the action that is the subject of the
dispute, provided Respondent demonstrates to EPA's satisfaction that
each of the following is met: (a) there will be insufficient time to
complete such action on an expedited basis in the time remaining after
completion of dispute resolution; (b) the assessment,
characterization, and cleanup of the location(s) affected by the
dispute will not be unduly delayed by the timeframe modification
requested by Respondent; and (c) the dispute was brought in good faith
and was not an attempt to delay compliance with the Consent Order.
EPA's decision on Respondent's request shall not be subject to dispute
resolution. Neither Respondent's request for modification of the
applicable timeframe, nor consideration by EPA of any such request,
shall excuse, toll, or suspend any compliance obligation or deadline
required pursuant to this Consent Order.
13.6 The accrual of stipulated penalties shall continue notwithstanding the
existence of a dispute or invocation of the procedures set forth in
this Section.
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13.7 In order to prevail in any dispute concerning costs under Section XVII
of this Consent Order, Respondent shall have the burden of proving that
such costs have been calculated incorrectly, or that such costs were
not authorized by CERCLA or were incurred in a manner inconsistent
with the NCP.
XIV. DELAY IN PERFORMANCE AND STIPULATED PENALTIES
14.1 For each day, or portion thereof, that Respondent fails to comply with
any requirement of this Consent Order at the time and in the manner
not forth herein, the Respondent shall be liable upon demand to EPA
for the sums set forth below as stipulated penalties. Checks shall be
made payable to the "Hazardous Substance Superfund" and shall be
transmitted to:
U.S. Environmental Protection Agency, Region III
Attention: Superfund Accounting
Box 360515
Pittsburgh, PA 15251-6515
Payment shall be made by cashier's or certified check within thirty
(30) calendar days of receipt of demand. Interest at the rate of the
current annualized treasury bill rate shall begin to accrue on the
unpaid balance at the and of the thirty day period pursuant to section
107(a) of CERCLA, 42 U.S.C. section 9607(a). A copy of the
transmittal letter shall be sent simultaneously to the EPA Project
Coordinator. A copy of the transmittal letter and check shall be sent
simultaneously to:
Regional Hearing Clerk (3RCOO)
U.S. Environmental Protection Agency
841 Chestnut Building
Philadelphia, PA 19107
and
Andrew S. Goldman (3RC21)
Sr. Assistant Regional Counsel
U.S. Environmental Protection Agency
841 Chestnut Street
Philadelphia, PA 19107
14.2 Stipulated penalties shall accrue in the amount of $5,000 per calendar
day per violation. Neither the accrual of, nor demand for stipulated
penalties set forth in this Section shall preclude EPA from pursuing
other penalties or sanctions available to EPA for Respondent's failure
to comply with the requirements of this Consent Order. In the event
that statutory penalties are imposed for a violation of this Consent
Order for which Respondent is concurrently liable for
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stipulated penalties pursuant to this Consent Order, Respondent shall
be entitled to an offset to the total amount of statutory penalties
assessed by the total amount of stipulated penalties paid for such
violation.
14.3 Determinations of non-compliance by Respondent with this Consent Order
shall be made by EPA and are subject to Dispute Resolution under
Section XIII of this Consent Order.
XV. FORCE MAJEURE AND NOTIFICATION OF DELAY
15.1 A failure by Respondent to comply with any requirement of this Consent
Order in the manner or in the time required by this Consent Order
["Compliance Failure"] shall constitute a violation of this Consent
Order unless such Compliance Failure has resulted from a Force Majeure
Event within the meaning of Section 15.2 of this Consent Order. To
the extent that a delay is caused by a Force Majeure Event, the
schedule for performance of work affected by the delay will be
extended by EPA for the time necessary to complete such work, up to
the period of the delay directly resulting from the Force Majeure
Event. Except as may be specifically provided by EPA, no such
schedule extension shall affect the schedule for completion of any
other tasks required by this Consent Order.
15.2 A Force Majeure Event is any event which:
(a) arises from causes not reasonably foreseeable and
beyond the control of Respondent, and
(b) results in delays or prevents performance by a date or manner
required by this Consent Order,
provided that Respondent has used reasonable efforts to perform as
required by this Consent Order. "Reasonable efforts" as used in this
Paragraph shall include, but not be limited to, efforts to expedite
the performance of activities in order to minimize delays to the
extent practicable. Neither increased costs of performance nor
changed economic circumstances shall be considered a Force Majeure
Event. Force Majeure may include delays caused by failure to obtain
Federal, State, or local permits provided Respondent proves force
majeure and demonstrates that Respondent timely submitted all
information and documentation required for applications for permits
(and any supplemental information that may be requested) within a
timeframe that would permit work to proceed in accordance with EPA-
approved schedules.
15.3 Respondent shall have the burden of proving that a Force Majeure Event
has occurred.
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15.4 The Respondent shall notify EPA of any delay or anticipated delay in
achieving compliance with any requirement of this Consent Order,
including any approved Submission. Such notification shall be made
orally as soon as possible but no later than two (2) business days
after Respondent or any of its agents or contractors becomes aware of
such delay, or through the exercise of due diligence should have
become aware of such delay, and in writing no later than seven (7)
days after Respondent or any of its agents or contractors becomes
aware, or through the exercise of due diligence should have become
aware, of such a delay or anticipated delay. The written
notification, which shall be certified in accordance with Section 8.11
of this Consent Order, shall describe in reasonable detail the nature
of the delay; the reasons the delay is beyond the control of
Respondent (if applicable); the actions that will be taken to
mitigate, prevent, and/or minimize further delay; the anticipated
length of the delay; and the timetable according to which the actions
to mitigate, prevent, and/or minimize the delay will be taken. The
Respondent shall adopt all reasonable measures to avoid and minimize
any such delay. Failure of the Respondent to comply with the notice
requirements of this Section shall constitute a waiver of the
Respondent's right to invoke the benefits of Section 15.1 of this
Consent Order with respect to that event.
15.5 In the event that EPA and the Respondent cannot agree that a
particular delay in achieving compliance with the requirements of this
Consent Order, including any approved Submission, has been or will be
caused by a Force Majeure Event, the dispute shall be resolved in
accordance with the provisions of Section XIII of this Consent Order.
The Respondent shall have the burden of proving that the delay was
caused by a Force Majeure Event.
15.6 Modifications to this Consent Order following a Force Majeure Event
shall be made in accordance with Section XXIII of this Consent Order.
XVI. RESERVATION OF RIGHTS
16.1 Except as expressly provided in this Consent Order, (1) each party
reserves all rights, claims, interests, and defenses it may otherwise
have, including Respondent's right to seek contribution and any right
it may have to seek legal or equitable relief from any action by EPA
under this Consent Order which Respondent alleges may result in
irreparable harm to Respondent in the discharge of its
responsibilities as a natural gas pipeline company, and (2) nothing
herein shall prevent EPA from seeking legal or equitable relief to
enforce the terms of this Consent Order, including the right to seek
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EPA Docket No. III-94-35-DC 46
injunctive relief and/or the imposition of statutory penalties.
16.2 As provided by this Consent Order, EPA expressly reserves its right to
disapprove of any work performed by Respondent which is not performed
to EPA's satisfaction in accordance with this Consent Order; to halt
work being performed by Respondent if Respondent has not complied with
an approved work plan or this Consent Order, or at any time EPA deems
necessary to protect public health, welfare, or the environment, and
to perform such work; and to request and require hereunder that
Respondent correct and/or re-perform any and all work disapproved by
EPA; and/or to request or require that Respondent perform response
actions in addition to those required by this Consent Order. In the
event EPA requires Respondent, and Respondent declines, to correct
and/or re-perform work that has been disapproved by EPA and/or to
perform response actions in addition to those required by this Consent
Order, EPA reserves the right to undertake such actions and seek
reimbursement of the costs incurred, and/or to seek any other
appropriate relief. In addition, EPA reserves the right to undertake
removal and/or remedial actions at any time that such actions are
appropriate under the NCP and to seek reimbursement for any costs
incurred and/or take any other action authorized by law.
16.3 EPA reserves all rights it may have to bring an action against the
Respondent for recovery of all oversight and other response costs
provided for by Section XVII of this Consent Order which have been
incurred by the United States in connection with this Consent Order
and which are not reimbursed by the Respondent, as well as any other
costs incurred by the United States for response actions conducted in
connection with the Site.
16.4 Except as expressly provided in Section XXVI of this Consent Order,
EPA reserves all rights including, without limitation, the right to
institute legal action against Respondent and/or any other persons in
connection with the performance of any response actions not addressed
by this Consent Order including, but not limited to, response actions
at areas of the Site not identified by Respondent as required by
Section 8.2 of this Consent Order and response actions deemed
necessary by EPA at areas of the Site which have been removed from the
Work Scope List pursuant to Sections 8.2 (d), 8.4, and 8.5(d) of this
Consent Order.
16.5 Nothing in this Consent Order shall limit the authority of the EPA
Project Coordinator under CERCLA and the NCP.
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XVII. REIMBURSEMENT OF COSTS
17.1 EPA will submit to the Respondent on a periodic basis a summary report
of response costs, including oversight costs and any costs of
obtaining access to property pursuant to Section 12.2 of this Consent
Order, paid by the U.S. Government in connection with this Consent
Order. Oversight costs shall include administrative, enforcement,
inspection, and investigative costs paid by EPA, its agents, or
contractors in connection with EPA's oversight of the work performed
by the Respondent under the terms of this Consent Order and shall
include, but not be limited to, time and travel costs of EPA personnel
and associated indirect costs, contractor costs, costs of compiling
cost documentation, compliance monitoring, collection and analysis of
split samples, inspection of activities, Site visits, interpretation
of Consent Order provisions, discussions regarding disputes that may
arise as a result of this Consent Order, and review and approval or
disapproval of reports. In view of the decision in United States v.
Rohm and Haas Co., No. 92-1517 (3d Cir.: Aug. 12, 1993) regarding the
liability of responsible parties for reimbursement of oversight costs
under section 107(a) of CERCLA, 42 U.S.C. section 9607(a), the
summary report shall, to the extent practical, distinguish costs
incurred for oversight performed at locations in the States of New
Jersey and Delaware and the Commonwealth of Pennsylvania from all
other oversight costs incurred in connection with this Consent Order.
17.2 Upon request, Respondent shall have the right to examine the
documentation in EPA's possession on which the summary report
described in Section 17.1 of this Consent Order is based. Requests
for such documentation shall be made in writing and must be received
by EPA within fourteen (14) days from the date Respondent receives the
summary report. All documents provided to Respondent by EPA pursuant
to this paragraph shall be handled in the manner set forth in Section
17.4 of this Consent Order.
17.3 (a) Except as provided in Section 17.3(b) of this Consent order,
the amount identified in the summary report provided under
Section 17.1 of this Consent Order shall be due and payable by
Respondent no later than thirty (30)'calendar days of receipt
of such summary report, or of the documents provided by EPA
pursuant to Section 17.2 of this Consent Order, whichever is
later. On or before the date such amount is due and payable,
Respondent shall remit a check for the amount of those costs
made payable to the "Hazardous Substances Superfund."
Interest at a rate established pursuant to section 107(a) of
CERCLA, 42 U.S.C. section 9607(a), shall begin to accrue on
the unpaid
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EPA Docket No. III-94-35-DC 48
balance from that date, even if there is a dispute or an
objection to any portion of the costs. Checks should
specifically identify the Site name and be forwarded to:
U.S. Environmental Protection Agency
Region III
Attention: Superfund Accounting
Box 360515
Pittsburgh, PA 15251-6515
A copy of the transmittal letter and check shall be sent to
the EPA Project Manager and to the EPA Region III Regional
Hearing Clerk at the address specified in Section XIV of this
Consent Order.
(b) Respondent shall not be obligated by this Consent Order to
reimburse the United States for costs incurred for oversight
of work performed at locations in the States of New Jersey and
Delaware and the Commonwealth of Pennsylvania unless the
decision in United States v. Rohm and Haas Co., No. 92-1517
(3d Cir.: Aug. 12, 1993) regarding the liability of
responsible parties for reimbursement of oversight costs under
section 107(a) of CERCLA, 42 U.S.C. section 9607(a) , is
reversed or overturned by the United States Court of Appeals
for the Third Circuit, the United States Supreme Court, or the
United States Congress through statutory amendment or
otherwise. In such event, EPA will notify Respondent of the
oversight costs due and payable under this Consent Order in
connection with oversight performed in these states.
Respondent shall, within thirty (30) calendar days of receipt
of such notice, reimburse such costs in accordance with
Section 17.3(a) of this Consent Order.
(c) Nothing in this Consent Order shall be deemed to be an
admission by EPA or the United States regarding the liability
of responsible parties to reimburse oversight costs incurred
by the United States. Nothing in this Consent Order shall be
admissible in any proceeding as to the legal issue whether
oversight costs are properly recoverable under section 107 of
CERCLA, 42 U.S.C. section 9607, or pursuant to a settlement of
any action brought thereunder.
17.4 Respondent acknowledges that documents provided by EPA pursuant to
Section 17.2 of this Consent Order may include documents which have
been submitted to EPA by various contractors and which contain certain
information which may be entitled to confidential treatment under 40
C.F.R. Part 2. EPA and Respondent agree that limitation on the
disclosure of such documents is necessary in order to protect the
interests
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EPA Docket No. III-94-35-DC 49
of the submitters in the confidentiality of their business
information. Accordingly, documents provided by EPA pursuant to
Section 17.2 of this Consent Order shall be subject to the following:
a. EPA shall provide the documents containing information which
may be entitled to confidential treatment to Respondent and
such documents shall be handled in accordance with the
requirements of this Section.
b. As used in this Section, the term "confidential information"
means trade secrets or commercial or financial information
submitted by a person to EPA and which may be entitled to
confidential treatment under 40 C.F.R. Part 2. Such
"confidential information" has not been determined by EPA
under 40 C.F.R. Part 2, Subpart B, to be entitled to
confidential treatment.
c. Any information to be produced by EPA pursuant to Section 17.2
of this Consent Order and which may be entitled to
confidential treatment under 40 C.F.R. Part 2 shall be stamped
conspicuously with the word "CONFIDENTIAL" by EPA at the top
of each page of each document prior to transmittal to
Respondent. The transmittal of information designated as
confidential shall be done by letter from EPA stating that the
information is designated as confidential and is subject to
this Consent Order.
d. Information designated as confidential under this Section 17.4
shall not be used or disclosed by Respondent or any person
subject to paragraph (e) below for any purpose other than
reimbursement of costs in accordance with this Consent Order.
e. Respondent and its counsel who obtain information designated
as confidential hereunder, and any nonparty subject to this
Section 17.4, shall not disclose or permit disclosure of this
information to any other person including, without limitation,
any officer, director, employee, agent, or representative of
Respondent, Respondent's counsel, or any nonparty, except in
the following circumstances:
1. Disclosure may be made to employees of Respondent or
of Respondent's counsel who have responsibility for
reimbursement of costs pursuant to this Consent
Order. Any employee to whom disclosure is made shall
be advised of, and become subject to, this Section
17.2 prior to such disclosure by signing a
Confidentiality Agreement which reads substantially
as follows:
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50
"CONFIDENTIALITY AGREEMENT. The undersigned is
currently working at ___________ which is located at
___________. During the past year the undersigned
has been employed or otherwise engaged as a
contractor or consultant by the following companies
located at the corresponding addresses: _________,
_____________. The undersigned hereby acknowledges
that he/she has read Section 17.4 of the Consent
Order between EPA and Columbia Gas Transmission
Corporation [EPA Docket No. III-94-35-DC] ["Consent
Order"], understands the terms thereof, and agrees to
be bound by such terms. The undersigned understands
that disclosure of information which has been
designated as confidential by EPA may cause
substantive harm to the affected business'
competitive position. Accordingly, among other
responsibilities, the undersigned shall only share
such information with persons specifically authorized
to receive the information pursuant to the Consent
Order, shall retain the information in a secure
manner, and shall use such information only for the
purposes authorized by the Consent Order. The
undersigned understands that this pledge of
confidentiality continues for an indefinite term.
Furthermore, the undersigned understands that a
breach of this Confidentiality Agreement may subject
him/her to damages and to criminal prosecution under
42 U.S.C. section 9604 (e) (7) (B) .
"Signed: ____________________________________________
"Dated: ____________________________________________."
Employees do not include persons, firms, or
corporations engaged by Respondent or Respondent's
counsel on a contract basis, who shall be subject to
the requirements of subparagraph 2 of this Paragraph.
2. Disclosure may be made to consultants, witnesses,
experts, or employees of experts ["Experts"] employed
or otherwise engaged by Respondent or Respondent's
counsel to assist in complying with this Consent
Order. Prior to disclosure to any Expert, the Expert
must agree to be bound to the terms of this Section
17.4 by executing a Confidentiality Agreement
substantially in the form set forth in subparagraph
(1) above. A copy of each executed Confidentiality
Agreement shall be furnished to EPA not less than
five (5) business
<PAGE> 53
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 51
days prior to disclosure to the Expert of the business
information.
f. Respondent, Respondent's counsel, and any other person subject
to this Section who obtains information designated as
confidential hereunder shall take all necessary and
appropriate measures to maintain the confidential nature of
the information, shall share such information only with
persons authorized to receive it pursuant to this Section
17.4, and shall retain the information in a secure manner.
Except as provided in paragraph (e) above, no other person
shall be permitted access to the information.
g. Any person who obtains access to information designated as
confidential under this Section may make copies, duplicates,
extracts, summaries, or descriptions of the information or any
portion thereof only for the purpose of complying with this
Consent Order. All copies, duplicates, extracts, etc. shall
be subject handled in the manner set forth in this Section
17.4 to the same extent and manner as original documents.
h. Any unauthorized disclosure of information designated as
confidential hereunder shall not result in a waiver of any
submitter's claim of confidentiality.
i. Within sixty (60) days following payment of the amount
identified in each summary report provided pursuant to Section
17.1 of this Consent Order, any person who obtained
information designated as confidential hereunder shall
assemble and return such information to EPA, including all
copies, extracts, summaries, or descriptions of the
information or portions thereof. Such return shall be
certified in writing by the person who obtained the
information from EPA. All such information covered by this
Section which constitutes the work product of counsel or
Respondent shall be destroyed.
17.5 EPA anticipates that it will oversee Respondent's performance under
this Consent Order using EPA personnel and personnel of other agencies
of the United States to the extent practicable. In addition, EPA and
Respondent contemplate that State environmental agencies may provide
oversight of Respondent's work under this Consent Order, provided EPA
determines that such environmental agencies have the personnel and
other resources to provide oversight in accordance with EPA
requirements. The use of such State environmental agencies in
overseeing Respondent's performance under this Consent Order, as well
as the use of Federal and non-Federal personnel, shall be solely at
the discretion of EPA and shall not be subject to dispute
<PAGE> 54
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 52
resolution. EPA intends to notify Respondent's Project Coordinator
when EPA engages any non-Federal personnel to perform oversight of
Respondent's work under this Consent Order.
17.6 On an annual basis, Respondent and EPA will meet to identify and
consider strategies for minimizing oversight costs. Neither the
scheduling nor holding of any such meeting shall delay, alter, or
otherwise affect Respondent's obligation to reimburse any costs at the
time and in the manner provided by this section.
XVIII. RECORD PRESERVATION
18.1 For each location included at any time on the Work Scope List,
Respondent agrees to preserve, during the pendency of this Consent
Order and for a minimum of five (5) years after:
(a) the date such location has been removed from the Work
Scope List by EPA, or
(b) the date on which Respondent receives written notice from EPA
that EPA has accepted the Final Report for such location
pursuant to Section 8.8(d) of this Consent Order,
whichever occurs earlier, all records and documents in its possession
or in the possession of any of its divisions, officers, directors,
employees, successors, and assigns that relate in any way to work
performed under this Consent Order at such location, or to hazardous
substance management and/or disposal at such location, including raw
data, despite any document retention policy to the contrary.
Respondent shall ensure that copies of all such records and documents
that relate to the location and are in the possession of its
employees, agents, accountants, contractors, and attorneys are
retained in accordance with the requirements of this Consent Order.
18.2 Within seven (7) days of the effective date of this Consent Order
Respondent shall designate a Document Coordinator for all records and
documents required to be preserved pursuant to Section 18.1 of this
Consent Order, including records and documents that will be retained
on Respondent's behalf by persons other than Respondent, and shall
notify EPA of the identity of that Custodian. Respondent may change
its Document Coordinator upon written notification to EPA of such
change.
<PAGE> 55
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 53
18.3 Any agreement between Respondent and an agent, contractor, consultant,
accountant, or attorney relating to performance of work under this
Consent Order shall require in writing that said agent, contractor,
consultant, accountant, or attorney maintain and preserve all records
and documents in its possession that in any way relate to such
agreement for the period required of Respondent under Section 18.1 of
this Consent Order.
18.4 Respondent shall not destroy any records or documents required to be
preserved by this Consent Order, including records and documents
claimed as privileged, unless the obligation to maintain and preserve
such records and documents has terminated in accordance with Section
18.5 of this Consent Order.
18.5 (a) Notwithstanding any other provision of this Section, any
obligation of any person to maintain and preserve records and
documents for a particular location included at any time on
the Work Scope List during the pendency of this Consent Order
shall terminate when both:
(1) Five (5) years have passed after the earlier of:
a. the date such location was removed
from the Work Scope List by EPA; or
b. the date on which Respondent receives written
notice from EPA that EPA has accepted
Respondent's Final Report for such location
pursuant to Section 8.8(d) of this Consent
Order;
and
(2) Respondent's Document Coordinator has notified both
(i) EPA Region III, and (ii) the EPA Regional Office
with jurisdiction over the location for which
Respondent seeks to destroy records or documents, by
certified letters to the Regional Administrator(s)
and Regional Counsel(s) stating that, pursuant to
this Consent Order, which shall be attached to such
letters, such records or documents will be destroyed
no less than ninety (90) days after receipt of such
letters unless EPA requests copies of the records and
documents, and either:
a. EPA has failed to request copies of such
records and documents within ninety (90) days
after its receipt of the above-described
<PAGE> 56
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 54
letters, or
b. EPA has requested and received copies or
originals of the documents.
(b) Respondent shall provide EPA with originals or copies of all
non-privileged records and documents, including records and
documents retained by others on behalf of Respondent,
requested by EPA pursuant to this Section within thirty (30)
days following receipt of any such request. In the event that
the Respondent withholds a document as privileged, the
Respondent shall provide EPA with the title of the document,
the date of the document, the name(s) of the author(s), and
addressee(s)/recipient(s), a description of the nature of the
document, and identification of the privilege asserted at the
time any such document is due to be provided to EPA.
Respondent shall not destroy any records or documents claimed
as privileged until EPA has notified Respondent that EPA has
waived its right to obtain such records or documents from
Respondent.
(c) Respondent shall provide the notice required by Section 18.5
(a) (2) of this Consent Order no more than once in any twelve
month period. Each such notice shall identify the location(s)
covered by such notice and shall reasonably identify the
records and documents which Respondent, and/or others
retaining documents on behalf of Respondent, intends to
destroy.
XIX. OTHER CLAIMS
19.1 Nothing in this Consent Order shall constitute or be construed as a
release from any claim, cause of action, or demand in law or equity
against any person, firm, partnership, or corporation not bound by
this Consent Order for any liability it may have arising out of or
relating in any way to the generation, storage, treatment, handling,
transportation, release, or disposal of any hazardous substances,
hazardous wastes, pollutants, or contaminants found at, taken to, or
taken from the Site. With regard to claims for contribution against
Respondent for matters addressed in this Consent Order, EPA and
Respondent agree that Respondent is entitled to such protection from
contribution actions or claims as is provided by section 113(f)(2) of
CERCLA, 42 U.S.C. section 9613(f)(2).
19.2 This Consent Order does not constitute any decision on
preauthorization of funds under section 111(a)(2) of CERCLA, 42 U.S.C.
section 9611(a) (2).
<PAGE> 57
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 55
19.3 By consenting to the issuance of this Consent Order, the
Respondent waives any claim to reimbursement it may have under
sections 106(b) , 111, and 112 of CERCLA, 42 U.S.C. section section
9606(b), 9611, and 9612.
XX. OTHER APPLICABLE LAWS
20.1 All work required by this Consent Order shall be undertaken in
accordance with the requirements of all applicable or relevant and
appropriate local, State, and Federal laws and regulations, as
required by the NCP. In accordance with section 121(e) of CERCLA, 42
U.S.C. section 9621(e), no local, State, or Federal permit shall be
required for any portion of any action conducted entirely on-site,
including studies, where such action is carried out in compliance with
this Consent Order.
XXI. INDEMNIFICATION OF THE UNITED STATES GOVERNMENT
21.1 Respondent agrees to indemnify and save and hold harmless the United
States Government, its agencies, departments, agents, and employees,
from any and all claims or causes of action arising from or on account
of acts or omissions of Respondent or its agents, contractors,
receivers, trustees, and assigns in carrying out activities required
by this Consent Order, except under circumstances in which the United
States Government, its agencies, departments, agents, and employees
were negligent and this negligence was the sole cause of the harm
alleged. This indemnification shall not be construed in any way as
affecting or limiting the rights or obligations of Respondent or the
United States under their various contracts.
XXII. LIABILITY OF THE UNITED STATES GOVERNMENT
22.1 Neither the United States Government nor any agency thereof shall be
liable for any injuries or damages to persons or property resulting
from acts or omissions of Respondent, or of Respondent's employees,
agents, servants, receivers, successors, or assignees, or of any
persons, including, but not limited to firms, corporations,
subsidiaries, contractors, or consultants, in carrying out activities
pursuant to this Consent Order, nor shall the United States Government
or any agency thereof be held as a party to any contract entered into
by Respondent in carrying out activities pursuant to this Order.
<PAGE> 58
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 56
XXXXI. SUBSEQUENT MODIFICATION
23.1 This Consent Order may be amended by mutual agreement of EPA and the
Respondent. Such amendments shall be in writing and shall have as
their effective date, the date on which such amendments are signed by
EPA.
23.2 (a) Minor modifications to the requirements Of the ASAWPs, CWPs,
and RAWPs, specifically those which EPA determines do not
materially or significantly affect the nature, scope, or
timing of the work to be performed, may be made by mutual
agreement of the Project Coordinators. Any such modifications
must be in writing and signed by both Project Coordinators.
The effective date of the modification shall be the date on
which the letter from EPA's Project Coordinator is signed.
(b) Modifications to the requirements of the ASAWPs, CWPs, or
RAWPs that are not minor modifications as described in Section
23.2 (a) of this Consent Order may be made by mutual agreement
of EPA and the Respondent. Any such modifications must be in
writing and signed by Respondent's Project Coordinator and the
chief of the Region III Toxic and Pesticides Branch or his/her
designee. The effective date of the modification shall be the
date on which the modification in signed by EPA.
23.3 Respondent agrees that any request for modification of this Consent
Order by Respondent shall be accompanied by a statement of how such
modification shall affect the schedules set forth in all affected work
plans.
23.4 Following EPA approval of a modification to a schedule, Respondent
agrees, within seven (7) days of receipt of the modification, to
supply to EPA a revised schedule and accompanying charts which shall
reflect the approved modifications to such schedule.
23.5 Any reports, plans, specifications, schedules, or other submissions
required by this Consent Order and any modifications thereto are, upon
approval by EPA, enforceable as requirements of this Consent Order.
Any non-compliance with such EPA-approved or modified reports, plans,
specifications, schedules, or other submissions shall be considered
non-compliance with the requirements of this Consent Order and shall
subject the Respondent to, among other things, the requirements of
Section XIV of this Consent Order.
23.6 No informal advice, guidance, suggestions, or comments by EPA, other
than a formal approval as specified in Section IX of this Consent
Order, regarding reports, plans, specifications,
<PAGE> 59
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 57
schedules, and any other writing submitted by the Respondent or
regarding any other requirement of this Consent Order will be
construed as relieving the Respondent of its obligation to obtain
formal approval when required by this Consent Order, and to comply
with requirements of this Consent Order, unless formally modified.
XXIV. EFFECTIVE DATE
24.1 Within forty-five (45) days following receipt of a fully executed true
and correct copy of this Consent Order, Respondent shall file papers
with the United States Bankruptcy Court for the District of Delaware
seeking authority to be bound by the terms of this Consent Order.
Respondent shall provide EPA with a copy of all relevant moving papers
and shall give EPA reasonable notice of any hearings with respect to
such matter. Respondent shall further provide EPA with copies of any
written decisions and orders issued by the Court relating to this
matter within five (5) days of Respondent's receipt of such documents
and shall provide EPA with copies of all appeal petitions and related
documents and all written appellate decisions and orders relating to
this matter within five (5) days following receipt by Respondent of
such documents. Respondent shall notify EPA in writing no later than
three (3) business days after the date that the period for all appeals
from any decision by the Bankruptcy Court or appellate Court which
provides Respondent with authority to be bound by any of the terms of
this Consent Order has expired, provided no appeals have been filed.
All notices and documents required to be provided to EPA pursuant to
this Section 24.1 shall be forwarded to:
Andrew S. Goldman (3RC21)
Sr. Assistant Regional Counsel
U.S. Environmental Protection Agency
841 Chestnut Building
Philadelphia, PA 19107
(215) 597-4840
This Section 24.1 shall be effective three (3) business days following
the date on which EPA forwards a fully executed true and correct copy
of this Consent Order to Respondent.
24.2 EPA reserves the right to withdraw its consent from this Consent Order
at any time prior to the effective date of this Consent Order as
provided by this Section 24.2, or at any time following modification
of this Consent Order or its requirements by the United States
Bankruptcy Court, or any appellate Court, during the pendency of
Respondent's bankruptcy. Following resolution of all appeals relating
to Respondent's
<PAGE> 60
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 58
authority to be bound by the terms of this Consent Order, EPA will
evaluate the Court's grant of authority to Respondent, including the
attachment of any conditions or limitations on Respondent's authority
to be bound by the terms of this Consent Order, and will notify
Respondent of EPA's decision whether it continues to consent to this
Consent Order. Except as provided in Section 24.1 of this Consent
Order, the effective date of this Consent Order shall be three (3)
business days following the date on which EPA forwards written notice
to Respondent that EPA continues to consent to this Consent Order.
24.3 Nothing in this Consent Order shall be construed as an admission by
EPA that (i) Respondent's liability to perform response actions at the
Site under CERCLA, to reimburse the United States for all costs
incurred in connection with response actions undertaken by EPA at the
Site pursuant to CERCLA, or to comply with any law or regulation
administered by EPA is conditioned on approval by or authority from
the United States Bankruptcy Court, or (ii) that authority to enforce
this Consent Order rests with the United States Bankruptcy Court.
Except as otherwise provided by this Consent Order, EPA reserves the
right to issue such orders as may be necessary to require that
Respondent perform the work described in this Consent Order.
XXV. NOTICE OF COMPLETION/TERMINATION OF ORDER
25.1 When Respondent believes that (1) Characterization Reports for all
locations included in the approved Work Scope List have been submitted
to, and approved by, EPA; (2) Final Reports required by Section 8.7(d)
of this Consent Order have been submitted and approved by EPA for all
locations included in the approved Work Scope List; (3) all costs
reimburseable under Section XVII of this Consent Order and identified
by EPA have been paid to EPA; and (4) all penalties assessed by EPA
pursuant to this Consent Order have been paid to EPA, Respondent shall
so notify EPA in writing ["Respondent's Completion Petition"].
25.2 If, following receipt of Respondent's Completion Petition, EPA
determines that (1) Characterization Reports for all locations
included in the approved Work Scope List have been submitted to, and
approved by, EPA; (2) Final Reports required by Section 8.7(d) of this
Consent Order have been submitted and approved by EPA for all
locations included in the approved Work Scope List; (3) all costs
identified by EPA in each summary report provided to Respondent
pursuant to Section 17.1 of this Consent Order have been paid to EPA;
and (4) all penalties assessed by EPA pursuant to this Consent Order
have
<PAGE> 61
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 59
been paid to EPA, EPA shall so notify Respondent in writing ["Notice
of Completion"]. Except as provided herein, this Consent Order shall
be deemed terminated upon Respondent's receipt of a Notice of
Completion from EPA. EPA's issuance of a Notice Of Completion shall
not terminate or otherwise affect Sections I (Jurisdiction/General
Provisions/Definitions), II (Statement of Purpose), III (EPA Findings
of Fact), IV (Conclusions of Law), V (Determinations), VI (Parties
Bound) (Section 6.1 only), XIV (Delay in Performance and Stipulated
Penalties), XV (Force Majeure and Notification of Delay), XVI
(Reservation of Rights), XVII (Reimbursement of Costs), XVIII (Record
Preservation), XIX (Other Claims), XXI (Indemnification of the United
States Government), and XXII (Liability of the United States
Government), XXVI (Covenant Not to Sue) of this Consent Order. EPA
reserves the right to require hereunder that Respondent reimburse all
costs identified in summary reports provided to Respondent pursuant to
Section 17.1 of this Consent Order after issuing a Notice of
Completion pursuant to this Paragraph.
25.3 If EPA does not agree that (1) Characterization Reports for all
locations included in the approved Work Scope List have been
submitted to, and approved by, EPA; (2) removal response actions
selected by EPA for implementation at all locations included in the
approved Work Scope List have been completed; (3) all costs
reimburseable under Section XVII of this Consent Order have been paid
to EPA; and (4) all penalties assessed by EPA pursuant to this Consent
Order have been paid to EPA, EPA shall notify Respondent in writing of
the activities that must be undertaken to complete such work. If
applicable, EPA will set forth a schedule for performance of such
activities consistent with this Consent Order or may require
Respondent to submit a schedule for EPA approval. Respondent shall
perform all activities described in EPA's notice in accordance with
the specifications and schedules established pursuant to this
paragraph, subject to Respondent's right to invoke dispute resolution
under Section XIII of this Consent Order, and shall submit a
Completion Petition to EPA in accordance with Section 25.1 of this
Consent Order.
XXVI. COVENANT NOT TO SUE
26.1 From the effective date of this Consent Order and for as long as EPA
determines that the terms of this Consent Order, including any
modifications made hereto, are being and have been fully complied
with, and except for any proceeding to enforce its terms or collect
any applicable costs or penalties, EPA agrees not to sue or take any
administrative action against the Respondent, its assigns, and
successors in interest, for the work required by this Consent Order or
for
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Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 60
reimbursement of costs incurred in connection with this Consent Order.
26.2 Nothing in this Consent Order shall be construed to limit the rights
EPA has reserved under Section XVI of this Consent Order.
26.3 Nothing in this Consent Order shall be construed to grant any rights
to persons not a party to this Consent Order.
XXVII. DISCLAIMER
27.1 By signing this Consent Order and taking actions under this Consent
Order, Respondent does not necessarily agree with EPA's Findinqs of
Fact and Conclusions of Law. Furthermore, the participation of
Respondent in this Consent Order shall not be considered an admission
of liability and is not admissable in evidence against Respondent in
any judicial or administrative proceeding other than a proceeding by
the United States, including EPA, to enforce this Consent Order or a
judgment relating to this Consent Order. Respondent retains its
rights to assert claims against other potentially responsible parties
at any location covered by this Consent Order.
<PAGE> 63
Columbia Gas Pipeline Site
EPA Docket No. III-94-35-DC 61
IT IS SO AGREED AND ORDERED:
FOR THE U.S. ENVIRONMENTAL PROTECTION AGENCY:
/s/ JEANNE M. FOX AUGUST 18, 1994
- -------------------------------------------- ---------------------
Jeanne M. Fox Date
Regional Administrator
EPA Region II
/s/ PETER H. KOSTMAYER SEPTEMBER 22, 1994
- -------------------------------------------- ---------------------
Peter H. Kostmayer Date
Regional Administrator
EPA Region III
/s/ JOHN HANKINSON, JR. SEPTEMBER 23, 1994
- -------------------------------------------- ---------------------
John Hankinson, Jr. Date
Regional Administrator
EPA Region IV
/s/ VALDAS ADAMKUS AUGUST 17, 1994
- -------------------------------------------- ---------------------
Valdas V. Adamkus Date
Regional Administrator
EPA Region V
FOR THE RESPONDENT:
The undersigned hereby certifies that he or she is authorized to execute this
Consent Order on behalf of the Respondent for whom he or she is signing and to
bind such Respondent to the terms and conditions herein:
/s/ R. LARRY ROBINSON SEPTEMBER 21, 1994
- -------------------------------------------- ---------------------
Date
Print Name: R. Larry Robinson
--------------------------------
Position: President
--------------------------------
<PAGE> 1
EXHIBIT 10-CN
================================================================================
AMENDED AND RESTATED SECURED REVOLVING CREDIT AGREEMENT
================================================================================
BETWEEN
THE COLUMBIA GAS SYSTEM, INC., A DEBTOR IN POSSESSION,
AND
CHEMICAL BANK
================================================================================
DATED AS OF SEPTEMBER 15, 1994
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
ARTICLE I. DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Section 1.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Section 1.2 Accounting Terms and Determinations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Section 1.3 Other Definitional Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
ARTICLE II. AMOUNT AND TERMS OF COMMITMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Section 2.1 Commitment of the Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Section 2.2 Agreement to Repay Letter of Credit Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Section 2.3 Commitment Fee; Letter of Credit Fee; Other
Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Section 2.4 Optional Termination or Reduction of Commitment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Section 2.5 Requirements of Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Section 2.6 Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Section 2.7 Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Section 2.8 Priority and Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Section 2.9 Right of Set-Off . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Section 2.10 Rating Downgrade; Alternative Fronting Banks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
ARTICLE III. CONDITIONS PRECEDENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Section 3.1 Conditions Precedent to Effectiveness of
Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Section 3.2 Conditions Precedent to Each Letter of Credit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
ARTICLE IV. REPRESENTATIONS AND WARRANTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Section 4.1 Organization and Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Section 4.2 Due Execution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Section 4.3 Effectiveness of Order . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Section 4.4 Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Section 4.5 Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Section 4.6 Security Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Section 4.7 Not an Investment Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Section 4.8 No Conflicting Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Section 4.9 No Defenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
ARTICLE V. COVENANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Section 5.1 Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Section 5.2 Maintenance of Property; Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Section 5.3 Compliance with Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Section 5.4 Inspection of Property; Books and Records . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Section 5.5 Chapter 11 Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Section 5.6 Corporate Existence; No Change in Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Section 5.7 Further Assurances; Security Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Section 5.8 Chapter 11 Claims and Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
ARTICLE VI. EVENTS OF DEFAULTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
</TABLE>
-i-
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<TABLE>
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<S> <C>
ARTICLE VII. MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Section 7.1 Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Section 7.2 No Waivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Section 7.3 Expenses; Documentary Taxes; Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Section 7.4 Amendments and Waivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Section 7.5 NEW YORK LAW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Section 7.6 Counterparts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Section 7.7 WAIVER OF TRIAL BY JURY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Section 7.8 Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Section 7.9 Confidentiality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
</TABLE>
EXHIBITS
Exhibit A Form of Security Agreement
Exhibit B Form of Letter of Credit Request
-ii-
<PAGE> 4
EXHIBIT 10-CN
AMENDED AND RESTATED SECURED REVOLVING CREDIT AGREEMENT
DATED AS OF SEPTEMBER 15, 1994
AMENDED AND RESTATED SECURED REVOLVING CREDIT AGREEMENT, dated
as of September 15, 1994, between THE COLUMBIA GAS SYSTEM, INC., a Delaware
corporation (the "Company"), a debtor-in-possession in proceedings under
Chapter 11 of the Bankruptcy Code, and CHEMICAL BANK, a New York banking
corporation (the "Bank", including its successors by merger or otherwise).
INTRODUCTORY STATEMENT
On July 31, 1991 (the "Filing Date") the Company and its
wholly-owned Subsidiary, Columbia Gas Transmission Corporation ("TCO"), filed
petitions with the United States Bankruptcy Court for the District of Delaware,
initiating proceedings in reorganization under Chapter 11 of Title 11 of the
United States Code.
Pursuant to the Secured Revolving Credit Agreement, dated as
of September 23, 1991 (as heretofore amended, supplemented or otherwise
modified, the "Original Agreement"), among the Company, the banks from time to
time parties thereto, and the Bank, as agent for such banks, a senior secured
revolving credit facility in an aggregate principal amount of up to
$275,000,000 was provided by such banks to the Company for the making of
revolving credit loans and for the issuance of Letters of Credit for the
benefit of various insurance companies, state agencies and other entities.
Upon request of the Company, the Banks party to the Original
Agreement have reduced their aggregate commitments under the Original Agreement
to $100,000,000.
To provide security for the obligations of the Company under
the Original Agreement, the Company provided to the Bank, as agent, certain
Liens on certain property of the Company (as more fully described in the
Original Security Agreement referred to herein) and an allowed administrative
expense claim in the Chapter 11 Case pursuant to Section 364(c)(1) of the
Bankruptcy Code having priority, subject to a Carve-Out (as herein defined),
over all administrative expenses of the kind specified in Sections 503(b) and
507(b) of the Bankruptcy Code.
In order to reduce certain fees currently payable under the
Original Agreement, the Company has requested that the Bank and the other banks
party to the Original Agreement agree to amend the Original Agreement to
eliminate the commitments of all banks party thereto other than the Bank, to
release the Liens on certain collateral under the Original Security Agreement
and to provide that the Commitment of the Bank shall be $25,000,000 and shall
be available only for the issuance of Letters of Credit from time to time.
Subject to the terms and conditions set forth herein, the Bank
is willing to agree to the Company's request.
<PAGE> 5
NOW THEREFORE, the parties hereto hereby agree to amend and
restate the Original Agreement in its entirety as follows:
ARTICLE I. DEFINITIONS
SECTION 1.1 DEFINITIONS. The following terms, as used
herein, have the following meanings:
"Agreement" means this Amended and Restated Secured Revolving
Credit Agreement, as it may be amended, modified or supplemented from
time to time.
"Alternate Base Rate" for any day, means a rate per annum
(rounded upwards, if necessary, to the next 1/16 of 1%) equal to the
greatest of (a) the Prime Rate in effect on such day, (b) the Base CD
Rate in effect on such day plus 1% and (c) the Federal Funds Effective
Rate in effect on such day plus 1/2 of 1%. For purposes hereof:
"Prime Rate" shall mean the rate of interest per annum publicly
announced from time to time by the Bank as its prime rate in effect at
its principal office in New York City (the Prime Rate not being
intended to be the lowest rate of interest charged by Chemical Bank in
connection with extensions of credit to debtors); "Base CD Rate" shall
mean the sum of (a) the product of (i) the Three-Month Secondary CD
Rate and (ii) a fraction, the numerator of which is one and the
denominator of which is one minus the C/D Reserve Percentage and (b)
the C/D Assessment Rate; "Three-Month Secondary CD Rate" shall mean,
for any day, the secondary market rate for three-month certificates of
deposit reported as being in effect on such day (or, if such day shall
not be a Business Day, the next preceding Business Day) by the Board
through the public information telephone line of the Federal Reserve
Bank of New York (which rate will, under the current practices of the
Board, be published in Federal Reserve Statistical Release H.15(519)
during the week following such day), or, if such rate shall not be so
reported on such day or such next preceding Business Day, the average
of the secondary market quotations for three-month certificates of
deposit of major money center banks in New York City received at
approximately 10:00 A.M., New York City time, on such day (or, if such
day shall not be a Business Day, on the next preceding Business Day)
by the Bank from three New York City negotiable certificate of deposit
dealers of recognized standing selected by it; and "Federal Funds
Effective Rate" shall mean, for any day, the weighted average of the
rates on overnight federal funds transactions with members of the
Federal Reserve System arranged by federal funds brokers, as published
on the next succeeding Business Day by the Federal Reserve Bank of New
York, or, if such rate is not so published for any day which is a
Business Day, the average of the quotations for the day of such
transactions received by the Bank from three federal funds brokers of
recognized standing selected by it. Any change in the Alternate Base
Rate due to a change in the Prime Rate, the Three-Month Secondary CD
Rate or the Federal Funds Effective Rate shall be effective as of
the opening of business on the effective day of such change in the
Prime Rate, the Three-
<PAGE> 6
3
Month Secondary CD Rate or the Federal Funds Effective Rate,
respectively.
"Bank" has the meaning set forth in the preamble to this
Agreement.
"Bankruptcy Code" means the Bankruptcy Reform Act of 1978 as
heretofore and hereafter amended and codified as 11 U.S.C. Section 101
et seq.
"Bankruptcy Court" means the United States Bankruptcy Court
for the District of Delaware having jurisdiction over the Chapter 11
Case.
"Board" means the Board of Governors of the Federal Reserve
System of the United States.
"Business Day" means any day except a Saturday, Sunday or
other day on which commercial banks in New York City are authorized by
law to close.
"Carve-Out" has the meaning set forth in Section 2.8(a).
"Cash Collateral Account" has the meaning set forth in the
Security Agreement.
"C/D Assessment Rate" means, for any day, the net annual
assessment rate (rounded upward to the nearest 1/100th of 1%)
determined by the Bank to be payable on such day to the Federal
Deposit Insurance Corporation or any successor thereof for its
insuring Dollar time deposits at offices of the Bank in the United
States.
"C/D Reserve Percentage" means, for any day, that percentage
(expressed as a decimal) which is in effect on such day, as prescribed
by the Board for determining the maximum reserve requirement for a
member bank of the Federal Reserve System in New York City with
deposits exceeding one billion Dollars, in respect of new non-personal
time deposits in Dollars in New York City having maturities of three
months.
"Chapter 11 Case" means the case of the Company administered
under Case No. 91-803 in the Bankruptcy Court.
"Code" means the Internal Revenue Code of 1986, as amended, or
any successor statute.
"Collateral" means the property of the Company, tangible and
intangible, and the proceeds thereof subject from time to time to the
Liens created by the Final Order and the Security Agreement.
"Commitment" means the commitment of the Bank to issue or
participate in Letters of Credit having an aggregate face
<PAGE> 7
4
amount at any time outstanding not in excess of the lesser of (a)
$25,000,000, (b) the amount of the commitment approved by the
Bankruptcy Court in the Final Order and (c) the amount of the
commitment approved by the Securities and Exchange Commission in the
SEC Order.
"Company" has the meaning set forth in the preamble of this
Agreement.
"Default" means any condition or event which with the giving
of notice or lapse of time or both would, unless cured or waived,
become an Event of Default.
"Dollars" or "$" means dollars in lawful currency of the
United States of America.
"Effective Date" has the meaning set forth in Section 3.1.
"ERISA" means the Employee Retirement Income Security Act of
1974, as amended.
"Event of Default" has the meaning set forth in Article VI.
"Filing Date" has the meaning set forth in the Introductory
Statement to this Agreement.
"Final Order" means the order entered by the Bankruptcy Court
on August 16, 1994 in the Chapter 11 Case approving this Agreement.
"Fronting Bank", with respect to any Letter of Credit, means
the financial institution issuing such Letter of Credit. The Fronting
Bank with respect to Letters of Credit issued hereunder shall be the
Bank or, at the election of the Company, in the case of any Letter of
Credit issued during a Rating Downgrade Period, an alternative
financial institution designated to act in such capacity in accordance
with Section 2.10.
"Governmental Authority" means any nation or government, any
state or other political subdivision thereof and any entity exercising
executive, legislative, judicial, regulatory or administrative
functions of or pertaining to government.
"L/C Coverage Requirement" means, at any time, with respect to
each Letter of Credit, an amount equal to 105% of the Stated Amount of
such Letter of Credit.
"Letter of Credit" means an irrevocable standby letter of
Credit issued by the Bank pursuant to the Original Agreement or by a
Fronting Bank pursuant hereto under which the Bank or Fronting Bank,
as the case may be, agrees to make payments in
<PAGE> 8
5
Dollars for the account of the Company or the joint and several
account of the Company and any Subsidiary (other than TCO), in respect
of obligations of the Company or any Subsidiary (other than TCO).
"Letter of Credit Fee" has the meaning set forth in Section
2.3(b).
"Letter of Credit Outstandings" means, at any time, without
duplication, the sum of (a) the aggregate Stated Amount of all
outstanding Letters of Credit and (b) the aggregate amount of all
Unpaid Drawings.
"Letter of Credit Request" has the meaning set forth in
Section 2.1(c).
"Lien" means, with respect to any asset, any mortgage, lien,
pledge, charge, security interest or encumbrance of any kind in
respect of such asset. For the purposes of this Agreement, the
Company or any Subsidiary of the Company shall be deemed to own
subject to a Lien any asset which it has acquired or holds subject to
the interest of a vendor or lessor under any conditional sale
agreement, capital lease or other title retention agreement relating
to such asset.
"Material Adverse Effect" means a material adverse effect on
(a) the business, operations, property, condition (financial or
otherwise) or prospects of the Company and its Subsidiaries (other
than TCO) taken as a whole, (b) the ability of the Company to perform
its obligations under this Agreement or the Security Agreement or (c)
the validity or enforceability of this Agreement or the Security
Agreement or the rights or remedies of the Bank or any Fronting Bank
hereunder or thereunder.
"Maturity Date" means December 31, 1995, or such later date as
may be from time to time agreed by the Company and the Bank.
"Obligations" means the reimbursement obligations in respect
of Letters of Credit, and all other monetary obligations of the
Company to the Bank or any Fronting Bank under this Agreement and the
Security Agreement.
"Original Agreement" has the meaning set forth in the
Introductory Statement to this Agreement.
"Original Security Agreement" means the security agreement,
dated as of September 23, 1991, between the Company and the Bank, as
agent under the Original Agreement.
"Permitted Liens" means:
<PAGE> 9
6
(a) Liens for Post-Petition taxes, assessments,
governmental charges or levies not yet due or which are being
contested in good faith and by appropriate proceedings if
adequate reserves with respect thereto are maintained on the
books of the Company or the appropriate Subsidiary, as the
case may be, in accordance with generally accepted accounting
principles; and
(b) statutory Liens of landlords and carriers',
warehousemen's, mechanics', materialmen's, repairmen's or
other like Liens arising in the ordinary course of business
which are not overdue or which are being contested in good
faith and by appropriate proceedings in a manner which will
not jeopardize or diminish the interest of the Bank in any of
the Collateral or interfere with the ordinary conduct of the
business of the Company or any Subsidiary (other than TCO).
"Person" means an individual, a corporation, a partnership, an
association, a trust or any other entity or organization, including a
government or political subdivision or an agency or instrumentality
thereof.
"Post-Petition" means and refers to any time on or after the
Filing Date.
"Pre-Petition" means and refers to any time prior to the
Filing Date.
"PUHCA" means the Public Utility Holding Company Act of 1935,
as amended.
"Rating Downgrade" means any date on which the Bank's
long-term indebtedness rating is reduced below either A- by Standard &
Poor's Rating Group ("S&P") or A3 by Moody's Investors Service, Inc.
("Moody's").
"Rating Downgrade Period" means any period commencing on the
date of the occurrence of a Rating Downgrade and ending on the first
date thereafter on which the Bank's long-term indebtedness ratings are
restored to at least A- by S&P and A3 by Moody's.
"Requirement of Law" as to any Person, means the Certificate
of Incorporation and By-Laws or other organizational or governing
documents of such Person, and any law, treaty, rule or regulation or
determination of an arbitrator or a court or other Governmental
Authority, in each case applicable to or binding upon such Person or
any of its property or to which such Person or any of its property is
subject.
"Responsible Officer" means the chief executive officer or the
president of the Company or, with respect to financial
<PAGE> 10
7
matters, the chief financial officer, the treasurer or the controller
of the Company.
"SEC Order" has the meaning set forth in Section 3.1(d).
"Security Agreement" means the Amended and Restated Security
Agreement, dated as of the date hereof, between the Bank and the
Company, in substantially the form of Exhibit A hereto, as the same
may be from time to time amended, supplemented or otherwise modified.
"Stated Amount" means, with respect to each Letter of Credit,
the remaining maximum amount available to be drawn thereunder,
determined without regard to whether any conditions to drawing could
then be met.
"Subsidiary" means, with respect to any Person, any
corporation or other entity of which securities or other ownership
interests having ordinary voting power to elect a majority of the
board of directors or other persons performing similar functions are
at the time directly or indirectly owned by such Person. Unless
otherwise specified, a reference to a Subsidiary is a reference to a
Subsidiary of the Company.
"TCO" has the meaning set forth in the Introductory Statement.
"Termination Date" shall mean the earliest of (a) the Maturity
Date, (b) the substantial consummation (as such term is defined in
Section 1101(2) of the Bankruptcy Code) of a plan of reorganization of
the Company in the Chapter 11 Case and (c) the date upon which the
Final Order shall be amended or modified (other than to correct
non-substantive errors) without the written consent of the Bank,
unless such amendment or modification is as a result of an amendment,
waiver or modification of this Agreement or the Security Agreement
approved by the Bank.
"UCC" means the Uniform Commercial Code as from time to time
in effect in the State of New York.
"Unpaid Drawing" has the meaning set forth in Section 2.2(a).
"Wholly Owned" means any Subsidiary of a Person all of the
shares of capital stock or other ownership interests of which (except
directors' qualifying shares) are at the time directly or indirectly
owned by such Person.
SECTION 1.2 ACCOUNTING TERMS AND DETERMINATIONS. Unless
otherwise specified herein, all accounting terms used herein shall be
interpreted, all accounting determinations hereunder shall be made, and all
financial statements required to be delivered hereunder shall be prepared in
accordance with generally accepted
<PAGE> 11
8
accounting principles as in effect from time to time, applied on a basis
consistent (except for changes concurred in by the Company's independent public
accountants) with the most recent audited consolidated financial statements of
the Company and its consolidated Subsidiaries delivered pursuant hereto.
The parties hereto agree, however, that in the event that any
change in accounting principles from those used in the preparation of the most
recent financial statements of the Company and its consolidated Subsidiaries
delivered to the Bank on or prior to the date hereof pursuant to the terms of
this Agreement is hereafter occasioned by the promulgation of rules,
regulations, pronouncements and opinions by or required by the Financial
Accounting Standards Board or Accounting Principles Board of the American
Institute of Certified Public Accountants (or successors thereto or agencies
with similar functions) and results in any change in the method of calculation
of financial covenants, standards or terms found in this Agreement, such
financial covenants, standards or terms (other than in respect of financial
statements to be delivered hereunder) shall be computed without giving effect
to such change in accounting principles.
SECTION 1.3 OTHER DEFINITIONAL PROVISIONS. (a) Unless
otherwise specified therein, all terms defined in this Agreement shall have the
defined meanings when used in the Security Agreement or any certificate or
other document made or delivered pursuant hereto or thereto.
(b) The words "hereof", "herein" and "hereunder" and
words of similar import when used in this Agreement shall refer to this
Agreement as a whole and not to any particular provision of this Agreement, and
Section, subsection and Exhibit references are to this Agreement unless
otherwise specified.
(c) The meanings given to terms defined herein shall be
equally applicable to both the singular and plural forms of such terms.
ARTICLE II. AMOUNT AND TERMS OF COMMITMENT
SECTION 2.1 COMMITMENT OF THE BANK. (a) From and including
the Effective Date to but excluding the Termination Date, the Bank agrees, on
the terms and conditions set forth in this Agreement, that it will from time to
time, following receipt of a Letter of Credit Request delivered in accordance
with Section 2.1(c) below, issue, for the account of the Company or the joint
and several accounts of the Company and any Subsidiary (other than TCO), and in
support of obligations of the Company or any Subsidiary (other than TCO), one
or more Letters of Credit in such form and for such purposes as are customary
for, or may otherwise be approved in the sole discretion of, the Bank;
provided, however, that no such Letter of Credit shall be so issued if:
<PAGE> 12
9
(i) at the time of such issuance, any order, judgment or
decree of any Governmental Authority or arbitrator shall purport by
its terms to enjoin or restrain the Bank from issuing such Letter of
Credit or any Requirement of Law applicable to the Bank or any request
or directive (whether or not having the force of law) from any
Governmental Authority with jurisdiction over the Bank shall prohibit,
or request that the Bank refrain from, the issuance of Letters of
Credit generally or such Letter of Credit in particular or shall
impose upon the Bank with respect to such Letter of Credit any
restriction or reserve or capital requirement (for which the Bank is
not otherwise compensated) not in effect on the date hereof, or any
unreimbursed loss, cost or expense which was not applicable or in
effect to the Bank as of the date hereof and which the Bank in good
faith deems material to it;
(ii) after giving effect to any such issuance, the Letter of
Credit Outstandings would exceed the Commitment;
(iii) in the case of a Letter of Credit to be issued in
support of obligations of a Subsidiary, at the time of such issuance,
the Company shall have failed to receive from such Subsidiary, an
agreement, in form and substance satisfactory to the Bank, pursuant to
which such Subsidiary agrees to reimburse the Borrower for the amount
of all drawings under the Letter of Credit, plus all interest and fees
in respect thereof; or
(iv) the Letter of Credit would have an expiration date
subsequent to the Maturity Date.
Each Letter of Credit Request and each Letter of Credit shall
be subject to the Uniform Customs and Practice for Documentary Credits (1993
Revision), International Chamber of Commerce Publication No. 400 and, to the
extent not inconsistent therewith, the laws of the State of New York and shall
provide for the fees set forth in Section 2.3 hereof.
(b) If on the Termination Date any Letter of Credit shall be
outstanding, then, upon request of the Bank, the Company shall use its
reasonable best efforts to immediately cause all such outstanding Letters of
Credit to be returned undrawn to the Bank.
(c) Whenever the Company wishes a Letter of Credit to be
issued, it shall give the Bank at least two Business Days' prior request
therefor. Each such request shall include the information required by Exhibit
B and such other information as the Bank shall reasonably request and shall be
either (i) in writing and executed by the Company or (ii) transmitted by the
Company to the Bank over a secure electronic data transmission system
maintained for such purpose by the Bank (such request, a "Letter of Credit
Request").
(d) The making of each Letter of Credit Request shall be
deemed to be a representation and warranty by the Company that such
<PAGE> 13
10
Letter of Credit will be issued in accordance with, and will not violate the
requirements of, Section 2.1 and that each of the applicable conditions
specified in Article III has been satisfied.
SECTION 2.2 AGREEMENT TO REPAY LETTER OF CREDIT DRAWINGS.
(a) The Company agrees to reimburse the Bank, for the account of the
applicable Fronting Bank, on each date on which the Bank notifies the Company
of the date and amount of a draft presented under any Letter of Credit and paid
by the Fronting Bank with respect thereto or otherwise paid in accordance with
the terms of the Letter of Credit Request relating thereto, for the amount of
(i) such draft so paid and (ii) any customary administrative and out-of-pocket
taxes, fees, charges or other costs or expenses incurred by the Fronting Bank
in connection with such payment (each such amount so paid until reimbursed, an
"Unpaid Drawing"). Each such payment shall be made in Dollars and in
immediately available funds to the Bank at its address for notices specified
herein; provided, however, that the Company authorizes the Bank to, and the
Bank agrees that it will, debit the Cash Collateral Account in amounts
sufficient to reimburse the Fronting Bank for any Unpaid Drawings; provided,
further, that the Bank shall not be obligated to withdraw from the Cash
Collateral Account any amount if the balance in the Cash Collateral Account
would, if such withdrawal occurred, be less than the L/C Coverage Requirement
for all outstanding Letters of Credit. Interest shall be payable to the Bank
on any and all amounts remaining unpaid by the Company under this Section 2.2
from 12:00 Noon, New York City time, on the date such amounts become payable
until the third Business Day thereafter at the Alternate Base Rate plus 1% and
thereafter until payment in full (after as well as before judgment) at a rate
per annum equal to the Alternate Base Rate plus 3%; it being understood that if
the Bank debits the Cash Collateral Account in amounts sufficient to reimburse
the Fronting Bank for any Unpaid Drawing pursuant to the immediately preceding
sentence, no interest will be paid under this Agreement with respect to such
Unpaid Drawing.
(b) The Company's obligations under this Section 2.2 to
reimburse the Bank with respect to Unpaid Drawings (including, in each case,
interest thereon) shall be absolute and unconditional under any and all
circumstances and irrespective of any set-off, counterclaim or defense to
payment which the Bank or the Company has or has had against any Fronting Bank,
the Bank or any beneficiary or transferee of any Letter of Credit, including,
without limitation, any defense based upon the failure of any drawing under a
Letter of Credit (each a "Drawing") to conform to the terms of the Letter of
Credit or any non-application or misapplication by the beneficiary of the
proceeds of such Drawing; provided, however, that the Company shall not be
obligated to reimburse the Bank for any wrongful payment made by the Fronting
Bank under a Letter of Credit as a result of acts or omissions constituting
willful misconduct or gross negligence on the part of the Fronting Bank.
<PAGE> 14
11
SECTION 2.3 COMMITMENT FEE; LETTER OF CREDIT FEE; OTHER FEES.
(a) The Borrower shall pay to the Bank (for its own account) a commitment fee
at the rate of 1/2 of 1% per annum (computed on the basis of actual days
elapsed over a year of 365 days) on the average daily unused portion of the
Commitment. The commitment fee shall accrue from and including the Effective
Date to but excluding the date on which the Commitment shall have been
terminated in its entirety pursuant to this Agreement. Such commitment fee
shall be payable in arrears quarterly on the 15th day of each March, June,
September and December, commencing on the first such date after the Effective
Date, and upon the termination of the Commitment.
(b) The Company agrees to pay to the Bank (for its own
account) a letter of credit fee (the "Letter of Credit Fee") with respect to
each Letter of Credit issued pursuant to this Agreement, for the period from
the date of issuance of such Letter of Credit until the date of termination of
such Letter of Credit, computed at the rate of 1% per annum (computed on the
basis of the actual number of days elapsed over a year of 365 days) on the
daily average Stated Amount of all Letters of Credit. The Letter of Credit Fee
with respect to all Letters of Credit shall be payable quarterly in arrears, on
the 15th day of each March, June, September and December, commencing [December
15,] 1994.
(c) The Company shall pay to the Bank (for its own account),
on the Effective Date, an amendment fee in the amount of 1/4 of 1% of the
Commitment.
(d) The Company shall pay to the Bank, for the account of the
Fronting Bank with respect to each Letter of Credit, the following fees on the
following dates, each such fee to be payable in the amount or at the rate then
generally being charged by the applicable Fronting Bank: (i) upon issuance of
each Letter of Credit, an issuance fee and a processing fee and (ii) upon each
amendment of each Letter of Credit, an amendment or reissuance fee. In
addition, with respect to each Letter of Credit issued by any Fronting Bank
other than the Bank, the Company shall pay to the Bank, for the account of the
Fronting Bank, a fronting fee with respect to such Letter of Credit, which
fronting fee shall be payable in such amounts and on such dates as shall be
agreed upon by the Company and the Fronting Bank and notified to the Bank prior
to the issuance of such Letter of Credit.
SECTION 2.4 OPTIONAL TERMINATION OR REDUCTION OF COMMITMENT.
The Borrower may, upon at least one Business Day's prior written notice to the
Bank, terminate at any time, or reduce from time to time by an aggregate amount
of $1,000,000 or any larger integral multiple thereof, the unused portion of
the Commitment; provided, however, that the Borrower shall not at any time
reduce the Commitment to an amount less than the aggregate Letter of Credit
Outstandings. If the Commitment is terminated in its entirety, all accrued
commitment fees shall be payable on the effective date of such termination.
<PAGE> 15
12
SECTION 2.5 REQUIREMENTS OF LAW. In the event that the
Bank or any Fronting Bank shall have determined that any change in any
Requirement of Law regarding capital adequacy or in the interpretation or
application thereof or compliance by the Bank or such Fronting Bank, as the
case may be, with any request or directive regarding capital adequacy (whether
or not having the force of law) from any Governmental Authority made subsequent
to the date hereof does or shall have the effect of reducing the rate of return
on the Bank's or such Fronting Bank's capital, as the case may be, as a
consequence of its obligations hereunder to a level below that which the Bank
or such Fronting Bank could have achieved but for such change or compliance
(taking into consideration such the Bank's or such Fronting Bank's policies
with respect to capital adequacy) by an amount deemed by the Bank or such
Fronting Bank, as the case may be, to be material, then from time to time,
after submission by the Bank to the Company, or such Fronting Bank to the Bank
and the Company, of a written request therefor (setting forth the basis of such
claim), the Company shall pay to the Bank, for its own account or the account
of such Fronting Bank, as the case may be, such additional amount or amounts as
will compensate the Bank or such Fronting Bank for such reduction.
SECTION 2.6 PAYMENTS. All payments to be made by the
Company hereunder, whether on account of any Unpaid Drawing, interest, fees or
otherwise, shall be made without set-off or counterclaim and shall be made
prior to 12:00 Noon, New York City time, on the due date thereof to the Bank,
at the Bank's office specified in Section 7.1, in Dollars and in immediately
available funds. If any payment hereunder becomes due and payable on a day
other than a Business Day, such payment shall be extended to the next
succeeding Business Day, and, if such payment that would have otherwise been
due and payable is an Unpaid Drawing, interest thereon shall be payable at the
then applicable rate during such extension.
SECTION 2.7 TAXES. All payments made by the Company
under this Agreement shall be made free and clear of, and without deduction or
withholding for or on account of, any present or future income, stamp or other
taxes, levies, imposts, duties, charges, fees, deductions or withholdings, now
or hereafter imposed, levied, collected, withheld or assessed by any
Governmental Authority, excluding net income taxes and franchise taxes (imposed
in lieu of net income taxes) imposed on the Bank or any Fronting Bank, as a
result of any present or former connection (excluding a connection arising
solely from the Bank or such Fronting Bank having executed, delivered,
performed its obligations or received a payment under, or enforced, this
Agreement or the other agreements or instruments required to be executed in
connection herewith) between the Bank or such Fronting Bank, as the case may
be, and the jurisdiction of the government or taxing authority imposing such
tax or any political subdivision or taxing authority thereof or therein (all
such non-excluded taxes, levies, imposts, duties, charges, fees, deductions and
withholdings being
<PAGE> 16
13
hereinafter called "Taxes"). If any Taxes are required to be withheld from any
amounts payable to the Bank or any Fronting Bank hereunder, the amounts so
payable shall be increased to the extent necessary to yield to the Bank or such
Fronting Bank, as the case may be (after payment of all Taxes), interest or any
such other amounts payable hereunder at the rates or in the amounts specified
in this Agreement. Whenever any Taxes relating to withholding are payable by
the Company in connection with any Letter of Credit issued hereunder, as
promptly as possible thereafter the Company shall send to the Bank and to the
applicable Fronting Bank (if other than the Bank) a certified copy of an
original official receipt received by the Company showing payment thereof. If
the Company fails to pay any Taxes when due to the appropriate taxing authority
or fails to remit to the Bank (for its own account or the account of the
applicable Fronting Bank, as the case may be) the required receipts or other
required documentary evidence, the Company shall indemnify the Bank and such
Fronting Bank for any incremental taxes, interest or penalties that may become
payable by the Bank or such Fronting Bank, as the case may be, as a result of
any such failure. If the Bank or a Fronting Bank shall become aware that it is
entitled to receive a refund in respect of Taxes in respect of which it has
been paid additional amounts by the Company pursuant to this Section 2.6, it
shall promptly notify the Company and the Bank of the availability of such
refund and shall, within 30 days after receipt of a request by the Company,
apply for such refund. If the Bank or a Fronting Bank receives a refund in
respect of any Taxes in respect of which it has been paid additional amounts by
the Company pursuant to this Section 2.6, it shall promptly notify the Company
and the Bank of such refund and shall, within 30 days after receipt of a
request by the Company (or promptly upon receipt, if the Company has requested
application for such refund pursuant hereto), repay such refund to the Company.
The Bank and any Fronting Bank shall use reasonable efforts to file any
certificate or document if the making of such a filing would avoid the need for
or reduce the amount of any such additional amounts which may thereafter accrue
and would not be disadvantageous to the Bank or such Fronting Bank, as the case
may be. The agreements in this Section shall survive the termination of this
Agreement and the payment of all amounts payable hereunder.
SECTION 2.8 PRIORITY AND LIENS. (a) The Company hereby
covenants, represents and warrants that pursuant to Section 364(c)(1) of the
Bankruptcy Code, the Obligations shall constitute allowed administrative
expense claims in the Chapter 11 Case having priority over any and all
administrative expenses of the kind specified in Section 503(b) or 507(b) of
the Bankruptcy Code. Notwithstanding anything to the contrary contained herein,
all of the claims referred to in this Section 2.8(a) and granted in the Chapter
11 Case to the Bank shall be subject in the event of the occurrence of a
Default or an Event of Default, (i) to allowed accrued and unpaid professional
fees and disbursements incurred by the Company and any statutory committee
appointed in the Chapter 11 Case in an amount not to exceed $7,500,000 in the
aggregate to the extent allowed by the Bankruptcy Court (exclusive of
compensation
<PAGE> 17
14
previously awarded, whether or not paid) and (ii) to fees pursuant to 28 U.S.C.
Section 1930 (collectively, the "Carve-Out").
(b) The Bank agrees that so long as no Event of Default shall
have occurred, the Company shall be permitted to pay administrative expenses of
the kind specified in Section 503(b) of the Bankruptcy Code incurred in the
ordinary course of the Company's business, and compensation and reimbursement
of expenses allowed and payable under Sections 330 and 331 of the Bankruptcy
Code, as the same may be due and payable, and checks issued therefor shall be
honored upon presentment (to the extent of available funds) and such payments
shall not be applied against the Carve-Out.
(c) The Company hereby covenants, represents and warrants
that, pursuant to Section 364(c)(2) of the Bankruptcy Code, the Obligations
shall at all times be secured by a first priority senior security interest in
and Lien upon all Collateral.
SECTION 2.9 RIGHT OF SET-OFF. Subject to the provisions of
Article VI, upon the occurrence and during the continuance of any Event of
Default, the Bank is hereby authorized at any time and from time to time, to
the fullest extent permitted by law and without further order of or application
to the Bankruptcy Court, to set off and apply any and all deposits (general or
special, time or demand, provisional or final) at any time held and other
indebtedness at any time owing by the Bank to or for the credit or the account
of the Company against any and all of the Obligations of the Company now or
hereafter existing under this Agreement and the Security Agreement,
irrespective of whether or not the Bank shall have made any demand under this
Agreement or the Security Agreement and although such Obligations may be
unmatured. The Bank agrees promptly to notify the Company after any such
set-off and application made by the Bank; provided that the failure to give
such notice shall not affect the validity of such set-off and application. The
rights of the Bank under this Section are in addition to other rights and
remedies which the Bank may have upon the occurrence and during the continuance
of any Event of Default.
SECTION 2.10 RATING DOWNGRADE; ALTERNATIVE FRONTING BANKS.
(a) During the continuation of any Rating Downgrade Period, the Borrower may
elect to designate a financial institution other than the Bank (which
institution shall be reasonably acceptable to the Bank) to act as Fronting Bank
with respect to any Letter of Credit requested to be issued during such Rating
Downgrade Period. If the Company so elects to designate an alternative
Fronting Bank with respect to any Letter of Credit, in lieu of the Letter of
Credit Request otherwise required pursuant to Section 2.1, the Company shall,
at least two Business Days prior to the issuance of such Letter of Credit,
deliver to the Bank the following: (i) the identity of such other Fronting
Bank, (ii) a copy of the letter of credit request submitted to such other
Fronting Bank, (iii) evidence satisfactory to the Bank that the conditions set
forth in Section 2.1(a)(ii), (iii) and (iv) have
<PAGE> 18
15
been satisfied with respect to the issuance of such Letter of Credit by such
Fronting Bank and (iv) an executed agreement of such Fronting Bank indicating
that such Fronting Bank has agreed to become bound by the terms of this
Agreement with respect to such Letter of Credit. Delivery of such documents to
the Bank shall be deemed to constitute a representation and warranty by the
Company that the conditions set forth in Sections 2.1(a)(ii), (iii) and (iv)
and Article III have been satisfied with respect to such Letter of Credit.
(b) If on the Termination Date any Letter of Credit issued by
a Fronting Bank other than the Bank shall be outstanding, then, upon request by
the Bank or such Fronting Bank, the Company shall use its reasonable best
efforts to immediately cause all such outstanding Letters of Credit to be
returned undrawn to such Fronting Bank. Such Fronting Bank shall promptly
notify the Bank upon receipt of any such returned Letter of Credit.
(c) Immediately upon the issuance by any Fronting Bank other
than the Bank of any Letter of Credit, such Fronting Bank shall be deemed to
have sold and transferred to the Bank, and the Bank shall be deemed irrevocably
and unconditionally to have purchased and received from such Fronting Bank,
without recourse or warranty, a participation in such Letter of Credit equal to
100% of such Fronting Bank's interest in such Letter of Credit, each drawing
made thereunder and the obligations of the Borrower under this Agreement with
respect thereto, and any security therefor.
(d) In the event that any Drawing is made under any Letter of
Credit issued by a Fronting Bank other than the Bank, upon notice by such
Fronting Bank to the Bank of such Drawing and of the amount of the Unpaid
Drawing with respect thereto, the Bank shall promptly and unconditionally pay
to the Fronting Bank the amount of such Unpaid Drawing in Dollars and in
immediately available funds. If the Fronting Bank so notifies the Bank prior
to 11:00 A.M, New York City time, on any Business Day, the Bank shall make
available to such Fronting Bank the amount of such payment on such Business
Day. If and to the extent the Bank shall not make such amount available to the
Fronting Bank on a timely basis, the Bank agrees to pay to the Fronting Bank
forthwith on demand, such amount (together with interest thereon for each day
from such date until the date such amount is paid to the Fronting Bank at the
Federal Funds Effective Rate). The Bank shall also pay to the Fronting Bank,
prior to 3:00 P.M. on the date when such amounts are due from the Company, all
amounts payable by the Company to such Fronting Bank pursuant to Section
2.3(d). The Bank shall also pay to the Fronting Bank, within one Business Day
of receipt thereof from the Company, all other amounts received from the
Company for the account of such Fronting Bank pursuant to the terms hereof.
(e) Upon the request of the Bank, each Fronting Bank shall
furnish to the Bank copies of any Letter of Credit to which
<PAGE> 19
16
such Fronting Bank is party and such other documentation as may reasonably be
requested by the Bank.
(f) The obligations of the Bank to make payments to each
Fronting Bank with respect to Letters of Credit issued by such Fronting Bank
shall be irrevocable and not subject to any qualification or exception
whatsoever and shall be made in accordance with the terms and conditions of
this Agreement under all circumstances, including, without limitation, any of
the following circumstances:
(i) any lack of validity or enforceability of this
Agreement;
(ii) the existence of any claim, set-off, defense or
other right which the Company may have at any time against a
beneficiary named in a Letter of Credit, any transferee of any Letter
of Credit (or any Person for whom any such transferee may be acting),
the Fronting Bank or any other Person, whether in connection with this
Agreement, any Letter of Credit, the transactions contemplated herein
or any unrelated transactions (including any underlying transaction
between the Company and the beneficiary named in any such Letter of
Credit);
(iii) any draft, certificate or any other document
presented under the Letter of Credit proving to be forged, fraudulent,
invalid or insufficient in any respect or any statement therein being
untrue or inaccurate in any respect;
(iv) the surrender or impairment of any security for
the performance or observance of any of the terms of this Agreement or
the Final Order; or
(v) the occurrence of any Default or Event of Default.
(g) Each Fronting Bank hereby irrevocably designates and
appoints the Bank as its agent to receive payments on its behalf pursuant to
Section 2.2 or 2.3 and to take action with respect to the Collateral and any
other collateral security existing from time to time securing payment of the
Obligations, and to exercise such powers and perform such duties as are
reasonably incidental thereto. The Bank reserves the right, in its sole
discretion in each instance, to exercise or refrain from exercising any rights
or remedies which the Bank may have under the Security Agreement, including,
without limitation, the right to foreclose and sell and otherwise deal with, or
refrain from foreclosing and selling or otherwise dealing with any Collateral
or any other collateral security existing from time to time securing payment of
the Obligations or to enforce, or refrain from enforcing, the Security
Agreement, and no Fronting Bank shall be entitled to exercise any rights
thereunder. The Security Agreement and all Collateral shall be held by the
Bank in its name, but to the extent of any Fronting Bank's interest in the
Letters of Credit in accordance with this Agreement, the Bank agrees that the
Collateral and the Security
<PAGE> 20
17
Agreement shall be held by the Bank as agent for such Fronting Bank.
(h) The Bank shall not have any duties or responsibilities to
any Fronting Bank, except those expressly set forth in this Section 2.10, or
any fiduciary relationship with any Fronting Bank, and no implied covenants,
functions, responsibilities, duties, obligations or liabilities shall be read
into this Agreement or the Security Agreement. Neither the Bank nor any of its
officers, directors, employees, agents, attorneys-in-fact or affiliates shall
be liable for any action lawfully taken or omitted to be taken by it or such
person under or in connection with this Agreement, the Security Agreement or
any document delivered pursuant hereto or thereto, except that it or such
person shall be liable for its or such person's own gross negligence or willful
misconduct.
(i) Each Fronting Bank severally agrees to indemnify the Bank
against all liabilities, obligations, losses, damages, penalties, actions,
judgments, suits, costs, expenses or disbursements of any kind whatsoever which
may at any time be imposed on, incurred by or asserted against the Bank
relating to the gross negligence or willful misconduct, or alleged gross
negligence or willful misconduct, of such Fronting Bank.
ARTICLE III. CONDITIONS PRECEDENT
SECTION 3.1 CONDITIONS PRECEDENT TO EFFECTIVENESS OF
AGREEMENT. This Agreement shall become effective on the date (the "Effective
Date") on which all of the following conditions are satisfied, whether or not
the Company requests the issuance of a Letter of Credit on such date:
(a) receipt by the Bank of an opinion of Daniel L. Bell, Jr.,
Chief Legal Officer of the Company, in form and substance satisfactory
to the Bank (which opinion may be given in reliance on opinions
delivered by local counsel or special counsel or the provisions of the
Final Order);
(b) receipt by the Bank of evidence satisfactory to it that
all conditions precedent to the issuance of a Letter of Credit have
been met, including, without limitation, a certificate signed by the
chairman or president or any vice president and by the chief financial
officer or treasurer or controller of the Company, to the effect set
forth in clauses (c), (d), (e), (f) and (h) of Section 3.2;
(c) receipt by the Bank of (i) a certified copy of the Final
Order which shall have been entered by the Bankruptcy Court on such
notice and with such terms as may be satisfactory to the Bank and the
Company and which shall not have been reversed, modified, amended,
vacated or stayed and (ii) evidence, satisfactory to the Bank, that
the Company has filed with the Securities and Exchange Commission
("SEC") a
<PAGE> 21
18
declaration, in form and substance satisfactory to the Bank, pursuant
to Section 7(b) of PUHCA, and that the SEC has issued an order, in
form and substance satisfactory to the Bank (the "SEC Order") in
response to such declaration approving this transaction;
(d) the Bank shall be satisfied that, in its judgment, there
is no (i) injunction, stay, decree or order issued by any court or
arbitrator or any governmental body, agency or official or (ii)
action, suit or proceeding pending or threatened against or affecting
the Company before any court or arbitrator or any governmental body,
agency or official in which there is a reasonable possibility of an
adverse decision, in either case, which could reasonably be expected
to have a Material Adverse Effect or which in any manner draws into
question the validity of this Agreement, the Security Agreement, the
Final Order or the SEC Order;
(e) receipt by the Bank of an amount equal to the L/C
Coverage Requirement for all Letters of Credit issued by the Bank
under the Original Agreement and outstanding on such date deposited in
the Cash Collateral Account in accordance with the Security Agreement;
(f) receipt by the Bank of all documents it may reasonably
request, including, but not limited to, Certificates of Incorporation
and good standing certificates and board resolutions, relating to the
existence of the Company and its Subsidiaries (other than TCO), the
corporate authority for and validity hereof, and any other matters
relevant hereto, all in form and substance reasonably satisfactory to
the Bank;
(g) all actions necessary or advisable in order to establish,
protect and perfect the interest of the Bank in the Collateral
pursuant to the Security Agreement which the Bank has requested the
Company to make or take as a condition to the initial extension of
credit hereunder shall have been made or taken (it being understood
that the failure to request a particular action shall be without
prejudice to the rights of the Bank set forth in Section 5.8);
(h) receipt by the Bank of all fees owed hereunder or under
the Original Agreement including, without limitation, all fees payable
pursuant to Section 2.3;
(i) receipt by the Bank from each bank (other than the Bank)
party to the Original Agreement of a letter, in form and substance
satisfactory to the Bank, evidencing that such bank (A) consents to
the termination of its commitment under the Original Agreement, (B)
acknowledges receipt of payment in full of all principal of and
interest on all loans outstanding under the Original Agreement, all
interest, fees and other amounts payable to it in respect of all
letters of credit
<PAGE> 22
19
issued thereunder and all other amounts payable to such bank under the
Original Agreement (including all fees and other amounts payable as a
result of the termination of its Commitment under the Original
Agreement) and (C) in the case of any fronting bank (other than the
Bank) under the Original Agreement, lists the letters of credit, if
any, issued by such fronting bank and remaining outstanding, which
letters the Company shall cause to be returned to such fronting bank
for cancellation on or promptly after the Effective Date; and
(j) each of this Agreement and the Security Agreement shall
have been duly executed and delivered to the Bank by each party
thereto and shall be in form and substance satisfactory to the Bank.
SECTION 3.2 CONDITIONS PRECEDENT TO EACH LETTER OF CREDIT.
Each issuance of a Letter of Credit by the Bank shall be subject to the
satisfaction of the following conditions precedent:
(a) receipt by the Bank of a Letter of Credit Request as
required by Section 2.1;
(b) receipt by the Bank of an amount equal to the L/C
Coverage Requirement for such Letter of Credit deposited in the Cash
Collateral Account in accordance with the Security Agreement;
(c) immediately after such issuance of such Letter of Credit,
no Default or Event of Default shall have occurred and be continuing;
(d) the representations and warranties of the Company
contained in this Agreement and the Security Agreement, or otherwise
made in writing in connection herewith and therewith, shall be true
and correct in all material respects on and as of the date of such
issuance of such Letter of Credit with the same effect as if made on
and as of such date (unless stated to relate to a specific earlier
date, in which case such representations and warranties shall be true
and correct as of such earlier date);
(e) each of the Final Order and the SEC Order shall be in
full force and effect and shall not have been modified or amended in
any respect (other than to correct non-substantive errors) without the
written consent of the Bank, unless such amendment or modification is
as a result of an amendment, waiver or modification of this Agreement
or the Security Agreement approved by the Bank, and neither the Final
Order or the SEC Order shall be subject to appeal or shall have been
reversed or vacated;
(f) immediately after giving effect to such issuance of such
Letter of Credit, the Letter of Credit Outstandings shall not exceed
the Commitment;
<PAGE> 23
20
(g) all corporate and judicial proceedings and all
instruments and agreements in connection with the transactions
contemplated by this Agreement shall be satisfactory in form and
substance to the Bank, and the Bank shall have received all
information and copies of all documents and papers, including records
of corporate and judicial proceedings, which the Bank may have
reasonably requested in connection therewith, such documents and
papers where appropriate to be certified by proper corporate,
governmental or judicial authorities; and
(h) all fees payable pursuant hereto on or before the date of
such issuance of such Letter of Credit shall have been paid in full.
Each Letter of Credit Request hereunder shall be deemed to be a representation
and warranty by the Company on the date of such Letter of Credit Request as to
the facts specified in clauses (c), (d), (e), (f) and (h) of this Section 3.2.
ARTICLE IV. REPRESENTATIONS AND WARRANTIES
In order to induce the Bank to enter into this Agreement and
to issue Letters of Credit hereunder, the Company represents and warrants to
the Bank as follows:
SECTION 4.1 ORGANIZATION AND AUTHORITY. Each of the Company
and each of its Subsidiaries (other than TCO) (a) is a corporation duly
organized and validly existing under the laws of the state of its incorporation
and is duly qualified as a foreign corporation and is in good standing in each
jurisdiction in which the failure to so qualify would have a Material Adverse
Effect, (b) has the requisite corporate power and authority to effect the
transactions contemplated hereby and by the Security Agreement and (c) has all
requisite corporate power and authority and the legal right to own, pledge,
mortgage and operate its properties as contemplated hereunder and under the
Security Agreement, and to conduct its business as now or currently proposed to
be conducted.
SECTION 4.2 DUE EXECUTION. The execution, delivery and
performance by the Company of each of this Agreement and the Security Agreement
are within the corporate powers of the Company, have been duly authorized by
all necessary corporate action, including the consent of shareholders where
required, and do not (a) contravene the charter or by-laws of the Company, (b)
violate any law (including, without limitation, the Securities Exchange Act of
1934 or PUHCA) or regulation (including, without limitation, Regulations G, T,
U or X of the Board), or any order or decree of any court or governmental
instrumentality, (c) conflict with or result in a breach of or constitute a
default under, any material indenture, mortgage or deed of trust entered into
after the Filing Date or any material lease, agreement or other instrument
entered into after the Filing Date binding on the Company, any of its
<PAGE> 24
21
Subsidiaries or any of their respective properties, (d) result in or require
the creation or imposition of any Lien other than the Liens granted pursuant to
this Agreement and the Security Agreement or (e) require the consent,
authorization by or approval of or notice to or filing or registration with any
governmental body, agency, authority, or regulatory body other than the entry
of the Final Order and the SEC Order. This Agreement has been duly executed
and delivered by the Company. This Agreement is, and the Security Agreement,
when executed and delivered will be, a legal, valid and binding obligation of
the Company, enforceable against the Company in accordance with its terms.
SECTION 4.3 EFFECTIVENESS OF ORDER. The Final Order is in
full force and effect.
SECTION 4.4 INFORMATION. (a) The consolidated balance sheet
of the Company and its consolidated Subsidiaries as of December 31, 1993 and
the related consolidated statements of income, changes in shareholders' equity
and cash flows for the fiscal year then ended, reported on by Arthur Andersen &
Co. and set forth in the Company's 1993 Form 10-K, a copy of which has been
delivered to the Bank, fairly present, in conformity with generally accepted
accounting principles, the consolidated financial position of the Company and
its consolidated Subsidiaries and the financial position of the Company as of
such date and their respective results of operations and cash flows for such
fiscal year.
(b) The unaudited consolidated balance sheet of the Company
and its consolidated Subsidiaries as of June 30, 1994 and the related unaudited
consolidated statements of income, changes in shareholders' equity and cash
flows for the six months then ended, set forth in the Company's quarterly
report for the fiscal quarter ended June 30, 1994, copies of which have been
delivered to the Bank, fairly present, in conformity with generally accepted
accounting principles applied on a basis consistent with the financial
statements referred to in paragraph (a) of this Section, the consolidated
financial position of the Company and its consolidated Subsidiaries as of such
date and their consolidated results of operations and cash flows for such
six-month period (subject to normal year-end adjustments).
(c) Other than as disclosed to the Bank in writing prior to
the date hereof, since December 31, 1993 there has been no material adverse
change in the business, financial position, results of operations or prospects
of the Company and its Subsidiaries (other than TCO) taken as a whole.
(d) Neither this Agreement, the Security Agreement, the
Original Agreement nor any agreement, document, certificate or statement
furnished to the Bank by or on behalf of the Company in connection with the
transactions contemplated hereby or thereby or filed in the Bankruptcy Court by
or on behalf of the Company in connection with the Chapter 11 Case, at the time
it was furnished or filed, contained any untrue statement of a material fact or
<PAGE> 25
22
omitted to state any fact necessary in order to make the statements therein, in
light of the circumstances under which they were made, not misleading; the
projections contained therein were prepared in good faith and represented at
the time they were furnished, the Company's best estimate of the information
purported to be shown therein, and the Company is not aware of any information
that would lead it to believe that such projections or other information are
misleading in any material respect.
SECTION 4.5 LITIGATION. Other the Chapter 11 Case or as
otherwise disclosed to the Bank in writing prior to the date hereof, there is
no (a) injunction, stay, decree or order issued by any court or arbitrator or
any governmental body, agency or official or (b) action, suit or proceeding
pending against, or to the knowledge of the Company threatened against or
affecting, the Company or any of its Subsidiaries (other than TCO) before any
court or arbitrator or any governmental body, agency or official which could
reasonably be expected to have a Material Adverse Effect.
SECTION 4.6 SECURITY INTEREST. The Final Order and the
Security Agreement will create and grant to the Bank a valid, first priority
perfected and enforceable security interest in and lien upon the Collateral,
securing the Obligations, superior in right to any other Liens, existing or
future, which the Company or any creditors thereof or any other Person, may
have against such Collateral or interests therein, other than Permitted Liens.
SECTION 4.7 NOT AN INVESTMENT COMPANY. The Company is not an
"investment company" within the meaning of the Investment Company Act of 1940,
as amended.
SECTION 4.8 NO CONFLICTING REQUIREMENTS. Neither the Company
nor any Subsidiary is in violation or in default under any term or provision of
any charter, by-law, statute, rule, regulation, judgment, decree, order, writ
or injunction applicable to it, such that such violations or defaults in the
aggregate could reasonably be expected to have a Material Adverse Effect.
Neither the Company nor any of its Subsidiaries (other than TCO) is a party to
any agreement or instrument or subject to any legislative or charter or other
corporate restriction or any judgment, order, writ, injunction, decree, rule or
regulation materially and adversely affecting the business, operations,
properties or assets or the financial condition of the Company or its
Subsidiaries (other than TCO), taken as a whole.
SECTION 4.9 NO DEFENSES. The Company is truly and justly
indebted to the Bank for the Obligations, and does not currently have, and
agrees that it will not at any time hereafter assert, any defense, offset or
counterclaim with respect to the reimbursement of amounts drawn under Letters
of Credit, except as such defense offset or counterclaim relates to the gross
negligence or willful misconduct of the Bank.
<PAGE> 26
23
ARTICLE V. COVENANTS
The Company agrees that during the period commencing on the
Effective Date and ending on the later of the Termination Date and the date on
which all amounts owing in respect of all Letters of Credit or otherwise
arising hereunder or under the Security Agreement are paid:
SECTION 5.1 INFORMATION. The Company will deliver to the
Bank:
(a) as soon as available, and in any event within 90 days
after the end of each fiscal year of the Company, the consolidated
balance sheet of the Company and its consolidated Subsidiaries as of
the end of such fiscal year and the related consolidated statements of
earnings, changes in consolidated shareholders' equity and cash flows
for such fiscal year, setting forth in each case in comparative form
the figures for the previous fiscal year, all reported on in a manner
acceptable to the Securities and Exchange Commission by Arthur
Andersen & Co or other independent public accountants of recognized
standing;
(b) as soon as available, and in any event within 50 days
after the end of each of the first three quarters of each fiscal year
of the Company, consolidated balance sheets of the Company and its
consolidated Subsidiaries as of the end of such quarter and the
related consolidated statements of earnings, changes in consolidated
shareholders' equity and consolidated cash flows for such quarter and
for the portion of the Company's fiscal year ended at the end of such
quarter, setting forth in comparative form the figures for the
corresponding quarter and the corresponding portion of the Company's
previous fiscal year;
(c) simultaneously with the delivery of each set of financial
statements referred to in clauses (a) and (b) above, a certificate of
the chief financial officer or the chief accounting officer of the
Company stating (i) that the Company is responsible for the
preparation and fair presentation of each balance sheet and the
related statements of earnings, changes in shareholders' equity and
cash flows of the Company in conformance with generally accepted
accounting principles, (ii) that such officer has no reason to believe
that such balance sheets and statements have not been prepared in
conformance with generally accepted accounting principles and (iii)
whether any Default or Event of Default exists on the date of such
certificate and, if any Default or Event of Default then exists,
setting forth the details thereof and the action which the Company is
taking or proposes to take with respect thereto;
(d) as soon as available, copies of all final annual budgets
and business plans, forecasts and other similar
<PAGE> 27
24
materials prepared by or for the Company and its consolidated
Subsidiaries (other than TCO);
(e) within five Business Days of any Responsible Officer of
the Company obtaining knowledge of any Default or Event of Default, if
such Default or Event of Default is then continuing, a certificate of
a Responsible Officer of the Company setting forth the details thereof
and the action which the Company is taking or proposes to take with
respect thereto; and
(f) from time to time such additional information regarding
the financial position or business of the Company or any Subsidiary as
the Bank may reasonably request.
SECTION 5.2 MAINTENANCE OF PROPERTY; INSURANCE. The Company
will keep, and will cause each Subsidiary (other than TCO) to keep, all
material property useful and necessary in its business in good working order
and condition, ordinary wear and tear excepted; will maintain, and will cause
each such Subsidiary to maintain (either in the name of the Company or in such
Subsidiary's own name), either with financially sound and reputable insurance
companies or pursuant to a plan of self-insurance established in accordance
with sound and appropriate practices, insurance on all their property in at
least such amounts and against at least such risks as are usually insured
against in the same general area by companies of established repute engaged in
the same or a similar business; and will furnish to the Bank, upon written
request, full information as to the insurance carried.
SECTION 5.3 COMPLIANCE WITH LAWS. (a) The Company will
comply, and cause each Subsidiary (other than TCO) to comply, in all material
respects with all applicable laws, ordinances, rules, regulations, and
requirements of Governmental Authorities (including, without limitation, ERISA
and the rules and regulations thereunder), except where (i) the failure to so
comply would not have a Material Adverse Effect or (ii) the necessity of
compliance therewith is contested in good faith by appropriate proceedings.
(b) The Company will comply with all court orders in the
Chapter 11 Case.
SECTION 5.4 INSPECTION OF PROPERTY; BOOKS AND RECORDS. The
Company will keep, and will cause each Subsidiary (other than TCO) to keep,
proper books of record and account in which full, true and correct entries in
conformity with generally accepted accounting principles shall be made of all
dealings and transactions in relation to its business and activities; and will
permit, and cause each Subsidiary (other than TCO) to permit, representatives
of the Bank to visit and inspect any of their respective properties, to examine
and make abstracts from any of their respective books and records and to
discuss their respective affairs, finances and accounts with their respective
officers, appropriate employees, independent public accountants, consultants
<PAGE> 28
25
and financial advisors all at such reasonable times, upon reasonable notice and
as often as may reasonably be desired.
SECTION 5.5 CHAPTER 11 CASE. The Company will furnish
monthly to the Bank's counsel an index of all pleadings, motions, applications,
judicial information, financial information and other documents filed (and not
under seal) with the Bankruptcy Court by the Company or any other Person or
(except for such materials as the Company and the official committee receiving
the same shall determine in good faith are inappropriate for review by the
Bank) distributed by the Company to any official committee appointed in the
Chapter 11 Case. The Company will provide to the Bank's counsel copies of any
documents described in such index promptly upon request by the Bank or the
Bank's counsel.
SECTION 5.6 CORPORATE EXISTENCE; NO CHANGE IN BUSINESS. The
Company shall continue to, and shall cause each of its Subsidiaries (other than
TCO) to, do or cause to be done all things necessary to preserve, renew and
keep in full force and effect its corporate existence, material rights,
licenses, permits and franchises and comply in all material respects with all
laws and regulations applicable to it. Neither the Company nor any Subsidiary
(other than TCO) will engage in any business which is not directly related to
its business as conducted on the date hereof.
SECTION 5.7 FURTHER ASSURANCES; SECURITY INTERESTS. (a)
Upon the request of the Bank, the Company shall duly execute and deliver, or
cause to be duly executed and delivered, at the cost and expense of the
Company, such further instruments as may be necessary or proper, in the
reasonable judgment of the Bank, to provide the Bank a perfected Lien in the
Collateral and to carry out the provisions and purposes of this Agreement and
the Security Agreement.
(b) Upon the reasonable request of the Bank, the Company
shall promptly perform or cause to be performed any and all acts and execute or
cause to be executed any and all mortgages and other documents (including,
without limitation, the execution, amendment or supplementation of any
financing statement and continuation statement or other statement) for filing
under the provisions of the UCC and the rules and regulations thereunder, or
any other statute, rule or regulation of any applicable foreign, federal, state
or local jurisdiction, which are desirable, from time to time, in order to
grant and maintain in favor of the Bank the security interest in the Collateral
contemplated hereby and by the Security Agreement, subject to no other Liens
except as may be expressly permitted hereunder and under the Security
Agreement.
(c) The Company shall promptly undertake to deliver or cause
to be delivered to the Bank from time to time such other documentation,
consents, authorizations, approvals and orders in form and substance
satisfactory to the Bank, as the Bank shall deem
<PAGE> 29
26
reasonably advisable to perfect or maintain the Lien of the Bank in the
Collateral.
SECTION 5.8 CHAPTER 11 CLAIMS AND LIENS. The Company will
not incur, create, assume, suffer or permit to exist or permit any Subsidiary
to incur, create, assume, suffer or permit to exist any claim against the
Company or any Subsidiary in the Chapter 11 Case which would be pari passu with
or senior to the claims of the Bank against the Company nor any Lien which
would be pari passu with or senior to the Liens of the Bank, nor will the
Company apply to the Bankruptcy Court for authority to do so.
ARTICLE VI. EVENTS OF DEFAULTS
If one or more of the following events (each, an "Event of
Default") shall have occurred and be continuing:
(a) the Company shall fail to pay when due (i) any amount
specified in Section 2.2 or (ii) any other amount required to be paid
by the Company hereunder and any such failure shall remain unremedied
for three Business Days; or
(b) the Company shall fail to observe or perform its
covenants contained in Section 5.1(e) or Section 5.8; or
(c) the Company or any Subsidiary shall fail to observe or
perform any covenant or agreement contained in this Agreement or in
the Security Agreement (other than those covered by clauses (a) or (b)
above) for 20 days after the Company has knowledge of such failure; or
(d) any representation, warranty, certification or statement
made by the Company or any Subsidiary in this Agreement or the
Security Agreement or in any certificate, financial statement or other
document delivered pursuant hereto or thereto shall prove to have been
incorrect in any material respect when made (or deemed made); or
(e) this Agreement or the Security Agreement shall cease to
be in full force and effect and valid, or any security interest or
Lien purported to be created hereby thereby shall cease to be valid
and perfected or the Company or any Subsidiary shall so have asserted;
or
(f) the Final Order shall be vacated or reversed or shall be
modified, supplemented or amended in any respect (except as provided
in Section 3.2(e)) or the Company shall apply to the Bankruptcy Court
for authority to do so; or
(g) the Bankruptcy Court shall enter an order (i) dismissing
the Chapter 11 Case, (ii) converting the Chapter 11 Case to a case
under Chapter 7 of the Bankruptcy Code, (iii) appointing a trustee in
the Chapter 11 Case or (iv) appointing an examiner with enlarged
powers (powers beyond those set
<PAGE> 30
27
forth in Sections 1106(a)(3) and (4) of the Bankruptcy Code) under
Section 1106(b) of the Bankruptcy Code; provided, however, that
appointment of an examiner with enlarged powers based upon a finding
of fraud or dishonesty by the Company's management, incompetence of
the Company's management or mismanagement or irregularities in the
management of the Company's affairs shall not be an Event of Default;
or an application shall be filed for the approval of, or there shall
exist any Lien on the Collateral (other than those of the Bank
hereunder or under the Security Agreement or as otherwise expressly
permitted hereby) in the Chapter 11 Case having a priority (whether
under Section 364 of the Bankruptcy Code or otherwise) superior to or
pari passu with that of the Bank; or an application shall be filed for
the approval of, or there shall arise, any claim in the Chapter 11
Case having a priority (whether under Section 364 of the Bankruptcy
Code or otherwise) pari passu with or superior to that of the Bank; or
the Company shall pay, or apply to the Bankruptcy Court for authority
to pay, any Pre-Petition claim except as expressly contemplated by
this Agreement or otherwise approved in writing by the Bank; or the
Bankruptcy Court shall enter an order approving a disclosure statement
in connection with a plan of reorganization proposed by the Company,
any Subsidiary or any third party, which plan does not provide for
payment in full in cash of the Obligations on the Termination Date; or
(h) any judgments or orders as to a Post-Petition liability
or debt for the payment of money in excess of $10,000,000 in the
aggregate shall be rendered against the Company and either (i)
enforcement proceedings shall have been commenced and be continuing by
any creditor upon such judgment or order or (ii) there shall be any
period of 15 consecutive days during which a stay of enforcement of
such judgment or order, by reason of a pending appeal or otherwise,
shall not be in effect; or
(i) any non-monetary judgment or order with respect to a
Post-Petition event shall be rendered against the Company which does
or could reasonably be expected to (i) have a Material Adverse Effect
or (ii) cause a material decrease in the value of the Collateral, and
in each case there shall be any period of 10 consecutive days during
which a stay of enforcement of such judgement or order by reason of a
pending appeal or otherwise, shall not be in effect; or
(j) the Bankruptcy Court shall enter an order granting relief
from the automatic stay applicable under Section 362 of the Bankruptcy
Code to a party to any Pre-Petition action, suit or proceeding against
the Company, which action, suit or proceeding (x) could reasonably be
expected to materially adversely affect the business, consolidated
financial position or consolidated results of operations of the
Company and its consolidated Subsidiaries or (y) draws into question
the validity of this Agreement or the Security Agreement or could
<PAGE> 31
28
materially adversely affect the ability of the Company to perform any
of its obligations hereunder or thereunder;
then, and in every such event and at any time thereafter during the continuance
of such event, without further order of or application to the Bankruptcy Court,
the Bank may take any or all of the following actions, at the same or different
times: (i) by notice to the Borrower, terminate the Commitment and it shall
thereupon terminate, (ii) set-off amounts in the Company's accounts deposited
with the Bank or otherwise take steps to foreclose upon Collateral (as set
forth in the Security Agreement) and/or (iii) upon seven (7) days' prior notice
to the Company and the official committees in the Chapter 11 Case and the
Bankruptcy Court, exercise such remedies as are provided for elsewhere in this
Agreement or as may otherwise be available to it under applicable law or in
equity. Upon the occurrence of any Event of Default described in this Article
VI which shall be continuing, the Bank may, in its sole discretion, but shall
not be obligated to, by notice of default to the Company, declare all amounts
owing or contingently owing hereunder to be forthwith due and payable, and the
same shall thereupon become due and payable without demand, presentment,
protest or further notice of any kind, all of which are hereby expressly waived
by the Company.
ARTICLE VII. MISCELLANEOUS
SECTION 7.1 NOTICES. All notices, requests and other
communications to any party hereunder shall be in writing (including bank wire
or telecopy or similar writing) and shall be given to such party: (a) in the
case of the Company or the Bank, at its address or telecopy number set forth on
the signature pages hereof or (b) in the case of the official committees in the
Chapter 11 Case or any party, at such other address or telecopy number as such
party may hereafter specify for such purpose by notice to the Bank and the
Company. Each such notice, request or other communication shall be effective
(i) if given by telecopy, when such telecopy is transmitted to the telecopy
number specified in this Section and such telecopy is electronically or
telephonically confirmed, (ii) if given by mail, 96 hours after such
communication is deposited in the mails with first class postage prepaid,
addressed as aforesaid or (iii) if given by any other means, when delivered at
the address specified in this Section; provided that notices to the Bank under
Article II shall not be effective until received.
SECTION 7.2 NO WAIVERS. No failure or delay by the Bank in
exercising any right, power or privilege hereunder shall operate as a waiver
thereof nor shall any single or partial exercise thereof preclude any other or
further exercise thereof or the exercise of any other right, power or
privilege. The rights and remedies herein provided shall be cumulative and not
exclusive of any rights or remedies provided by law.
<PAGE> 32
29
SECTION 7.3 EXPENSES; DOCUMENTARY TAXES; INDEMNIFICATION.
(a) The Company shall pay (i) all reasonable out-of-pocket expenses of the
Bank, including reasonable fees and disbursements of counsel for the Bank in
connection with the negotiation, preparation and administration of this
Agreement and the Security Agreement (including, without limitation, the
recording or filing of any security document and the reasonable out-of-pocket
fees and expenses and allocable internal costs incurred by the Bank in
connection with its audit or review of the Collateral) and any other document
contemplated hereby or thereby, any waiver or consent hereunder or thereunder
or any amendment hereof or thereof or any Default or alleged Default hereunder
or thereunder and (ii) if an Event of Default occurs, all out-of-pocket
expenses incurred by the Bank, including fees and disbursements of counsel, in
connection with such Event of Default and collection and other enforcement
proceedings resulting therefrom. The Company shall indemnify the Bank against
any transfer taxes, filing charges or taxes, documentary taxes, assessments or
charges made by any Governmental Authority by reason of the execution or
delivery of this Agreement, the Security Agreement or any related documents or
the recording or filing of any security document.
(b) The Company agrees to indemnify the Bank and hold the
Bank harmless from and against any and all liabilities, losses, damages, costs
and expenses of any kind (including, without limitation, the reasonable fees
and disbursements of counsel for the Bank) in connection with any claim
asserted against the Bank or investigative, administrative or judicial
proceeding, whether or not the Bank shall be designated a party thereto, which
may be incurred by the Bank relating to or arising out of this Agreement or the
transactions contemplated hereby or in connection with any press release issued
by the Company, or any document filed by the Company with the Securities and
Exchange Commission; provided that the Bank shall not have the right to be
indemnified hereunder for its own gross negligence or willful misconduct as
determined by a court of competent jurisdiction.
SECTION 7.4 AMENDMENTS AND WAIVERS. Any provision of this
Agreement may be amended or waived if, but only if, such amendment or waiver is
in writing and is signed by the Company and the Bank and, if the rights and
duties of any Fronting Bank are adversely affected thereby in any material
respect, by such Fronting Bank.
SECTION 7.5 NEW YORK LAW. THIS AGREEMENT SHALL BE CONSTRUED
IN ACCORDANCE WITH, AND BE GOVERNED BY, THE INTERNAL LAWS OF THE STATE OF NEW
YORK, WITHOUT REGARD TO CONFLICT OF LAWS PRINCIPLES, EXCEPT TO THE EXTENT
PREEMPTED BY FEDERAL LAW.
SECTION 7.6 COUNTERPARTS. This Agreement may be signed in
any number of counterparts (including telecopy counterparts), each of which
shall be an original, with the same effect as if the signature thereto and
hereto were upon the same instrument.
<PAGE> 33
30
SECTION 7.7 WAIVER OF TRIAL BY JURY. THE PARTIES TO THIS
AGREEMENT WAIVE ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING
ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED
THEREBY.
SECTION 7.8 EFFECTIVENESS. This Agreement shall become
effective on the Effective Date, on which date the Original Agreement shall be
amended and restated in its entirety as set forth herein. Effective on the
Effective Date, the Letter of Credit Fees with respect to Letters of Credit
issued by the Bank under the Original Agreement shall be payable at the rate
provided in this Agreement.
SECTION 7.9 CONFIDENTIALITY. The Bank agrees to keep
confidential (and to cause its officers, directors, employees, agents and
representatives to keep confidential) all materials, documents and information
which the Company may furnish to it pursuant hereto or in connection with the
transaction contemplated hereby (collectively, the "Information"), except that
the Bank shall be permitted to disclose Information (a) to its officers,
directors, employees, agents, counsel, advisors and representatives, (b) to the
extent (i) required by any subpoena or similar legal process or compelled by
any court acting in law or in equity or (ii) required by applicable laws or
regulations or requested by any bank regulatory authority, (c) to the extent
such Information (i) becomes publicly available other than as a result of the
Bank's breach of this Agreement, (ii) becomes available to it on a
non-confidential basis from a source other than the Company or (iii) was
available to it on a non-confidential basis prior to disclosure to it by the
Company, (d) to the extent the Company shall have consented to such disclosure
in writing; provided that (x) any Information constituting trade secrets is
protected by an appropriate confidentiality stipulation or order, in any legal
proceeding and (y) the Bank will use its best efforts to give the Company prior
notice in the case of any disclosure of Information made in accordance with
subparagraph (b)(i) of this Section 7.9.
<PAGE> 34
31
IN WITNESS WHEREOF, the parties hereto have caused this
Amended and Restated Secured Revolving Credit Agreement to be duly executed by
their respective authorized officers as of the day and year first above
written.
THE COLUMBIA GAS SYSTEM, INC.
By: /s/ L. J. Bainter
----------------------
Title: Treasurer
Address for Notices:
20 Montchanin Road
Wilmington, Delaware 19807
Attention: L.J. Bainter
Telephone: (302) 429-5597
Telecopy: (302) 429-5461
CHEMICAL
By: /s/ Thomas L. James
------------------------
Title: Managing Director
Address for Notices:
270 Park Avenue
New York, New York 10017
Attention: Thomas James
Telephone: (212) 270-1348
Telecopy: (212) 949-1459
<PAGE> 1
Exhibit 11
THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES
Statements Re Computation of Per Share Earnings
Year Ended December 31,
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
Computation for Statements of Consolidated
Income ($ in millions)
<S> <C> <C> <C>
Income before extraordinary item and
cumulative effect of accounting change . . . . . . . . . . . . 246.2 152.2 90.9
Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . . - - (39.7)
Change in accounting for postretirement benefits . . . . . . . . . (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 . . . . . . . . . . . . . . . . . . . . . . . . - - (.78)
Change in accounting for postretirement benefits . . . . . . . . . (0.11) - -
- ------------------------------------------------------------------------------------------------------------------
Earnings on common stock . . . . . . . . . . . . . . . . . . . . . 4.76 3.01 1.01
==================================================================================================================
Additional computation of average common
shares outstanding (thousands) NOTE
- ------------------------------------------------------------------------------------------------------------------
Average shares of common stock outstanding . . . . . . . . . . . . 50,560 50,559 50,559
Incremental common shares applicable to
common stock based on the common stock
daily average market price:
Applicable to contingent stock awards . . . . . . . . . . . . . . 3 4 4
- ------------------------------------------------------------------------------------------------------------------
Average common shares as adjusted . . . . . . . . . . . . . . . . . 50,563 50,563 50,563
==================================================================================================================
Average shares of common stock outstanding . . . . . . . . . . . . 50,560 50,559 50,559
Incremental common shares applicable to
common stock based on the more dilutive
of the common stock ending or daily average
market price during the year:
Applicable to contingent stock awards . . . . . . . . . . . . . . 3 4 4
- ------------------------------------------------------------------------------------------------------------------
Average common shares assuming full dilution . . . . . . . . . . . 50,563 50,563 50,563
==================================================================================================================
Earnings (loss) per share of common stock
as adjusted:
Before extraordinary item and accounting change . . . . . . . . . 4.87 3.01 1.79
Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . . - - (.78)
Change in accounting for postretirement benefits . . . . . . . . . (0.11) - -
- ------------------------------------------------------------------------------------------------------------------
Average common shares as adjusted ($) . . . . . . . . . . . . . . . 4.76 3.01 1.01
==================================================================================================================
Earnings (loss) per common shares assuming full
dilution:
Before extraordinary item and accounting change . . . . . . . . . . 4.87 3.01 1.79
Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . . - - (.78)
Change in accounting for postretirement benefits . . . . . . . . . (0.11) - -
- ------------------------------------------------------------------------------------------------------------------
Average common shares assuming full dilution ($) . . . . . . . . . 4.76 3.01 1.01
==================================================================================================================
</TABLE>
NOTE These caculations are submitted in accordance with the Securities
Exchange Act of 1934 Release No. 9083 although not required by
footnote 2 to paragraph 14 of Accounting Principles Opinion No. 15
because they result in dilution of less than 3%.
<PAGE> 1
Exhibit 12
THE COLUMBIA GAS SYSTEM, INC., AND SUBSIDIARIES
Statements of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
($ in millions)
<TABLE>
<CAPTION>
Twelve Months
Ended December 31,
---------------------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Consolidated Income (Loss) from Continuing Operations
before Income Taxes and Extraordinary Charges . . . . . . . . 392.2 288.1 161.4 (1,205.8) 162.6
Adjustments:
Interest during construction . . . . . . . . . . . . . . . - - - (3.4) (10.0)
Distributed (Undistributed) equity income . . . . . . . . (0.9) (0.1) (0.1) (2.4) 2.9
Fixed charges . . . . . . . . . . . . . . . . . . . . . . 14.8 101.5 13.7 139.9 182.5
------- ------- ------- ---------- ---------
Earnings Available . . . . . . . . . . . . . . . . . 406.1 389.5 175.0 (1,071.7) 338.0
------- ------- ------- ---------- ---------
Fixed Charges:
Interest on long-term and short-term debt . . . . . . . . 0.7 3.1 4.9 112.4 170.6
Other interst . . . . . . . . . . . . . . . . . . . . . . 14.1 98.4 8.8 27.6 10.5
------- ------- ------- ---------- ---------
Total Fixed Charges before Adjustments*,** . . . . . 14.8 101.5 13.7 140.0 181.1
------- ------- ------- ---------- ---------
Adjustments:
Gain/(Loss) on reacquired debt . . . . . . . . . . . . . . - - - (0.1) 1.4
------- ------- ------- ---------- ---------
Total Fixed Charges . . . . . . . . . . . . . . . . . 14.8 101.5 13.7 139.9 182.5
------- ------- ------- ---------- ---------
Ratio of Earnings Before Taxes to Fixed Charges . . . . . . . . 27.44 3.84 12.77 N/A(a) 1.85
======= ======= ======= ========== =========
</TABLE>
(a) To achieve a one-to-one coverage, the Corporation would need an additional
$1,211.6 million of earnings.
* This amount excludes approximately $222 million, $207 million, $203
million and $84 million of estimated interest expense not recorded for
1994, 1993, 1992 and 1991, respectively. Reference is made to the
Statements of Consolidated Income for the twelve months ended December 31,
1994, as reported in Form 10-K and to Note 2 of Notes to Consolidated
Financial Statements of the Corporation's Annual Report on Form 10-K for
the year ended December 31, 1994.
** This amount excludes $8.6 million of interest expense not recorded with
respect to the registrant's guarantee of LESOP Trust's debentures for each
of the twelve months ended December 31, 1994, 1993, 1992 and 1991, and
$6.7 million of interest expense not recorded with respect to the
registrant's guarantee of LESOP Trust's debentures for the twelve months
ended December 31, 1990.
<PAGE> 1
Exhibit 21
SUBSIDIARIES OF THE COLUMBIA GAS SYSTEM, INC.
as of December 31, 1994
<TABLE>
<CAPTION>
State of
Segment / Subsidiary Incorporation
- --------------------------------------------------- --------------------
<S> <C>
Oil and Gas Operations
Columbia Gas Development Corporation Delaware
Columbia Natural Resources, Inc. Texas
Transmission Operations
Columbia Gas Transmission Corporation Delaware
Columbia Gulf Transmission Company Delaware
Distribution Operations
Columbia Gas of Kentucky, Inc. Kentucky
Columbia Gas of Maryland, Inc. Delaware
Columbia Gas of Ohio, Inc. Ohio
Columbia Gas of Pennsylvania, Inc. Pennsylvania
Commonwealth Gas Services, Inc. Virginia
Other Energy Operations
Columbia Atlantic Trading Corporation Delaware
Columbia Coal Gasification Corporation Delaware
Columbia Energy Services Corporation Kentucky
Columbia Gas System Service Corporation Delaware
Columbia LNG Corporation Delaware
Columbia Propane Corporation Delaware
Commonwealth Propane, Inc. Virginia
TriStar Ventures Corporation Delaware
TriStar Capital Corporation Delaware
</TABLE>
<PAGE> 1
EXHIBIT 23-A
CONSENT
As independent petroleum and natural gas consultants, we
hereby consent to the filing of this Letter Report in its entirety as an
Exhibit to the 1993 Annual Report of The Columbia Gas System, Inc., to the
Securities and Exchange Commission on Form 10-K, and any Registration Statement
of The Columbia Gas System, Inc., relating to the issue of securities to the
public during 1995; to the quotation or summarization of portions of this
Letter Report, subject to our approval of the related page(s) of the
document(s), in the 10-K, the Prospectus included in said Registration
Statement(s) or the 1994 Annual Report to Stockholders; and, subject to
approval of the related page(s) of the document(s), to the use of our name and
the reliance upon our authority as experts in said Annual Report to
Stockholders, Form 10-K and Prospectus(es) and in Part II of said Registration
Statement(s). We have no interest of a substantial or material nature in The
Columbia Gas System, Inc., or in any affiliate, nor are we to receive any such
interest as payment for the preparation of this Letter Report; we have not been
employed for such preparation on a contingent fee basis; and we are not
connected with The Columbia Gas System, Inc., or any affiliate as a promoter,
underwriter, voting trustee, director, officer, employee, or affiliate.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
February 3, 1995
<PAGE> 2
January 24, 1995
The Columbia Gas System, Inc.
20 Montchanin Road
Wilmington, Delaware 19807
Attention: Mr. Jeffrey Grossman, Assistant Controller
Arthur Andersen & Company
1345 Avenue of the Americas
New York, New York 10105
Attention: Mr. J. M. Sepanski
Gentlemen:
The estimated reserve volumes and future income amounts
presented in this report are related to hydrocarbon prices. December 1994
hydrocarbon prices were used in the preparation of this report as required by
Securities and Exchange Commission (SEC) and Financial Accounting Standards
Bulletin No. 69 (FASB 69) guidelines; however, actual future prices may vary
significantly from December 1994 prices. Therefore, volumes of reserves
actually recovered and amounts of income actually received may differ
significantly from the estimated quantities presented in this report.
Our estimates of the net proved reserves attributable to the
interests of The Columbia Gas System, Inc. (referred to herein as the Company)
as of December 31, 1994 are presented below. Table 1 is a tabulation of the
oil, gas, and natural gas liquid reserves by subsidiary. The Company's
reserves are located in the United States and the Federal Offshore waters.
<TABLE>
<CAPTION>
Proved Net Reserves
As of December 31, 1994
------------------------------------------
Liquid, Barrels Gas, MMCF
----------------- -----------------
<S> <C> <C>
Developed and Undeveloped 12,254,925 683,768
Developed 11,504,250 543,346
</TABLE>
The "Liquid" reserves shown above are comprised of crude oil,
condensate, and natural gas liquids. Natural gas liquids comprise 13.3 percent
of the Company's developed liquid reserves and 12.5 percent of the Company's
developed and undeveloped liquid reserves. All hydrocarbon liquid reserves are
expressed in standard 42 gallon barrels. All gas volumes are sales gas
expressed in MMCF at the pressure and temperature bases of the area where the
gas reserves are located.
In accordance with the requirements of FASB 69, our estimates
of the Company's net proved reserves as of December 31, 1991, 1992, 1993, and
1994, as contained in this report and our previous reports, are presented in
attached Table No. 2 together with a tabulation of the components of the
differences in the estimates as of such dates.
The proved reserves presented in this report comply with the
SEC's Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent
Commission Staff Accounting Bulletins, and are based on the following
definitions and criteria:
<PAGE> 3
The Columbia Gas System, Inc.
Arthur Andersen & Company
January 24, 1995
Page 2
Proved reserves of crude oil, condensate, natural gas, and
natural gas liquids are estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be recoverable
in the future from known reservoirs under existing conditions.
Reservoirs are considered proved if economic producibility is supported
by actual production or formation tests. In certain instances, proved
reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are
analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a
reservoir considered proved includes (1) that portion delineated by
drilling and defined by fluid contacts, if any, and (2) the adjoining
portions not yet drilled that can be reasonably judged as economically
productive on the basis of available geological and engineering data. In
the absence of data on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir. Proved reserves are estimates of hydrocarbons to be recovered
from a given date forward. They may be revised as hydrocarbons are
produced and additional data become available. Proved natural gas
reserves are comprised of non-associated, associated, and dissolved gas.
An appropriate reduction in gas reserves has been made for the expected
removal of natural gas liquids, for lease and plant fuel, and the
exclusion of non-hydrocarbon gases if they occur in significant
quantities and are removed prior to sale. Reserves that can be produced
economically through the application of improved recovery techniques are
included in the proved classification when these qualifications are met:
(1) successful testing by a pilot project or the operation of an
installed program in the reservoir provides support for the engineering
analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes
all methods for supplementing natural reservoir forces and energy, or
otherwise increasing ultimate recovery from a reservoir, including (1)
pressure maintenance, (2) cycling, and (3) secondary recovery in its
original sense. Improved recovery also includes the enhanced recovery
methods of thermal, chemical flooding, and the use of miscible and
immiscible displacement fluids. Estimates of proved reserves do not
include crude oil, natural gas, or natural gas liquids being held in
underground storage. Depending on the status of development, these
proved reserves are further subdivided into:
(i) "developed reserves" which are those proved reserves
reasonably expected to be recovered through existing wells with
existing equipment and operating methods, including (a) "developed
producing reserves" which are those proved developed reserves
reasonably expected to be produced from existing completion
intervals now open for production in existing wells, and (b)
"developed non-producing reserves" which are those proved
developed reserves which exist behind the casing of existing wells
which are reasonably expected to be produced through these wells
in the predictable future where the cost of making such
hydrocarbons available for production should be relatively small
compared to the cost of a new well; and
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on undrilled
acreage, from existing wells where a relatively large expenditure
is required, and from acreage for which an application of fluid
injection or other improved recovery technique is contemplated
where the technique has been proved effective by actual tests in
the area in the same reservoir. Reserves from undrilled acreage
are limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units are included only where it can
be demonstrated with reasonable certainty that there is continuity
of production from the existing productive formation.
Because of the direct relationship between volumes of proved
undeveloped reserves and development plans, we include in the proved
undeveloped category only reserves assigned to undeveloped locations that we
have been assured will definitely be drilled and reserves assigned to the
undeveloped portions of secondary or tertiary projects which we have been
assured will definitely be developed.
The Company has interests in certain tracts which have
substantial additional hydrocarbon quantities which cannot be classified as
proved and consequently are not included herein. The Company has active
exploratory and development drilling programs which may result in the
reclassification of significant additional volumes to the proved category.
<PAGE> 4
The Columbia Gas System, Inc.
Arthur Andersen & Company
January 24, 1995
Page 3
In accordance with the requirements of FASB 69, our estimates
of future cash inflows, future costs, and future net cash inflows before income
tax as of December 31, 1994 from this report and as of December 31, 1993 from
our previous report are presented below.
<TABLE>
<CAPTION>
As of December 31
($000)
----------------------------------------
1994 1993
---------------- ----------------
<S> <C> <C>
Future Cash Inflows $ 1,667,288 $ 2,206,438
Future Costs
Production $ 492,036 $ 508,017
Development 167,946 172,002
----------- ------------
Total Costs $ 659,982 $ 680,019
Future Net Cash Inflows
Before Income Tax $ 1,007,306 $ 1,526,419
Present Value at 10%
Before Income Tax $ 549,046 $ 778,386
</TABLE>
The future cash inflows are gross revenues before any
deductions. The production costs were based on current data and include
production taxes, ad valorem taxes, and certain other items such as
transportation costs in addition to the operating costs directly applicable to
the individual leases or wells. The development costs were based on current
data and include certain dismantlement and abandonment costs net of salvage.
Table 3 presents a tabulation showing future cash inflow data by subsidiary.
The Company furnished us with gas prices in effect at December
31, 1994 and with its forecasts of future gas prices which take into account
SEC guidelines, current market prices, contract prices, and fixed and
determinable price escalations where applicable. In accordance with SEC
guidelines, the future gas prices used in this report make no allowances for
future gas price increases which may occur as a result of inflation nor do they
account for seasonal variations in gas prices which may cause future yearly
average gas prices to be somewhat lower than December gas prices.
<PAGE> 5
The Columbia Gas System, Inc.
Arthur Andersen & Company
January 24, 1995
Page 4
For gas sold under contract, the contract gas price including fixed and
determinable escalations exclusive of inflation adjustments, was used until the
contract expires and then was adjusted to the current market price for the area
and held at this adjusted price to depletion of the reserves.
The Company furnished us with liquid prices in effect at
December 31, 1994 and these prices were held constant to depletion of the
properties. In accordance with SEC guidelines, changes in liquid prices
subsequent to December 31, 1994 were not considered in this report.
Operating costs for the leases and wells in this report are
based on the operating expense reports of the Company and include only those
costs directly applicable to the leases or wells. When applicable, the
operating costs include a portion of general and administrative costs allocated
directly to the leases and wells under terms of operating agreements.
Development costs were furnished to us by the Company and are based on
authorizations for expenditure for the proposed work or actual costs for
similar projects. The current operating and development costs were held
constant throughout the life of the properties. The estimated net cost of
abandonment after salvage was considered for the Appalachia properties and
offshore properties where abandonment costs net of salvage are significant.
The estimates of net abandonment costs furnished by the Company were accepted
without independent verification. Abandonment costs for certain other onshore
properties were not considered because of their relative insignificance.
No deduction was made for indirect costs such as general
administration and overhead expenses, loan repayments, interest expenses, and
exploration and development prepayments. No attempt has been made to quantify
or otherwise account for any accumulated gas production imbalances that may
exist.
In our examination, we made a detailed investigation of
reserves and future production and income for those properties of the Company
which comprise 93.0 percent of the total future net income discounted at 10
percent. Due to the limitations of time and to their relative insignificance,
we accepted without examination and included herein the Company's estimates of
reserves and future production and income for those properties which comprise
the remaining 7.0 percent of total future net income discounted at 10 percent.
No consideration was given in this report to potential environmental
liabilities which may exist nor were any costs included for potential inability
to restore and clean up damages, if any, caused by past operating practices.
The Company informed us that it has furnished us all of the accounts, records,
geological and engineering data and reports and other data required for our
investigation The ownership interests, prices and other factual data were
accepted as represented. Moreover, to facilitate timely issuance of this
report, production data used in this report includes estimated production for
the last few months of 1994.
The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may not be
actually recovered, and if recovered, the revenues therefrom and the actual
costs related thereto could be more or less than the estimated amounts.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells were then projected to decline at
their decreasing delivery capacity rate. Our general policy on estimates of
future gas production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases. The future production rates from wells
now on production may be more or less than estimated because of changes in
market demand or allowables set by regulatory bodies. Wells or locations which
are not currently producing may start producing earlier or later than
anticipated in our estimates of their future production rates.
While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and other costs
relating to such production may also increase or decrease from existing levels,
such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in making this
<PAGE> 6
The Columbia Gas System, Inc.
Arthur Andersen & Company
January 24, 1995
Page 5
evaluation.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future cash inflows
for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ Harry J. Gaston, Jr.
----------------------------
Harry J. Gaston, Jr., P.E.
President
HJG/sw
<PAGE> 7
TABLE 1
THE COLUMBIA GAS SYSTEM, INC.
Summary of Estimated Net Reserves in the United States
<TABLE>
<CAPTION>
As of December 31, 1994
--------------------------------------------------------
Developed Undeveloped Total
--------------- --------------- ---------------
<S> <C> <C> <C>
SALES GAS - MMCF
- ----------------
Columbia Natural Resources Inc. 417,323 128,639 545,962
Columbia Gas Development Corp. 126,023 11,783 137,806
---------- --------- -------------
Total Gas 543,346 140,422 683,768
OIL/CONDENSATE - BARRELS
- ------------------------
Columbia Natural Resources Inc. 1,504,085 0 1,504,085
Columbia Gas Development Corp. 8,473,471 743,503 9,216,974
--------- ------- ------------
Total Oil/Condensate 9,977,556 743,503 10,721,059
NATURAL GAS LIQUIDS
- -------------------
Columbia Natural Resources Inc. 0 0 0
Columbia Gas Development Corp. 1,526,694 7,172 1,533,866
--------- --------- -----------
Total Natural Gas Liquids 1,526,694 7,172 1,533,866
</TABLE>
General: Volumes shown are net interest (i.e., working interest less
royalty interests).
<PAGE> 8
Page 1 of
TABLE 2
COLUMBIA GAS SYSTEM, INC.
PROVED NET RESERVES DATA
AS OF DECEMBER 31, 1994
<TABLE>
<CAPTION>
COLUMBIA NATURAL RESOURCES INC.(2)(3)
-------------------------------------------------------------
1994 1993 1992 1991
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Net Proved Liquid Reserves - Barrels(1)
- ------------------------------------
Developed and Undeveloped
- -------------------------
Beginning of Year 1,605,177 1,961,800 1,921,868 1,796,599
Revisions -108,420 -248,472 209,114 201,318
Extensions and Discoveries 291,238 106,681 48,253 119,899
Improved Recovery 0 0 0 0
Production -283,910 -214,832 -217,435 -195,948
Purchases of Reserves In-Place 0 0 0 0
Sales of Reserves In-Place 0 0 0 0
End of Year 1,504,085 1,605,177 1,961,800 1,921,868
Developed
---------
Beginning of Year 1,578,927 1,953,695 1,913,763 1,643,239
End of Year 1,504,085 1,578,927 1,953,695 1,913,763
Net Proved Gas Reserves - MMCF
- ------------------------------
Developed and Undeveloped
-------------------------
Beginning of Year 560,965 604,488 626,449 612,634
Revisions -35,982 -40,962 -15,591 15,106
Extensions and Discoveries 54,410 35,722 30,295 42,035
Improved Recovery 0 0 0 0
Production -32,959 -35,021 -35,150 -32,089
Purchases of Reserves In-Place 0 0 0 0
Sales of Reserves In-Place -472 -3,262 -1,515 -11,237
End of Year 545,962 560,965 604,488 626,449
Developed
---------
Beginning of Year 462,007 513,078 540,712 536,101
End of Year 417,323 462,007 513,078 540,712
</TABLE>
<TABLE>
<CAPTION>
INLAND GAS COMPANY (2)
-----------------------------------------------------
1994 1993 1992 1991
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Net Proved Liquid Reserves - Barrels(1)
- ------------------------------------
Developed and Undeveloped
- -------------------------
Beginning of Year 0 0 0 0
Revisions 0 0 1,913 2,140
Extensions and Discoveries 0 0 0 0
Improved Recovery 0 0 0
Production 0 0 -1,913 -2,140
Purchases of Reserves In-Place 0 0 0 0
Sales of Reserves In-Place 0 0 0 0
End of Year 0 0 0 0
Developed
---------
Beginning of Year 0 0 0 0
End of Year 0 0 0 0
Net Proved Gas Reserves - MMCF
- ------------------------------
Developed and Undeveloped
-------------------------
Beginning of Year 0 24,981 26,254 26,344
Revisions 0 -24,981 195 1,693
Extensions and Discoveries 0 0 0 0
Improved Recovery 0 0 0 0
Production 0 0 -1,356 -1,783
Purchases of Reserves In-Place 0 0 0 0
Sales of Reserves In-Place 0 0 -112 0
End of Year 0 0 24,981 26,254
Developed
---------
Beginning of Year 0 24,305 25,517 25,608
End of Year 0 0 24,305 25,517
</TABLE>
<PAGE> 9
Page 2 of
TABLE 2
COLUMBIA GAS SYSTEM, INC.
PROVED NET RESERVES DATA
AS OF DECEMBER 31, 1994
<TABLE>
<CAPTION>
APPALACHIAN AREA
----------------------------------------------------------
1994 1993 1992 1991
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Net Proved Liquid Reserves - Barrels(1)
- ------------------------------------
Developed and Undeveloped
- -------------------------
Beginning of Year 1,605,177 1,961,800 1,921,868 1,796,599
Revisions -108,420 -248,472 211,027 203,458
Extensions and Discoveries 291,238 106,681 48,253 119,899
Improved Recovery 0 0 0 0
Production -283,910 -214,832 -219,348 -198,088
Purchases of Reserves In-Place 0 0 0 0
Sales of Reserves In-Place 0 0 0 0
End of Year 1,504,085 1,605,177 1,961,800 1,921,868
Developed
---------
Beginning of Year 1,578,927 1,953,695 1,913,763 1,643,239
End of Year 1,504,085 1,578,927 1,953,695 1,913,763
Net Proved Gas Reserves - MMCF
- ------------------------------
Developed and Undeveloped
-------------------------
Beginning of Year 560,965 629,469 652,703 638,978
Revisions -35,982 -65,943 -15,396 16,799
Extensions and Discoveries 54,410 35,722 30,295 42,035
Improved Recovery 0 0 0 0
Production -32,959 -35,021 -36,506 -33,872
Purchases of Reserves In-Place 0 0 0 0
Sales of Reserves In-Place -472 -3,262 -1,627 -11,237
End of Year 545,962 560,965 629,469 652,703
Developed
---------
Beginning of Year 462,007 537,383 566,229 561,709
End of Year 417,323 462,007 537,383 566,229
</TABLE>
<TABLE>
<CAPTION>
COLUMBIA GAS DEVELOPMENT CORPORATION (4)
----------------------------------------------------------------
1994 1993 1992 1991
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Net Proved Liquid Reserves - Barrels(1)
- ------------------------------------
Developed and Undeveloped
- -------------------------
Beginning of Year 11,187,195 12,688,494 13,646,268 12,944,718
Revisions 1,755,212 -340,701 -1,157,063 -1,057,271
Extensions and Discoveries 1,094,997 2,227,717 3,040,860 4,394,136
Improved Recovery 0 0 0 0
Production -3,324,154 -3,388,315 -2,841,571 -2,635,315
Purchases of Reserves In-Place 37,590 0 0 0
Sales of Reserves In-Place 0 0 0 0
End of Year 10,750,840 11,187,195 12,688,494 13,646,268
Developed
---------
Beginning of Year 9,213,848 11,189,415 11,423,798 9,567,172
End of Year 10,000,165 9,213,848 11,189,415 11,423,798
Net Proved Gas Reserves - MMCF
- ------------------------------
Developed and Undeveloped
-------------------------
Beginning of Year 136,081 150,021 155,445 173,519
Revisions 4,495 5,839 6,267 -2,572
Extensions and Discoveries 27,254 16,733 20,956 20,689
Improved Recovery 0 0 0 0
Production -33,622 -36,512 -32,647 -36,191
Purchases of Reserves In-Place 3,598 0 0 0
Sales of Reserves In-Place 0 0 0 0
End of Year 137,806 136,081 150,021 155,445
Developed
---------
Beginning of Year 111,713 126,983 131,495 168,360
End of Year 126,023 111,713 126,983 131,495
</TABLE>
<PAGE> 10
Page 3 of 3
TABLE 2
COLUMBIA GAS SYSTEM, INC.
PROVED NET RESERVES DATA
AS OF DECEMBER 31, 1994
<TABLE>
<CAPTION>
THE COLUMBIA GAS SYSTEM, INC. (2)(4)
------------------------------------------------------------
1994 1993 1992 1991
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Net Proved Liquid Reserves - Barrels(1)
- ------------------------------------
Developed and Undeveloped
- -------------------------
Beginning of Year 12,792,372 14,650,294 15,568,136 14,741,317
Revisions 1,646,792 -589,173 -946,036 -853,813
Extensions and Discoveries 1,386,235 2,334,398 3,089,113 4,514,035
Improved Recovery 0 0 0 0
Production -3,608,064 -3,603,147 -3,060,919 -2,833,403
Purchases of Reserves In-Place 37,590 0 0 0
Sales of Reserves In-Place 0 0 0 0
End of Year 12,254,925 12,792,372 14,650,294 15,568,136
Developed
---------
Beginning of Year 10,792,775 13,143,110 13,337,561 11,210,411
End of Year 11,504,250 10,792,775 13,143,110 13,337,561
Net Proved Gas Reserves - MMCF
- ------------------------------
Developed and Undeveloped
-------------------------
Beginning of Year 697,046 779,490 808,148 812,497
Revisions -31,487 -60,104 -9,129 14,227
Extensions and Discoveries 81,664 52,455 51,251 62,724
Improved Recovery 0 0 0 0
Production -66,581 -71,533 -69,153 -70,063
Purchases of Reserves In-Place 3,598 0 0 0
Sales of Reserves In-Place -472 -3,262 -1,627 -11,237
End of Year 683,768 697,046 779,490 808,148
Developed
---------
Beginning of Year 573,720 664,366 697,724 730,069
End of Year 543,346 573,720 664,366 697,724
</TABLE>
(1) Liquid reserves shown above are comprised of crude oil, condensate
and natural gas liquids.
(2) Inland Gas Company reserves combined with Columbia Natural Resources
in 1993.
(3) Columbia Gas Transmission Company reserves combined with Columbia
Natural Resources in 1990.
(4) Includes some Company supplied estimates. See discussion.
<PAGE> 11
TABLE 3
COLUMBIA GAS SYSTEM, INC.
PRESENT VALUE OF FUTURE NET REVENUE FROM PROVED RESERVES
FROM UNITED STATES RESERVES
AS OF DECEMBER 31, 1994
($000)
<TABLE>
<CAPTION>
COLUMBIA NATURAL RESOURCES INC. (a)
-------------------------------------------
Developed Undeveloped Total
--------- ----------- ----------
<S> <C> <C> <C>
Revenues from Production 984,120 290,635 1,274,755
Costs of Development (b) 16,172 108,323 124,495
Costs of Production 338,260 42,613 380,873
Future Net Revenue 629,688 139,699 769,387
Present Value Discounted @ 10% 326,491 26,486 352,977
</TABLE>
<TABLE>
<S> <C>
Present Value Attributable to:
(1) Reserves added Prior to 1994 329,605
(2) Proved Reserves Added During 1994 23,372
(3) Application of Improved Recovery Techniques During 1994 0
(4) Purchases of Reserves In-Place During 1994 0
</TABLE>
<TABLE>
<CAPTION>
COLUMBIA GAS
DEVELOPMENT CORPORATION (c)
----------------------------------------
Developed Undeveloped Total
--------- ----------- ----------
<S> <C> <C> <C>
Revenues from Production 359,191 33,342 392,533
Costs of Development (b) 34,922 8,529 43,451
Costs of Production 108,204 2,959 111,163
Future Net Revenue 216,065 21,854 237,919
Present Value Discounted @ 10% 180,438 15,631 196,069
</TABLE>
<TABLE>
<S> <C>
Present Value Attributable to:
(1) Reserves added Prior to 1994 150,184
(2) Proved Reserves Added During 1994 44,882
(3) Application of Improved Recovery Techniques During 1994 0
(4) Purchases of Reserves In-Place During 1994 1,003
</TABLE>
<TABLE>
<CAPTION>
THE COLUMBIA GAS SYSTEM, INC. (c)
---------------------------------------------
Developed Undeveloped Total
--------- ----------- ----------
<S> <C> <C> <C>
Revenues from Production 1,343,311 323,977 1,667,288
Costs of Development (b) 51,094 116,852 167,946
Costs of Production 446,464 45,572 492,036
Future Net Revenue 845,753 161,553 1,007,306
Present Value Discounted @ 10% 506,929 42,117 549,046
</TABLE>
<TABLE>
<S> <C>
Present Value Attributable to:
(1) Reserves added Prior to 1994 479,789
(2) Proved Reserves Added During 1994 68,254
(3) Application of Improved Recovery Techniques During 1994 0
(4) Purchases of Reserves In-Place During 1994 1,003
</TABLE>
(a) Reflects merging of reserves from Columbia Gas Transportation and Inland
Gas Company with those of Columbia Natural Resources.
(b) Includes future development and abandonment costs.
(c) Includes some company supplied estimates. See discussion.
<PAGE> 1
EXHIBIT 23-B
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated February 9, 1995, included in The Columbia Gas System, Inc.'s
1994 Annual Report on Form 10-K, into the following previously filed
registration statements:
1. Form S-8 of The Columbia Gas System, Inc. (File No. 33-10004)
2. Form S-8 of The Columbia Gas System, Inc. (File No. 33-42776)
ARTHUR ANDERSEN LLP
New York, New York
March 6, 1995
<PAGE> 1
EXHIBIT 24
COLUMBIA GAS SYSTEM 10-K FILING
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
WHEREAS, THE COLUMBIA GAS SYSTEM, INC., a Delaware corporation
(the "Corporation"), proposes to file with the Securities and Exchange
Commission, under the Securities Exchange Act of 1934, as amended, an annual
report on Form 10-K for the fiscal year ended December 31, 1994, together with
such exhibits and amendments as may be necessary or appropriate thereto.
NOW THEREFORE, the undersigned hereby constitutes and appoints
J. H. Croom, M. W. O'Donnell, R. E. Lowe, D. L. Bell, Jr., and L. J. Bainter,
and each of them, as attorneys for him or her in his or her name, place and
stead to sign such Form 10-K and any and all amendments thereto, and to file
the same with all exhibits thereto, and other documents in connection
therewith, hereby giving and granting to said attorneys full power and
authority (including substitution and revocation) to do and perform all and
every act and thing whatsoever requisite and necessary to be done in and about
the premises as fully, to all intents and purposes, as he or she might or could
do if personally present at the doing thereof, hereby ratifying and confirming
all that said attorneys may or shall lawfully do, or cause to be done, by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereunto set his or
her hand on the date indicated.
/s/CG Board of Directors
--------------------------------
Dated: February 15, 1995
<PAGE> 2
J. H. Croom
COLUMBIA GAS SYSTEM 10-K FILING
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
WHEREAS, THE COLUMBIA GAS SYSTEM, INC., a Delaware corporation
(the "Corporation"), proposes to file with the Securities and Exchange
Commission, under the Securities Exchange Act of 1934, as amended, an annual
report on Form 10-K for the fiscal year ended December 31, 1994, together with
such exhibits and amendments as may be necessary or appropriate thereto.
NOW THEREFORE, the undersigned hereby constitutes and appoints
M. W. O'Donnell, R. E. Lowe, D. L. Bell, Jr., and L. J. Bainter, and each of
them, as attorneys for him or her in his or her name, place and stead to sign
such Form 10-K and any and all amendments thereto, and to file the same with
all exhibits thereto, and other documents in connection therewith, hereby
giving and granting to said attorneys full power and authority (including
substitution and revocation) to do and perform all and every act and thing
whatsoever requisite and necessary to be done in and about the premises as
fully, to all intents and purposes, as he or she might or could do if
personally present at the doing thereof, hereby ratifying and confirming all
that said attorneys may or shall lawfully do, or cause to be done, by virtue
hereof.
IN WITNESS WHEREOF, the undersigned has hereunto set his or
her hand on the date indicated.
/s/J. H. Croom
--------------------------------
Dated: February 2, 1995
<PAGE> 3
M. W. O'Donnell
COLUMBIA GAS SYSTEM 10-K FILING
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
WHEREAS, THE COLUMBIA GAS SYSTEM, INC., a Delaware corporation
(the "Corporation"), proposes to file with the Securities and Exchange
Commission, under the Securities Exchange Act of 1934, as amended, an annual
report on Form 10-K for the fiscal year ended December 31, 1994, together with
such exhibits and amendments as may be necessary or appropriate thereto.
NOW THEREFORE, the undersigned hereby constitutes and appoints
J. H. Croom, R. E. Lowe, D. L. Bell, Jr., and L. J. Bainter, and each of them,
as attorneys for him or her in his or her name, place and stead to sign such
Form 10-K and any and all amendments thereto, and to file the same with all
exhibits thereto, and other documents in connection therewith, hereby giving
and granting to said attorneys full power and authority (including substitution
and revocation) to do and perform all and every act and thing whatsoever
requisite and necessary to be done in and about the premises as fully, to all
intents and purposes, as he or she might or could do if personally present at
the doing thereof, hereby ratifying and confirming all that said attorneys may
or shall lawfully do, or cause to be done, by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereunto set his or
her hand on the date indicated.
/s/M. W. O'Donnell
--------------------------------
Dated: February 2, 1995
<PAGE> 4
R. E. Lowe
COLUMBIA GAS SYSTEM 10-K FILING
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
WHEREAS, THE COLUMBIA GAS SYSTEM, INC., a Delaware corporation
(the "Corporation"), proposes to file with the Securities and Exchange
Commission, under the Securities Exchange Act of 1934, as amended, an annual
report on Form 10-K for the fiscal year ended December 31, 1994, together with
such exhibits and amendments as may be necessary or appropriate thereto.
NOW THEREFORE, the undersigned hereby constitutes and appoints
J. H. Croom, M. W. O'Donnell, D. L. Bell, Jr., and L. J. Bainter, and each of
them, as attorneys for him or her in his or her name, place and stead to sign
such Form 10-K and any and all amendments thereto, and to file the same with
all exhibits thereto, and other documents in connection therewith, hereby
giving and granting to said attorneys full power and authority (including
substitution and revocation) to do and perform all and every act and thing
whatsoever requisite and necessary to be done in and about the premises as
fully, to all intents and purposes, as he or she might or could do if
personally present at the doing thereof, hereby ratifying and confirming all
that said attorneys may or shall lawfully do, or cause to be done, by virtue
hereof.
IN WITNESS WHEREOF, the undersigned has hereunto set his or
her hand on the date indicated.
/s/R. E. Lowe
--------------------------------
Dated: Febuary 15, 1995
<PAGE> 5
D. L. Bell, Jr.
COLUMBIA GAS SYSTEM 10-K FILING
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
WHEREAS, THE COLUMBIA GAS SYSTEM, INC., a Delaware corporation
(the "Corporation"), proposes to file with the Securities and Exchange
Commission, under the Securities Exchange Act of 1934, as amended, an annual
report on Form 10-K for the fiscal year ended December 31, 1994, together with
such exhibits and amendments as may be necessary or appropriate thereto.
NOW THEREFORE, the undersigned hereby constitutes and appoints
J. H. Croom, M. W. O'Donnell, R. E. Lowe, and L. J. Bainter, and each of them,
as attorneys for him or her in his or her name, place and stead to sign such
Form 10-K and any and all amendments thereto, and to file the same with all
exhibits thereto, and other documents in connection therewith, hereby giving
and granting to said attorneys full power and authority (including substitution
and revocation) to do and perform all and every act and thing whatsoever
requisite and necessary to be done in and about the premises as fully, to all
intents and purposes, as he or she might or could do if personally present at
the doing thereof, hereby ratifying and confirming all that said attorneys may
or shall lawfully do, or cause to be done, by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereunto set his or
her hand on the date indicated.
/s/D. L. Bell, Jr.
--------------------------------
Dated: Febuary 2, 1995
<PAGE> 6
L. J. Bainter
COLUMBIA GAS SYSTEM 10-K FILING
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS:
WHEREAS, THE COLUMBIA GAS SYSTEM, INC., a Delaware corporation
(the "Corporation"), proposes to file with the Securities and Exchange
Commission, under the Securities Exchange Act of 1934, as amended, an annual
report on Form 10-K for the fiscal year ended December 31, 1994, together with
such exhibits and amendments as may be necessary or appropriate thereto.
NOW THEREFORE, the undersigned hereby constitutes and appoints
J. H. Croom, M. W. O'Donnell, R. E. Lowe, D. L. Bell, Jr., and each of them, as
attorneys for him or her in his or her name, place and stead to sign such Form
10-K and any and all amendments thereto, and to file the same with all exhibits
thereto, and other documents in connection therewith, hereby giving and
granting to said attorneys full power and authority (including substitution and
revocation) to do and perform all and every act and thing whatsoever requisite
and necessary to be done in and about the premises as fully, to all intents and
purposes, as he or she might or could do if personally present at the doing
thereof, hereby ratifying and confirming all that said attorneys may or shall
lawfully do, or cause to be done, by virtue hereof.
IN WITNESS WHEREOF, the undersigned has hereunto set his or
her hand on the date indicated.
/s/L. J. Bainter
--------------------------------
Dated: Febuary 15, 1995
<PAGE> 7
CERTIFICATION
I, Tejinder S. Bindra, Assistant Secretary of THE COLUMBIA GAS SYSTEM,
INC., do hereby certify that the following is a true and complete copy of
resolutions duly adopted by the Board of Directors of said Corporation at a
meeting duly called and held in Wilmington, Delaware, on February 15, 1995, at
which a quorum was present and acting throughout.
RESOLVED, that the officers of the Corporation be, and they
hereby are, authorized to file an Annual Report on Form 10-K for the
fiscal year ended December 31, 1994, under the Securities Exchange Act
of 1934, as amended, together with such exhibits and amendments as may
be necessary or appropriate thereto; and
RESOLVED, that J. H. Croom, L. J. Bainter, D. L. Bell, Jr., R.
E. Lowe, and M. W. O'Donnell be, and each of them with full power to
act without the others and with full power of substitution and
resubstitution hereby is, authorized to sign such Annual Report for
the fiscal year ended December 31, 1994, on Form 10-K, and any and all
amendments thereto, on behalf of and as attorneys for this Corporation
and on behalf of and as attorneys for the principal executive officer,
the principal financial officer, the principal accounting officer, any
member of the Board of Directors, and any other officer of this
Corporation.
WITNESS my hand and the corporate seal of said Corporation, this 15th
day of February, 1995.
/s/T. S. Bindra
---------------------------------
Tejinder S. Bindra
SEAL
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