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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-9864
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EL PASO TENNESSEE PIPELINE CO.
(Exact Name of Registrant as Specified in its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0233548
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
</TABLE>
Registrant's Telephone Number, Including Area Code: (713) 420-2131
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 preceding 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] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, par value $.01 per share. Shares outstanding on August 10,
1999: 1,971
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GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-Q are defined below:
<TABLE>
<CAPTION>
DEFINITIONS
-----------
<S> <C>
ALJ....................... Administrative Law Judge
Company................... El Paso Tennessee Pipeline Co. and its subsidiaries
Court of Appeals.......... United States Court of Appeals for the District of Columbia
Circuit
EAPRC..................... East Asia Power Resources Corporation, a publicly traded
Philippine company
EBIT...................... Earnings before interest expense and income taxes, excluding
affiliate interest income
EnCap..................... EnCap Investments L.C., a Texas limited liability company
EPA....................... United States Environmental Protection Agency
EPEC...................... El Paso Energy Corporation, the parent of El Paso Tennessee
Pipeline Co.
EPEI...................... El Paso Energy International Company, a wholly owned
subsidiary of El Paso Tennessee Pipeline Co.
EPEM...................... El Paso Energy Marketing Company, a wholly owned indirect
subsidiary of El Paso Tennessee Pipeline Co.
EPFS...................... El Paso Field Services Company, a wholly owned subsidiary of
El Paso Tennessee Pipeline Co.
EPNG...................... El Paso Natural Gas Company, a wholly owned subsidiary of El
Paso Energy Corporation
EPTPC..................... El Paso Tennessee Pipeline Co., a direct subsidiary of El
Paso Energy Corporation
FERC...................... Federal Energy Regulatory Commission
GSR....................... Gas supply realignment
PCB(s).................... Polychlorinated-biphenyl(s)
PLN....................... Perusahaan, Listrik Negra, the Indonesian government-owned
electric utility
PRP(s).................... Potentially responsible party(ies)
TGP....................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of
El Paso Tennessee Pipeline Co.
</TABLE>
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PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
(UNAUDITED)
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
---------------- ----------------
1999 1998 1999 1998
------ ------ ------ ------
<S> <C> <C> <C> <C>
Operating revenues...................................... $1,005 $1,171 $2,021 $2,676
------ ------ ------ ------
Operating expenses......................................
Cost of gas and other products........................ 703 920 1,417 2,128
Operation and maintenance............................. 114 124 243 252
Depreciation, depletion, and amortization............. 52 50 104 99
Taxes, other than income taxes........................ 16 14 33 29
------ ------ ------ ------
885 1,108 1,797 2,508
------ ------ ------ ------
Operating income........................................ 120 63 224 168
------ ------ ------ ------
Other (income) and expense
Non-affiliated interest and debt expense.............. 37 30 73 62
Affiliated interest expense, net...................... -- 10 4 16
Equity investment earnings............................ (20) (14) (38) (23)
Net gain on sale of assets............................ (19) (7) (20) (10)
Other -- net.......................................... (9) (11) (24) (18)
------ ------ ------ ------
(11) 8 (5) 27
------ ------ ------ ------
Income before income taxes and cumulative effect of
accounting change..................................... 131 55 229 141
Income tax expense...................................... 39 16 71 45
------ ------ ------ ------
Income before cumulative effect of accounting change.... 92 39 158 96
Cumulative effect of accounting change, net of income
taxes................................................. -- -- (13) --
------ ------ ------ ------
Net income.............................................. $ 92 $ 39 $ 145 $ 96
====== ====== ====== ======
Comprehensive income.................................... $ 94 $ 35 $ 138 $ 91
====== ====== ====== ======
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
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EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
----------- ------------
(UNAUDITED)
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents................................. $ 24 $ 28
Accounts and notes receivable, net........................ 636 433
Materials and supplies.................................... 21 21
Assets from price risk management activities.............. 169 151
Other..................................................... 129 118
------ ------
Total current assets.............................. 979 751
Property, plant, and equipment, net......................... 5,614 5,628
Investment in unconsolidated affiliates..................... 820 579
Other....................................................... 595 476
------ ------
Total assets...................................... $8,008 $7,434
====== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable.......................................... $1,603 $1,200
Short-term borrowings (including current maturities of
long-term debt)........................................ 115 194
Other..................................................... 360 471
------ ------
Total current liabilities......................... 2,078 1,865
------ ------
Long-term debt, less current maturities..................... 1,555 1,467
------ ------
Deferred income taxes....................................... 1,349 1,277
------ ------
Other....................................................... 661 607
------ ------
Commitments and contingencies (See Note 3)
Minority interest........................................... 65 65
------ ------
Stockholders' equity
Preferred stock, 20,000,000 shares authorized;
Series A, no par; 6,000,000 shares issued; stated at
liquidation value..................................... 300 300
Common stock, par value $0.01 per share; authorized
100,000 shares; issued 1,971 shares.................... -- --
Additional paid-in capital................................ 1,561 1,540
Retained earnings......................................... 460 327
Accumulated comprehensive income.......................... (21) (14)
------ ------
Total stockholders' equity........................ 2,300 2,153
------ ------
Total liabilities and stockholders' equity........ $8,008 $7,434
====== ======
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
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EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED
JUNE 30
--------------
1999 1998
----- -----
<S> <C> <C>
Cash flows from operating activities
Net income................................................ $ 145 $ 96
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion, and amortization.............. 104 99
Deferred income taxes.................................. 72 11
Undistributed earnings in equity investees............. (22) (13)
Cumulative effect of accounting change, net of income
taxes................................................. 13 --
Net gain on sale of assets............................. (20) (10)
Working capital changes, net of the effect of
acquisitions........................................... (37) (20)
Other..................................................... (31) (34)
----- -----
Net cash provided by operating activities......... 224 129
----- -----
Cash flows from investing activities
Capital expenditures...................................... (90) (86)
Investment in joint ventures and equity investees......... (340) (331)
Net change in advances from EPEC.......................... 303 389
Acquisition of EnCap Investments L.C. .................... (36) --
Restricted cash deposited in escrow related to equity
investee............................................... (89) --
Proceeds from sale of assets.............................. 34 14
Other..................................................... (6) (1)
----- -----
Net cash used in investing activities............. (224) (15)
----- -----
Cash flows from financing activities
Net commercial paper repayments........................... (79) --
Net proceeds from long-term note payable.................. 89 --
Dividends paid on preferred stock......................... (12) (12)
Revolving credit repayments............................... -- (117)
Other..................................................... (2) --
----- -----
Net cash used in financing activities............. (4) (129)
----- -----
Decrease in cash and temporary investments.................. (4) (15)
Cash and temporary investments
Beginning of period............................... 28 35
----- -----
End of period..................................... $ 24 $ 20
===== =====
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
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EL PASO TENNESSEE PIPELINE CO.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The 1998 Annual Report on Form 10-K for the Company includes a summary of
significant accounting policies and other disclosures and should be read in
conjunction with this Quarterly Report on Form 10-Q. The condensed consolidated
financial statements at June 30, 1999, and for the quarters and six months ended
June 30, 1999, and 1998, are unaudited. The condensed balance sheet at December
31, 1998, is derived from audited financial statements at that date. These
financial statements do not include all disclosures required by generally
accepted accounting principles, but have been prepared pursuant to the rules and
regulations of the U.S. Securities and Exchange Commission. In the opinion of
management, all material adjustments necessary to present fairly the results of
operations for such periods have been included. All such adjustments, except for
those relating to the change in Company structure as described below, are of a
normal recurring nature. Results of operations for any interim period are not
necessarily indicative of the results of operations for the entire year due to
the seasonal nature of the Company's businesses. Financial statements for the
previous periods include certain reclassifications which were made to conform to
the current presentation. Such reclassifications have no effect on reported net
income or stockholders' equity.
Change in Company Structure
On December 31, 1998, EPEC completed a series of steps to effect a tax-free
internal reorganization in which certain energy marketing operations of EPEM,
certain field services operations of EPFS, and certain international operations
of EPEI were transferred to EPTPC. The transactions were treated as a transfer
of ownership between entities under common control and were accounted for in a
manner similar to a pooling of interests. Accordingly, the information for the
quarter and six months ended June 30, 1998, has been restated as though the
transactions occurred on January 1, 1998.
Cumulative Effect of Accounting Change
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-Up
Activities. The statement defines start-up activities and requires start-up and
organization costs be expensed as incurred. In addition, it requires that any
such cost that exists on the balance sheet be expensed upon adoption of this
pronouncement. The Company adopted this pronouncement effective January 1, 1999,
and reported a charge of $13 million, net of income taxes, in the first quarter
of 1999 as a cumulative effect of a change in accounting principle.
2. ACQUISITIONS AND DISPOSITIONS
East Asia Power
In February 1999, the Company acquired a 46 percent ownership interest in
EAPRC and an interest in a convertible loan. Following its acquisition, the
Company converted part of its interest in the convertible loan to equity,
increasing its ownership interest to 51 percent. In April 1999, the Company
converted the balance of its interest in the convertible loan to equity,
increasing its ownership interest to 65 percent. At June 30, 1999, the Company's
total investment in EAPRC was approximately $75 million. Since the Company's
majority ownership is expected to be temporary, the investment is accounted for
under the equity method of accounting. EAPRC owns and operates seven power
generation facilities in the Philippines and owns an interest in one power
generation facility in China, with a total generating capacity of 412 megawatts.
Electric power generated by the facilities is supplied to a diversified base of
customers including National Power Corporation, the Philippine state-owned
utility, private distribution companies and industrial users.
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EnCap
In March 1999, the Company acquired EnCap for $52 million, net of cash
acquired. The purchase price included $17 million in EPEC common stock, of which
$7 million is issuable upon the occurrence of certain events. The acquisition
was accounted for as a purchase. EnCap is an institutional funds management firm
specializing in financing independent oil and gas producers. EnCap manages three
separate institutional oil and gas investment funds in the U.S., and serves as
investment advisor to Energy Capital Investment Company PLC, a publicly traded
investment company in the United Kingdom.
Other
In March 1999, the Company increased its ownership interest from 30 percent
to 40 percent in the Samalayuca Power project for approximately $22 million. In
addition, the Company made a $48 million equity contribution replacing equity
financing which was established in the second quarter of 1996.
In June 1999, the Company acquired a 26 percent interest in a power plant
in Tamil Nadu, India for $37 million. Approximately $11 million was paid in June
1999, and the remaining amount will be paid in the first quarter of 2001. The
project consists of a 346 megawatt combined cycle power plant which will serve
as a base load facility and sell power to the state-owned Tamil Nadu Electricity
Board under a thirty-year power purchase agreement. Construction began in
January 1999, and operations are expected to commence in early 2001.
In June 1999, the Company transferred a 49 percent interest in Viosca Knoll
Gathering Company to Leviathan Gas Pipeline Partners, L.P. for total
consideration of approximately $80 million. Total consideration included cash of
approximately $20 million with the balance in Leviathan Gas Pipeline Partners,
L.P. common units. The gain from the transaction is included in net gain on sale
of assets in the Consolidated Statements of Income.
3. COMMITMENTS AND CONTINGENCIES
Indonesia
The Company owns a 47.5 percent ownership interest in a power generating
plant in Sengkang, South Sulawesi, Indonesia. Under the terms of the project's
power purchase agreement, PLN purchases power from the Company in Indonesian
rupiah indexed to the U.S. dollar at the date of payment. Due to the devaluation
of the rupiah, the cost of power to PLN has increased. PLN has been unable to
pass this increase in cost on to its customers. PLN has requested financial aid
from the Minister of Finance to help ease the effects of the devaluation. PLN
has been paying the Company in rupiah indexed to the U.S. dollar at the rate in
effect prior to the rupiah devaluation. The difference between the current and
prior exchange rate has resulted in an outstanding balance due from PLN of $15
million at June 30, 1999. The Company continues to meet with PLN on a regular
basis to resolve the payment in arrears issue but has been unsuccessful to date.
The Company has made additional working capital loans to the project of
approximately $1 million. The total investment in the Sengkang project was
approximately $26 million at June 30, 1999. All project debt is non-recourse and
the Company has political risk insurance on the Sengkang project. The Company
believes the current economic difficulties in Indonesia will not have a material
adverse effect on the Company's financial position, results of operations, or
cash flows.
Brazil
The Company owns 100 percent of a 240 megawatt power generating plant in
Manaus, Brazil. Power from the plant is currently sold to a subsidiary of
Centrais Electricas do Norte do Brasil, S.A., ("Eletronorte"), denominated in
Brazilian real. In January 1999, the real was devalued. Under a provision in the
contract, the Company is entitled to adjust its forward tariff rate to eliminate
further losses associated with the devaluation. In April 1999, the contract with
Eletronorte was amended to extend the term from four to six years. The Company
believes the current economic difficulties in Brazil will not have a material
adverse effect on the Company's financial position, results of operations, or
cash flows.
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The contract for the Manaus power project provides for delay and
availability damages to be paid to Eletronorte if the specified construction
schedule is not met or the project does not meet certain availability standards.
Completion of the project was delayed beyond the originally scheduled completion
dates provided in the contract, and the availability standards were not met.
Such delays have resulted in claims by Eletronorte for damages. In the second
quarter of 1999, the Company reached a settlement with all parties which
resolved all claims for availability damages. The Company expects to reach a
settlement with Eletronorte on the delay damages in the third or fourth quarter
of 1999. Any settlement on the delay damages will not have a material adverse
effect on the Company's financial position, results of operations, or cash
flows.
Rates and Regulatory Matters
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it sought comments on a wide range of initiatives to change the manner in which
short-term (less than one year) transportation markets are regulated. Among
other things, the NOPR proposes the following: (i) removing the price cap for
the short-term capacity market; (ii) establishing procedures to make pipeline
and shipper-owned capacity comparable; (iii) auctioning all available short-term
pipeline capacity on a daily basis with the pipeline unable to set a reserve
price above variable costs; (iv) changing policies or pipeline penalties,
nomination procedures and services; (v) increasing pipeline reporting
requirements; (vi) permitting the negotiation of terms and conditions of
service; and (vii) potentially modifying the procedures for certificating new
pipeline construction. Also in July 1998, FERC issued a Notice of Inquiry
("NOI") seeking comments on FERC's policy for pricing long-term capacity. The
Company provided comments on the NOPR and NOI in April 1999. It is not known
when FERC will act on the NOPR and NOI.
In February 1997, TGP filed a settlement with FERC of all issues related to
the recovery of its GSR and other transition costs and related proceedings (the
"GSR Stipulation and Agreement"). In April 1997, FERC approved the settlement.
Under the terms of the GSR Stipulation and Agreement, TGP is entitled to collect
up to $770 million from its customers, $693 million through a demand surcharge
and $77 million through an interruptible transportation surcharge. As of June
30, 1999, the demand portion had been collected and $44 million of the
interruptible transportation portion had been collected. There is no time limit
for collection of the interruptible transportation surcharge portion. The terms
of the GSR Stipulation and Agreement also provide for a rate case moratorium
through November 2000 (subject to certain limited exceptions) and an escalating
rate cap, indexed to inflation, through October 2005, for certain of TGP's
customers. In accordance with the terms of the GSR Stipulation and Agreement,
TGP filed a GSR Reconciliation Report with FERC in March 1999, and in June 1999,
FERC accepted the report as in compliance with the GSR Stipulation and
Agreement. TGP will refund $14 million to its firm customers in the third
quarter of 1999, which represents the amount collected in excess of the $693
million recoverable through the demand surcharge. TGP will also be required to
refund to firm customers amounts collected in excess of each firm customer's
share of the final transition costs based on the final GSR Reconciliation
Report, which will be filed in March 2001. Any future refund is not expected to
have a material adverse effect on the Company's financial position, results of
operations, or cash flows.
In December 1994, TGP filed for a general rate increase with FERC and in
October 1996, FERC approved a settlement resolving that proceeding. The
settlement included a structural rate design change that results in a larger
portion of TGP's transportation revenues being dependent upon throughput. One
party, a competitor of TGP, filed a Petition for Review of the FERC orders with
the Court of Appeals. The Court of Appeals remanded the case to FERC to respond
to the competitor's argument that TGP's cost allocation methodology deterred the
development of market centers (centralized locations where buyers and sellers
can physically exchange gas). At FERC's request, comments were filed in January
1999. This matter is still pending before FERC.
All cost of service issues related to TGP's 1991 general rate proceeding
were resolved pursuant to a settlement agreement approved by FERC in an order
which now has become final. However, cost allocation and rate design issues
remained unresolved. In July 1996, following an ALJ's decision on these cost and
design issues, FERC ruled on certain issues but remanded to the ALJ the issue of
the proper allocation of TGP's New England lateral costs. In July 1997, FERC
issued an order denying rehearing of its July 1996 order. In
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February 1999, petitions for review of the July 1996 and July 1997 FERC orders
were denied by the Court of Appeals. In the remand proceeding, the ALJ issued
his decision on the proper allocation of the New England lateral costs in
December 1997. That decision adopts a methodology that economically approximates
the one currently used by TGP. In October 1998, FERC issued an order affirming
the ALJ's decision and, in April 1999, FERC denied requests for rehearing of the
October 1998 order. In April 1999, TGP filed with FERC revised rates to be
effective May 1, 1999. In addition, TGP will refund approximately $1 million to
certain of its customers in the third quarter of 1999. Upon payment of the
refunds, the proceedings will be resolved.
In April 1999, FERC approved a settlement which resolved all outstanding
FERC proceedings relating to the cashout reports that TGP had filed for the
period September 1993 through August 1998. The settlement also established a new
cashout mechanism to account for customer imbalances. The new cashout mechanism
was implemented in the second quarter of 1999, retroactive to September 1998.
Substantially all of the revenues of TGP are generated under long-term gas
transmission contracts. Contracts representing approximately 70 percent of TGP's
firm transportation capacity will expire by November 2000. Although TGP cannot
predict how much capacity will be resubscribed, a majority of the expiring
contracts cover service to northeastern markets, where there is currently little
excess capacity. Several projects, however, have been proposed to deliver
incremental volumes to these markets. Although TGP is actively pursuing the
renegotiation, extension and/or replacement of these contracts, there can be no
assurance as to whether TGP will be able to extend or replace these contracts
(or a substantial portion thereof) or that the terms of any renegotiated
contracts will be as favorable to TGP as the existing contracts.
In a November 1997 order, FERC reversed its previous decision and found
that EPNG's Chaco Station should be functionalized as a gathering, not a
transmission, facility and should be transferred to EPFS. In accordance with
the FERC orders, the Chaco Station was transferred to EPFS in April 1998.
EPNG and two other parties filed petitions for review with the Court of
Appeals. EPNG and others contested FERC's functionalization ruling and other
parties contested FERC's determination of the impact of the functionalization
ruling on the treatment of the Chaco Station costs in the rate settlement.
The matter has been briefed and will be argued in September 1999.
As an interstate pipeline, TGP is subject to FERC audits of its books and
records. As part of an industry-wide initiative, TGP's property retirements are
currently under review by the FERC audit staff.
As the aforementioned rate and regulatory matters are fully and
unconditionally resolved, the Company may either recognize an additional refund
obligation or a non-cash benefit to finalize previously estimated liabilities.
Management believes the ultimate resolution of these matters, which are in
various stages of finalization, will not have a material adverse effect on the
Company's financial position, results of operations, or cash flows.
Legal Proceedings
In February 1998, the United States and the State of Texas filed in a
United States District Court a Comprehensive Environmental Response,
Compensation and Liability Act cost recovery action, United States v. Atlantic
Richfield Co., et al., against fourteen companies including the following
affiliates of EPEC: TGP, EPTPC, EPEC Corporation, EPEC Polymers, Inc. and the
dissolved Petro-Tex Chemical Corporation, relating to the Sikes Disposal Pits
Superfund Site ("Sikes") located in Harris County, Texas. Sikes was an
unpermitted waste disposal site during the 1960s that accepted waste hauled from
numerous Houston Ship Channel industries. The suit alleges that the former
Tenneco Chemicals, Inc. and Petro-Tex Chemical Corporation arranged for disposal
of hazardous substances at Sikes. TGP, EPTPC, EPEC Corporation and EPEC
Polymers, Inc. are alleged to be derivatively liable as successors or as parent
corporations. The suit claims that the United States and the State of Texas have
expended over $125 million in remediating the site, and seeks to recover that
amount plus interest. Other companies named as defendants include Atlantic
Richfield Company, Crown Central Petroleum Corporation, Occidental Chemical
Corporation, Exxon Corporation, Goodyear Tire & Rubber Company, Rohm & Haas
Company, Shell Oil Company and Vacuum Tanks, Inc. These defendants have filed
their answers and third-party complaints
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seeking contribution from twelve other entities believed to be PRPs at Sikes.
Although factual investigation relating to Sikes is in very preliminary stages,
the Company believes that the amount of material, if any, disposed at Sikes from
the Tenneco Chemicals, Inc. or Petro-Tex Chemical Corporation facilities was
small, possibly de minimis. However, the government plaintiffs have alleged that
the defendants are each jointly and severally liable for the entire remediation
costs and have also sought a declaration of liability for future response costs
such as groundwater monitoring. While the outcome of this matter cannot be
predicted with certainty, management does not expect this matter to have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
TGP is a party in proceedings involving federal and state authorities
regarding the past use by TGP of a lubricant containing PCBs in its starting air
systems. TGP has executed a consent order with the EPA governing the remediation
of certain of its compressor stations and is working with the EPA and the
relevant states regarding those remediation activities. TGP is also working with
the Pennsylvania and New York environmental agencies regarding remediation and
post-remediation activities at the Pennsylvania and New York stations.
Management believes that the ultimate resolution of these matters will not have
a material adverse effect on the Company's financial position, results of
operations, or cash flows.
In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court, Commonwealth of Kentucky, Natural Resources and
Environmental Protection Cabinet v. Tennessee Gas Pipeline Company, alleging
that TGP discharged pollutants into the waters of the state without a permit and
disposed of PCBs without a permit. The agency sought an injunction against
future discharges, sought an order to remediate or remove PCBs, and sought a
civil penalty. TGP has entered into agreed orders with the agency to resolve
many of the issues raised in the original allegations, has received water
discharge permits for its Kentucky compressor stations from the agency, and
continues to work to resolve the remaining issues. The relevant Kentucky
compressor stations are scheduled to be characterized and remediated under the
consent order with the EPA. Management believes that the resolution of this
issue will not have a material adverse effect on the Company's financial
position, results of operations, or cash flows.
A number of subsidiaries of EPEC, including wholly and partially owned
subsidiaries of the Company, have been named defendants in actions brought by
Jack Grynberg on behalf of the U.S. Government under the false claims act.
Generally, the complaints allege an industry-wide conspiracy to underreport the
heating value as well as the volumes of the natural gas produced from federal
and Indian lands, thereby depriving the U.S. Government of royalties. In April
1999, the U.S. Government filed a notice that it would not intervene in these
actions. Grynberg has petitioned for consolidation of pre-trial matters with the
Multidistrict Litigation Panel, which will not consider this matter until
September 1999. The Company believes the complaint to be without merit.
Management believes that the ultimate resolution of this issue will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
The Company is a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of business.
While the outcome of such lawsuits or other proceedings against the Company
cannot be predicted with certainty, management currently does not expect these
matters to have a material adverse effect on the Company's financial position,
results of operations, or cash flows.
Environmental
The Company is subject to extensive federal, state, and local laws and
regulations governing environmental quality and pollution control. These laws
and regulations require the Company to remove or remedy the effect on the
environment of the disposal or release of specified substances at current and
former operating sites. As of June 30, 1999, the Company had reserves of
approximately $141 million for expected environmental costs.
In addition, the Company estimates that its subsidiaries will make capital
expenditures for environmental matters of approximately $6 million for the
remainder of 1999. These expenditures primarily relate to compliance with air
regulations and, to a lesser extent, control of water discharges. The Company
expects to incur expenditures of approximately $96 million in the aggregate for
the years 2000 through 2007.
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Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances of concern, including
substances on the EPA List of Hazardous Substances, at compressor stations and
other facilities operated by both its interstate and intrastate natural gas
pipeline systems. While conducting this project, TGP has been in frequent
contact with federal and state regulatory agencies, both through informal
negotiation and formal entry of consent orders, to assure that its efforts meet
regulatory requirements.
In May 1995, following negotiations with its customers, TGP filed with FERC
a Stipulation and Agreement (the "Environmental Stipulation") that establishes a
mechanism for recovering a substantial portion of the environmental costs
identified in the internal project. The Environmental Stipulation was effective
July 1, 1995. As of June 30, 1999, all amounts have been collected under the
Environmental Stipulation. Refunds may be required to the extent actual eligible
expenditures are less than estimated eligible expenditures used to determine
amounts to be collected under the Environmental Stipulation.
The Company and certain of its subsidiaries have been designated, have
received notice that they could be designated, or have been asked for
information to determine whether they could be designated as a PRP with respect
to 11 sites under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought
to resolve its liability as a PRP with respect to these Superfund sites through
indemnification by third parties and/or settlements which provide for payment of
the Company's allocable share of remediation costs. Since the clean-up costs are
estimates and are subject to revision as more information becomes available
about the extent of remediation required, and because in some cases the Company
has asserted a defense to any liability, the Company's estimate of its share of
remediation costs could change. Moreover, liability under the federal Superfund
statute is joint and several, meaning that the Company could be required to pay
in excess of its pro rata share of remediation costs. The Company's
understanding of the financial strength of other PRPs has been considered, where
appropriate, in its determination of its estimated liability as described
herein. The Company presently believes that the costs associated with the
current status of such other entities as PRPs at the Superfund sites referenced
above will not have a material adverse effect on the Company's financial
position, results of operations, or cash flows.
The Company has initiated proceedings against its historic liability
insurers seeking payment or reimbursement of costs and liabilities associated
with environmental matters. In these proceedings, the Company contends that
certain environmental costs and liabilities associated with various entities or
sites, including costs associated with former operating sites, must be paid or
reimbursed by certain of its historic insurers. The proceedings are in the
discovery stage, and it is not yet possible to predict the outcome.
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
The Company may incur significant costs and liabilities in order to comply with
existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. As
such information becomes available, or other relevant developments occur,
related accrual amounts will be adjusted accordingly. While there are still
uncertainties relating to the ultimate costs which may be incurred, based upon
the Company's evaluation and experience to date, the Company believes the
recorded reserves are adequate.
For a further discussion of other environmental matters, see Legal
Proceedings above.
Other than the items discussed above, management is not aware of any other
commitments or contingent liabilities which would have a material adverse effect
on the Company's financial condition, results of operations, or cash flows.
9
<PAGE> 12
4. SEGMENT INFORMATION
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE QUARTER ENDED JUNE 30, 1999
---------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO
GAS FIELD ENERGY ENERGY
PIPELINE SERVICES MARKETING INTERNATIONAL TOTAL
--------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Revenues from external customers.... $ 182 $ 84 $726 $ 12 $1,004
Intersegment revenue................ 7 16 4 -- 27
Operating income (loss)............. 110 14 6 (7) 123
EBIT................................ 113 36 7 16 172
Segment assets...................... 4,919 1,062 618 1,193 7,792
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE QUARTER ENDED JUNE 30, 1998
---------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO
GAS FIELD ENERGY ENERGY
PIPELINE SERVICES MARKETING INTERNATIONAL TOTAL
--------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Revenues from external customers.... $ 168 $ 49 $938 $ 16 $1,171
Intersegment revenue................ 10 15 5 -- 30
Operating income (loss)............. 65 14 (4) (6) 69
EBIT................................ 72 17 -- 9 98
Segment assets...................... 4,943 958 703 752 7,356
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE SIX MONTHS ENDED JUNE 30, 1999
---------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO
GAS FIELD ENERGY ENERGY
PIPELINE SERVICES MARKETING INTERNATIONAL TOTAL
--------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Revenues from external customers.... $ 383 $ 145 $1,463 $ 29 $2,020
Intersegment revenues............... 14 33 6 -- 53
Operating income (loss)............. 213 27 15 (23) 232
EBIT................................ 226 53 17 19 315
Segment assets...................... 4,919 1,062 618 1,193 7,792
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE SIX MONTHS ENDED JUNE 30, 1998
---------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO
GAS FIELD ENERGY ENERGY
PIPELINE SERVICES MARKETING INTERNATIONAL TOTAL
--------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Revenues from external customers.... $ 371 $ 108 $2,165 $ 28 $2,672
Intersegment revenues............... 19 24 9 -- 52
Operating income (loss)............. 159 34 (4) (13) 176
EBIT................................ 170 41 -- 11 222
Segment assets...................... 4,943 958 703 752 7,356
</TABLE>
10
<PAGE> 13
The reconciliations of EBIT to income before income taxes and cumulative
effect of accounting change are presented below:
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
----------- -----------
1999 1998 1999 1998
---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Total EBIT for segments.................................. $172 $ 98 $315 $222
Corporate expenses, net.................................. (4) (3) (9) (3)
Non-affiliated interest and debt expense................. (37) (30) (73) (62)
Affiliated interest expense, net......................... -- (10) (4) (16)
---- ---- ---- ----
Income before income taxes and cumulative effect of
accounting change...................................... $131 $ 55 $229 $141
==== ==== ==== ====
</TABLE>
5. DEBT AND OTHER CREDIT FACILITIES
The average interest rate of short-term borrowings was 5.4% and 5.8% at
June 30, 1999, and December 31, 1998, respectively. The Company had short-term
borrowings, including current maturities of long-term debt, at June 30, 1999,
and December 31, 1998, as follows:
<TABLE>
<CAPTION>
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Commercial paper............................................ $111 $190
Current maturities of other long-term debt.................. 4 4
---- ----
$115 $194
==== ====
</TABLE>
In July 1999, EPEC issued $600 million aggregate principal amount of 6.625%
Senior Notes due 2001 and $100 million aggregate principal amount of floating
rate Senior Notes due 2001 with an interest rate equal to LIBOR plus .65%.
Proceeds of approximately $111 million were advanced to the Company and were
used to repay the Company's outstanding commercial paper.
6. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment at June 30, 1999, and December 31, 1998,
consisted of the following:
<TABLE>
<CAPTION>
1999 1998
------ ------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost
Tennessee Gas Pipeline.................................... 2,499 2,438
El Paso Field Services.................................... 1,124 1,117
El Paso Energy Marketing.................................. 15 15
El Paso Energy International.............................. 176 162
Corporate and Other....................................... 76 73
------ ------
3,890 3,805
Less accumulated depreciation and depletion................. 664 577
------ ------
3,226 3,228
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,388 2,400
------ ------
Total property, plant, and equipment, net................... $5,614 $5,628
====== ======
</TABLE>
Current FERC policy does not permit the Company to recover amounts in
excess of original cost allocated in purchase accounting to its regulated
operations through rates.
11
<PAGE> 14
7. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for Derivative Instruments and Hedging Activities
In June 1998, Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities, was issued by the
Financial Accounting Standards Board to establish accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. This pronouncement
requires that an entity classify all derivatives as either assets or liabilities
in the statement of financial position and measure those instruments at fair
value. If certain conditions are met, a derivative may be specifically
designated as (i) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (ii) a hedge
of the exposure to variable cash flows of a forecasted transaction, or (iii) a
hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an
available-for-sale security or a foreign-currency-denominated forecasted
transaction. The accounting for the changes in the fair value of a derivative
depends on the intended use of the derivative and the resulting designation. The
standard was amended by Statement of Financial Accounting Standards No. 137
issued in June 1999. The amendment defers the effective date to fiscal years
beginning after June 15, 2000. The Company is currently evaluating the effects
of this pronouncement.
12
<PAGE> 15
ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information contained in Item 2 updates, and should be read in
conjunction with, information set forth in Part II, Items 7, 7A, and 8, in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998, in
addition to the interim condensed consolidated financial statements and
accompanying notes presented in Item 1 of this Quarterly Report on Form 10-Q.
GENERAL
On December 31, 1998, EPEC completed a series of steps to effect a tax-free
internal reorganization in which certain energy marketing operations of EPEM,
certain field services operations of EPFS, and certain international operations
of EPEI were transferred to EPTPC. The transactions were treated as a transfer
of ownership between entities under common control and were accounted for in a
manner similar to a pooling of interests. Accordingly, the information for the
quarter and six months ended June 30, 1998, presented in the Management's
Discussion and Analysis of Financial Condition and Results of Operations has
been restated as though the transactions occurred on January 1, 1998.
RESULTS OF OPERATIONS
SEGMENT RESULTS
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
------------ ------------
1999 1998 1999 1998
---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Tennessee Gas Pipeline................................. $113 $72 $226 $170
El Paso Field Services................................. 36 17 53 41
El Paso Energy Marketing............................... 7 -- 17 --
El Paso Energy International........................... 16 9 19 11
Corporate expenses, net................................ (4) (3) (9) (3)
---- --- ---- ----
Total EBIT................................... $168 $95 $306 $219
==== === ==== ====
</TABLE>
TENNESSEE GAS PIPELINE
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
-------------- --------------
1999 1998 1999 1998
----- ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Operating revenues........................................ $ 189 $ 178 $ 397 $ 390
Operating expenses........................................ (79) (113) (184) (231)
Other -- net.............................................. 3 7 13 11
----- ----- ----- -----
EBIT.................................................... $ 113 $ 72 $ 226 $ 170
===== ===== ===== =====
</TABLE>
Second Quarter 1999 Compared to Second Quarter 1998
Operating revenues for the quarter ended June 30, 1999, were $11 million
higher than for the same period of 1998 primarily due to the favorable
resolution of a regulatory issue in the quarter and the impact of a downward
revision in the amount of recoverable interest on GSR costs in 1998. The
increase was partially offset by a favorable customer settlement in the second
quarter of 1998.
13
<PAGE> 16
Operating expenses for the quarter ended June 30, 1999, were $34 million
lower than for the same period of 1998. This decrease was primarily due to the
favorable resolution of an outstanding FERC proceeding in the second quarter of
1999.
Other -- net for the quarter ended June 30, 1999, was $4 million lower than
for the same period of 1998. The decrease was primarily due to a gain on the
sale of assets in the second quarter of 1998 and lower earnings from equity
investments in 1999.
Six Months Ended 1999 Compared to Six Months Ended 1998
Operating revenues for the six months ended June 30, 1999, were $7 million
higher than for the same period of 1998 primarily due to the favorable
resolution of regulatory issues and the impact of a downward revision in the
amount of recoverable interest on GSR costs in the second quarter of 1998. The
increase was partially offset by a favorable customer settlement in the second
quarter of 1998, and lower miscellaneous operating revenue.
Operating expenses for the six months ended June 30, 1999, were $47 million
lower than for the same period of 1998. The decrease was primarily due to the
favorable resolution of certain regulatory issues. The decrease was also
attributable to lower system fuel usage associated with operating efficiencies
achieved as a result of lower throughput levels.
Other -- net for the six months ended June 30, 1999, was $2 million higher
than for the same period of 1998. The increase was primarily due to the
favorable resolution of regulatory and contractual issues in the first quarter
of 1999, partially offset by a gain on the sale of assets in the second quarter
of 1998.
EL PASO FIELD SERVICES
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
------------ ------------
1999 1998 1999 1998
---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Gathering and treating margin......................... $ 36 $ 38 $ 76 $ 77
Processing margin..................................... 11 12 20 26
Other margin.......................................... 4 -- 4 2
---- ---- ---- ----
Total gross margin.......................... 51 50 100 105
Operating expenses.................................... (37) (36) (73) (71)
Other -- net.......................................... 22 3 26 7
---- ---- ---- ----
EBIT........................................ $ 36 $ 17 $ 53 $ 41
==== ==== ==== ====
</TABLE>
Second Quarter 1999 Compared to Second Quarter 1998
Total gross margin for the quarter ended June 30, 1999, was $1 million
higher than for the same period of 1998. The increase was primarily attributable
to the acquisition of EnCap in the first quarter of 1999. This increase was
partially offset by lower realized liquids prices during 1999 compared to the
same period of 1998. Also offsetting the increase in total gross margin, were
lower gathering and treating volumes, which were largely attributable to the
sale of the natural gas gathering and treating assets in the Anadarko Basin in
September 1998. The impact of the global compression project served to
substantially offset the decrease in gathering and treating volumes.
Operating expenses for the quarter ended June 30, 1999, were $1 million
higher than the same period of 1998 primarily due to an increase in amortization
and depreciation expense attributable to acquisitions.
Other -- net for the quarter ended June 30, 1999, was $19 million higher
than for the same period of 1998 primarily due to net gains on the sale of
assets in the second quarter of 1999.
14
<PAGE> 17
Six Months Ended 1999 Compared to Six Months Ended 1998
Total gross margin for the six months ended June 30, 1999, was $5 million
lower than for the same period of 1998. The decrease resulted primarily from
lower realized liquids prices during 1999 compared to the same period of 1998.
The contribution from EnCap partially offset the decrease in total gross margin.
The slight decrease in the gathering and treating margin resulted from lower
gathering and treating volumes largely attributable to the sale of the natural
gas gathering and treating assets in the Anadarko Basin in September 1998. The
impact of the global compression project served to substantially offset the
decrease in gathering and treating volumes.
Operating expenses for the six months ended June 30, 1999, were $2 million
higher than for the same period of 1998 primarily due to an increase in
amortization and depreciation expense attributable to acquisitions.
Other -- net for the six months ended June 30, 1999, was $19 million higher
than for the same period of 1998 primarily due to net gains on the sale of
assets in the second quarter of 1999.
EL PASO ENERGY MARKETING
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
------------ ------------
1999 1998 1999 1998
---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Natural gas margin..................................... $13 $(8) $ 30 $ (2)
Power margin........................................... -- 12 -- 19
--- --- ---- ----
Total gross margin........................... 13 4 30 17
Operating expenses..................................... (7) (8) (15) (21)
Other -- net........................................... 1 4 2 4
--- --- ---- ----
EBIT......................................... $ 7 $-- $ 17 $ --
=== === ==== ====
</TABLE>
Second Quarter 1999 Compared to Second Quarter 1998
Total gross margin for the quarter ended June 30, 1999, was $9 million
higher than for the same period of 1998. The increase in the natural gas margin
was primarily due to the income recognition from long-term natural gas
transactions closed during the quarter. The decrease in the power margin was due
to the January 1999 transfer of EPEM's power activities to El Paso Power
Services Company, a wholly owned direct subsidiary of EPEC.
Operating expenses for the quarter ended June 30, 1999, were $1 million
lower than for the same period of 1998 primarily due to a decrease in general
and administrative expenses.
Other -- net for the quarter ended June 30, 1999, was $3 million lower than
for the same period of 1998 primarily due to a gain on the sale of assets sold
in the second quarter of 1998.
Six Months Ended 1999 Compared to Six Months Ended 1998
Total gross margin for the six months ended June 30, 1999, was $13 million
higher than for the same period of 1998. The increase in the natural gas margin
was primarily due to the income recognition from long-term natural gas
transactions closed during the year. The decrease in the power margin was due to
the January 1999 transfer of EPEM's power activities to El Paso Power Services
Company.
Operating expenses for the six months ended June 30, 1999, were $6 million
lower than for the same period of 1998. The decrease was primarily due to lower
general and administrative expenses, including those associated with power
activities transferred to El Paso Power Services Company.
Other -- net for the six months ended June 30, 1999, was $2 million lower
than for the same period of 1998 primarily due to a gain on the sale of assets
sold in the second quarter of 1998.
15
<PAGE> 18
EL PASO ENERGY INTERNATIONAL
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
------------ ------------
1999 1998 1999 1998
---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Operating revenues.................................... $ 12 $ 16 $ 29 $ 28
Operating expenses.................................... (19) (22) (52) (41)
Other -- net.......................................... 23 15 42 24
---- ---- ---- ----
EBIT................................................ $ 16 $ 9 $ 19 $ 11
==== ==== ==== ====
</TABLE>
Second Quarter 1999 Compared to Second Quarter 1998
Operating revenues for the quarter ended June 30, 1999, were $4 million
lower than for the same period of 1998 primarily due to a decrease in revenues
from the Manaus Power project.
Operating expenses for the quarter ended June 30, 1999, were $3 million
lower than for the same period of 1998 primarily due to a decrease in project
development costs. The decrease was partially offset by higher operating
expenses.
Other -- net for the quarter ended June 30, 1999, was $8 million higher
than for the same period of 1998 due to higher earnings from equity investments.
The increase was primarily attributable to the earnings from EAPRC and from the
Samalayuca Power project.
Six Months Ended 1999 Compared to Six Months Ended 1998
Operating revenues for the six months ended June 30, 1999, were $1 million
higher than for the same period of 1998 primarily due to the consolidation for
financial reporting purposes of the Manaus Power project in May 1998. The
increase was partially offset by lower Manaus revenues in the second quarter of
1999.
Operating expenses for the six months ended June 30, 1999, were $11 million
higher than for the same period of 1998. The increase was primarily due to
higher operating expenses attributable to the consolidation of the Manaus Power
project.
Other -- net for the six months ended June 30, 1999, was $18 million higher
than for the same period of 1998. The increase was due to higher earnings from
equity investments primarily attributable to the Samalayuca Power project and
EAPRC, as well as higher interest income. The increase was partially offset by
the recognition of certain gains from project-related activities in the second
quarter of 1998.
CORPORATE EXPENSES, NET
Net corporate expenses for the quarter and six months ended June 30, 1999,
were higher than for the same period of 1998. The increase was primarily due to
the recognition of income from investments in 1998.
NON-AFFILIATED INTEREST AND DEBT EXPENSE
Non-affiliated interest and debt expense for the quarter and six months
ended June 30, 1999, was higher than for the same period of 1998, primarily due
to increased borrowings related to acquisitions, capital expenditures, and other
investing expenditures.
AFFILIATED INTEREST EXPENSE, NET
Affiliated interest expense, net for the quarter and six months ended June
30, 1999, was lower than for the same period of 1998, primarily due to the
reduction in the affiliated average debt balance.
16
<PAGE> 19
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $95 million higher for the
six months ended June 30, 1999, compared to the same period of 1998. The
increase was primarily due to higher income, partially offset by lower GSR
collections and broker margin requirements in 1999 and net income tax refunds
received in 1998.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was $224 million for the six months
ended June 30, 1999. Expenditures related to joint ventures and equity
investments were primarily attributable to the El Paso Energy International
segment. Other investment activity included expenditures for expansion and
construction projects, as well as the acquisition of EnCap. Internally generated
funds, advances from EPEC, supplemented by other financing activities, were used
to fund these expenditures.
Future funding for capital expenditures, acquisitions, and other investing
expenditures is expected to be provided by internally generated funds, available
capacity under existing credit facilities, and/or contributions from EPEC.
CASH FROM FINANCING ACTIVITIES
Net cash used in financing activities was $4 million for the six months
ended June 30, 1999. Long-term borrowings, supplemented by internally generated
funds, were used to reduce short-term borrowings, pay dividends, fund capital
and equity investments, and for other corporate purposes.
Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
available capacity under existing credit facilities, and/or contributions from
EPEC.
In July 1999, EPEC issued $600 million aggregate principal amount of 6.625%
Senior Notes due 2001 and $100 million aggregate principal amount of floating
rate Senior Notes due 2001 with an interest rate equal to LIBOR plus .65%.
Proceeds of approximately $111 million were advanced to the Company and used to
repay the Company's outstanding commercial paper.
COMMITMENTS AND CONTINGENCIES
See Note 3, which is incorporated herein by reference.
OTHER
The Company has agreed to acquire ownership interests in the Newark Bay
Cogeneration Facility and East Coast Power for approximately $280 million. The
Newark Bay facility is a 137 megawatt natural gas-fired cogeneration plant
located in New Jersey which sells power to a large utility and steam to various
local customers. East Coast Power has three natural gas-fired plants located in
New Jersey with a combined capacity of 1,037 megawatts and has long-term power
purchase agreements with three utilities. The Company anticipates closing these
transactions in the third quarter of 1999.
YEAR 2000
EPEC has established an executive steering committee and a project team to
coordinate the phases of its Year 2000 project to assure that the Company's key
automated systems, equipment, and related processes will remain functional
through the Year 2000. Those phases are: (i) awareness; (ii) assessment; (iii)
remediation; (iv) testing; (v) implementation of the necessary modifications and
(vi) contingency planning. The Company has participated in EPEC's Year 2000
project as described below.
17
<PAGE> 20
In recognition of the importance of Year 2000 issues and their potential
impact on EPEC, the initial phase of the Year 2000 project involved the
establishment of a company-wide awareness program. The awareness program is
directed by the executive steering committee and project team and includes
participation of senior management in each core business area. The awareness
phase is substantially completed, although EPEC will continually update
awareness efforts for the duration of the Year 2000 project.
The Company's assessment phase consists of conducting a company-wide
inventory of its key automated systems and related processes, analyzing and
assigning levels of criticality to those systems and processes, identifying and
prioritizing resource requirements, developing validation strategies and testing
plans, and evaluating business partner relationships. The portion of the
assessment phase related to internally developed computer applications, hardware
and equipment, third-party-developed software, and embedded chips is
substantially complete. The assessment phase of the project, among other things,
involves efforts to obtain representations and assurances from third parties,
including third party vendors, that their hardware and equipment products,
embedded chip systems, and software products being used by or impacting the
Company are or will be modified to be Year 2000 compliant. Increasingly, the
responses from such third parties are generally encouraging. Nonetheless, many
of these responses lack the substantive detail to allow the Company to make a
meaningful evaluation of such third-parties' Year 2000 readiness. Furthermore,
in some circumstances, third parties are refusing to provide any response beyond
those contained in their publicly-disseminated information. As a result, the
overall evaluation of the Company's business partners' Year 2000 readiness
remains inconclusive. Accordingly, the Company cannot predict the potential
consequences if these or other third parties or their products are not Year 2000
compliant. The Company continues to evaluate the exposure associated with such
business partner relationships, and will use the contingency planning process to
attempt to mitigate the uncertainty concerning third-party readiness.
The remediation phase involves converting, modifying, replacing or
eliminating key automated systems identified in the assessment phase. The
testing phase involves the validation of the identified key automated systems.
The Company is utilizing test tools and written test procedures to document and
validate, as necessary, its unit, system, integration and acceptance testing.
The implementation phase involves placing the converted or replaced key
automated systems into operation. Except as noted in the following paragraph,
the Company is substantially complete with its remediation, testing and
implementation phases for domestic systems.
One system that is important to the Company's efficient management of its
core-business process, but which was not substantially complete with respect to
Year 2000 issues as of June 30, 1999, is the nominations, scheduling and volume
accounting applications utilized by TGP. In 1998, FERC mandated that all
regulated pipelines were to implement a dual communication system involving Gas
Industry Standards Board ("GISB") approved Electronic Data Interchange ("EDI")
file transfers and standardized Internet web sites by June 2000, so shippers
would have the option of choosing the communication mode (EDI or the Internet
web site) that best fits their business needs. TGP had planned to implement a
new system in October 1999 that would allow for both modes of communication. In
the second quarter of 1999, TGP determined that a delay in the implementation of
the new system would be necessary to allow sufficient time to ensure that the
current nominations system is Year 2000 compliant. A request was filed with FERC
in June 1999, to delay compliance with certain GISB requirements. In July 1999,
FERC granted TGP an extension until April 2000. The Company expects TGP to
substantially complete remediation, testing and implementation of necessary Year
2000 revisions to its existing nominations system during the third quarter of
1999.
The Company had previously identified the contingency planning phase as a
subset of the implementation phase, but has now established the process as its
own phase of the overall Year 2000 program. The contingency planning phase
consists of developing a risk profile of the Company's critical business
processes and then providing for actions the Company will pursue to keep such
processes operational in the event of Year 2000 disruptions. The focus of such
contingency planning is on prompt response to any Year 2000 events, and a plan
for subsequent resumption of normal operations. The plan is expected to assess
the risk of a significant failure to critical processes performed by the
Company, and to address the mitigation of those risks. The plan will also
consider any significant failures related to the most reasonably likely worst
case scenario, discussed below, as they may occur. In addition, the plan is
expected to factor in the severity and duration of
18
<PAGE> 21
the impact of a significant failure. The Company has developed contingency plans
for each business unit and significant business process. By June 30, 1999, the
Company had conducted desk-top testing of its contingency plans and anticipates
conducting drills and mock outages over the next two calendar quarters,
including some testing with certain customers and other significant third
parties. The Year 2000 contingency plans will continue to be tested, modified
and adjusted throughout the year as additional information becomes available.
The goal of the Year 2000 project is to ensure that all of the critical
systems and processes which are under the Company's direct control remain
functional. Certain systems and processes may be interrelated with or dependent
upon systems outside the Company's control. However, systems within the
Company's control may also have unpredicted problems. Accordingly, there can be
no assurance that significant disruptions will be avoided. The Company's present
analysis of its most reasonably likely worst case scenario for Year 2000
disruptions includes sporadic Year 2000 failures in the telecommunications and
electricity industries, as well as interruptions from suppliers that might cause
disruptions in the Company's operations, thus causing temporary financial losses
and an inability to deliver products and services to customers. Virtually all of
the natural gas transported through the Company's interstate pipelines is owned
by third parties. Accordingly, failures of natural gas producers to be ready for
the Year 2000 could significantly disrupt the flow of product to the Company's
customers. In many cases, the producers have no direct contractual relationship
with the Company, and the Company relies on its customers to verify the Year
2000 readiness of the producers from whom they purchase natural gas. Since most
of the Company's revenues from the delivery of natural gas are based upon fees
paid by its customers for the reservation of capacity, and not based upon the
volume of actual deliveries, short-term disruptions in deliveries caused by
factors beyond the Company's control should not have a significant financial
impact on the Company, although it could cause operational problems for the
Company's customers. Longer-term disruptions, however, could materially impact
the Company's results of operations, financial condition, and cash flows.
While the Company owns or controls most of its domestic facilities and
projects, nearly all of the Company's international investments have been made
in conjunction with unrelated third parties. In many cases, the operators of
such international facilities are not under the sole or direct control of the
Company. As a consequence, the Year 2000 programs instituted at some of the
international facilities may be different from the Year 2000 program implemented
by the Company domestically, and the party responsible for the results of such
program may not be under the direct or indirect control of the Company. In
addition, the "non-controlled" programs may not provide the same degree of
communication, documentation and coordination as the Company achieves in its
domestic Year 2000 program. Moreover, the regulatory and legal environment in
which such international facilities operate makes analysis of possible
disruption and associated financial impact difficult. Many foreign countries
appear to be substantially behind the United States in addressing potential Year
2000 disruption of critical infrastructure and in developing a framework
governing the reporting requirements and relative liabilities of business
entities. Accordingly, the Year 2000 risks posed by international operations as
a whole are different than those presented domestically. As part of its Year
2000 effort, the Company is assessing the differences between the non-controlled
programs and its domestic Year 2000 project, and has formulated and instituted a
program for identifying such risks and preparing a response to such risks. While
the Company is monitoring or actively assisting in the Year 2000 programs of its
international ventures, and as a consequence, the Company has formed the belief
that most of the international facilities in which it has significant
investments are addressing Year 2000 issues in an adequate manner, it is
possible that some of them may experience significant Year 2000 disruption, and
that the aggregate effect of problems experienced at multiple international
locations may be material and adverse. The Company is incorporating this
possibility into the relevant contingency plans.
While the total cost of the Company's Year 2000 project continues to be
evaluated, the Company estimates that the costs remaining to be incurred in 1999
and 2000 associated with assessing, remediating and testing internally developed
computer applications, hardware and equipment, embedded chip systems, and
third-party-developed software will be between $6 million and $11 million. Of
these estimated costs, the Company expects between $3 million and $5 million to
be capitalized and the remainder to be expensed. As of June 30, 1999, the
Company has incurred expenses of approximately $7 million and has capitalized
costs of approximately $3 million. The Company has previously only traced
incremental expenses related to its
19
<PAGE> 22
Year 2000 project. This means that the costs of the Year 2000 project related to
salaried employees of the Company, including their direct salaries and benefits,
are not available, and have not been included in the estimated costs of the
project. Since the earlier phases of the project mostly involved work performed
by such salaried employees, the costs expended to date do not reflect the
percentage completion of the project. The Company anticipates that it will
expend a substantial amount of the remaining costs in the contingency planning
phase of the project, including the potential acquisition of back-up assets and
systems that may be deployed in the event primary systems fail to perform fully
according to expectations. It is possible the Company may need to reassess its
estimate of Year 2000 costs in the event the Company completes an acquisition
of, or makes a material investment in, substantial facilities or another
business entity.
Although the Company does not expect the costs of its Year 2000 project to
have a material adverse effect on its financial position, results of operations,
or cash flows, based on information available at this time the Company cannot
conclude that disruption caused by internal or external Year 2000 related
failures will not have such an effect. Specific factors which might affect the
success of the Company's Year 2000 efforts and the frequency or severity of a
Year 2000 disruption or the amount of expense include the failure of the Company
or its outside consultants to properly identify deficient systems, the failure
of the selected remedial action to adequately address the deficiencies, the
failure of the Company or its outside consultants to complete the remediation in
a timely manner (due to shortages of qualified labor or other factors), the
failure of other parties to joint ventures in which the Company is involved to
meet their obligations, both financial and operational, under the relevant joint
venture agreements to remediate assets used by the joint venture, unforeseen
expenses related to the remediation of existing systems or the transition to
replacement systems, the failure of third parties to become Year 2000 compliant
or to adequately notify the Company of potential noncompliance and the effects
of any significant disruption at international facilities in which the Company
has significant investments.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the
intention to comply fully with the Year 2000 Information and Readiness
Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law
October 19, 1998. All statements made herein shall be construed within the
confines of that Act. To the extent that any reader of the above Year 2000
Readiness Disclosure is other than an investor or potential investor in the
Company's -- or an affiliate's -- equity or debt securities, this disclosure is
made for the SOLE PURPOSE of communicating or disclosing information aimed at
correcting, helping to correct and/or avoiding Year 2000 failures.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Note 7, which is incorporated by reference herein.
20
<PAGE> 23
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.
This report contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. Where any such forward-looking
statement includes a statement of the assumptions or bases underlying such
forward-looking statement, the Company cautions that, while such assumptions or
bases are believed to be reasonable and are made in good faith, assumed facts or
bases almost always vary from the actual results, and the differences between
assumed facts or bases and actual results can be material, depending upon the
circumstances. Where, in any forward-looking statement, the Company or its
management expresses an expectation or belief as to future results, such
expectation or belief is expressed in good faith and is believed to have a
reasonable basis, but there can be no assurance that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions may
identify forward-looking statements.
Important factors that could cause actual results to differ materially from
those in the forward-looking statements herein include increasing competition
within the Company's industry, the timing and extent of changes in commodity
prices for natural gas and power, uncertainties associated with acquisitions and
joint ventures, potential environmental liabilities, potential contingent
liabilities and tax liabilities related to the Company's acquisitions, political
and economic risks associated with current and future operations in foreign
countries, conditions of the equity and other capital markets during the periods
covered by the forward-looking statements, and other risks, uncertainties and
factors, including the effect of the Year 2000 date change, discussed more
completely in the Company's other filings with the U.S. Securities and Exchange
Commission, including its Annual Report on Form 10-K for the year ended December
31, 1998.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in
conjunction with, information set forth in Part II, Item 7A in the Company's
Annual Report on Form 10-K for the year ended December 31, 1998, in addition to
the interim consolidated financial statements, accompanying notes and
Management's Discussion and Analysis of Financial Condition and Results of
Operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
There have been no material changes in market risks faced by the Company
from those reported in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998.
21
<PAGE> 24
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Financial Information, Note 3, which is incorporated herein by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
EPTPC held its annual meeting of stockholders on April 22, 1999. Proposals
presented for a stockholders vote included the election of one director by
holders of EPTPC's 8 1/4% Cumulative Preferred Stock Series A and the election
of five Directors by EPEC, the sole holder of EPTPC's Common Stock.
The one director nominated to be elected by the holder of EPTPC's 8 1/4%
Cumulative Preferred Stock Series A was elected with the following voting
results:
<TABLE>
<CAPTION>
FOR WITHHELD
--------- --------
<S> <C> <C>
Kenneth L. Smalley.......................................... 3,531,570 0
</TABLE>
Each of the five directors nominated to be elected by the common
stockholder were elected with the following voting results:
<TABLE>
<CAPTION>
FOR WITHHELD
----- --------
<S> <C> <C>
William A. Wise............................................. 1,971 0
H. Brent Austin............................................. 1,971 0
Joel Richards III........................................... 1,971 0
Britton White Jr............................................ 1,971 0
Jeffrey I. Beason........................................... 1,971 0
</TABLE>
There were no broker non-votes for the election of directors.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as a part of this report.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
27 -- Financial Data Schedule.
</TABLE>
22
<PAGE> 25
Undertaking
The undersigned hereby undertakes, pursuant to Regulation S-K, Item
601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of long-term debt of EPTPC and its consolidated subsidiaries not
filed herewith for the reason that the total amount of securities
authorized under any of such instruments does not exceed 10 percent of the
total consolidated assets of EPTPC and its consolidated subsidiaries.
b. Reports on Form 8-K
None.
23
<PAGE> 26
SIGNATURES
Pursuant to the requirements 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.
EL PASO TENNESSEE PIPELINE CO.
Date: August 12, 1999
/s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: August 12, 1999
/s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Vice President and Controller
(Chief Accounting Officer)
24
<PAGE> 27
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
27 -- Financial Data Schedule.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSOLIDATED
STATEMENTS OF INCOME AND CONSOLIDATED BALANCE SHEETS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<CASH> 24
<SECURITIES> 0
<RECEIVABLES> 636
<ALLOWANCES> 0<F1>
<INVENTORY> 21
<CURRENT-ASSETS> 979
<PP&E> 5,614
<DEPRECIATION> 0<F1>
<TOTAL-ASSETS> 8,008
<CURRENT-LIABILITIES> 2,078
<BONDS> 1,555
0
300
<COMMON> 0
<OTHER-SE> 2,000
<TOTAL-LIABILITY-AND-EQUITY> 8,008
<SALES> 0
<TOTAL-REVENUES> 2,021
<CGS> 0
<TOTAL-COSTS> 1,797
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 77
<INCOME-PRETAX> 229
<INCOME-TAX> 71
<INCOME-CONTINUING> 158
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (13)
<NET-INCOME> 145
<EPS-BASIC> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>Not separately identified in the Consolidated Financial Statements or
accompanying notes thereto.
</FN>
</TABLE>
