<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported):
July 6, 1999
SONAT INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
Delaware 1-7179 63-0647939
(State or other jurisdiction (Commission File Number) (IRS Employer Identification No.)
of incorporation)
AmSouth-Sonat Tower, Birmingham, Alabama 35203
(Address of principal executive offices) (Zip Code)
</TABLE>
(205) 325-3800
(Registrant's telephone number, including area code)
<PAGE> 2
Item 5. Other Events.
As previously reported, Sonat Inc. ("Sonat") and El Paso Energy Corporation
("El Paso Energy") have entered into the Second Amended and Restated Agreement
and Plan of Merger (the "Merger Agreement"), which provides for the merger of
Sonat into El Paso Energy (the "Merger"). Sonat is filing this report to
incorporate into its Registration Statements under the Securities Act of 1933
that incorporate this Form 8-K certain information concerning El Paso Energy and
the Merger. Accordingly, set forth on the following pages are (i) certain pro
forma financial information concerning the Merger and (ii) El Paso Energy's
Annual Report on Form 10-K for 1998 and Quarterly Report on Form 10-Q for the
quarter ended March 31, 1999.
2
<PAGE> 3
Pro forma financial information
FINANCIAL INFORMATION
On June 10, 1999, El Paso Energy stockholders and Sonat stockholders
approved the Merger Agreement. Presented below are unaudited pro forma condensed
combined financial statements reflecting the merger using the pooling of
interests method of accounting in accordance with United States generally
accepted accounting principles. Under this accounting method, El Paso Energy's
and Sonat's balance sheets and income statements are treated as if they had
always been combined for accounting and financial reporting purposes. This
information is included to give you a better understanding of what the combined
results of operations and financial position of El Paso Energy and Sonat may
have looked like had the merger occurred on an earlier date.
The pro forma information reflecting the merger assumes (1) each share of
Sonat common stock will be converted into one share of El Paso Energy common
stock and (2) El Paso Energy will issue a total of approximately 110 million
shares in the merger.
The unaudited pro forma condensed combined balance sheet as of March 31,
1999, assumes the merger had been completed on March 31, 1999. The unaudited pro
forma condensed combined income statements for the three months ended March 31,
1999, and three years ended December 31, 1998, assume the merger had been
completed on January 1, 1996, the beginning of the earliest period presented.
Accounting policy differences and intercompany balances between El Paso
Energy and Sonat have been determined to be immaterial and, accordingly, the
pro forma condensed combined financial statements have not been adjusted for
these differences. The unaudited pro forma condensed combined financial
statements are presented for illustrative purposes only and are not necessarily
indicative of the operating results or financial position that would have been
achieved had the merger of El Paso Energy and Sonat been consummated as of the
beginning of the periods presented, nor are they necessarily indicative of the
future operating results or financial position of El Paso Energy. The unaudited
pro forma condensed combined financial statements do not give effect to any
operating efficiencies or cost savings that may result from the integration of
El Paso Energy's and Sonat's operations.
These unaudited pro forma condensed combined financial statements should be
read in conjunction with the historical financial statements and related notes
of El Paso Energy and Sonat included in their respective Annual Reports on Form
10-K for the year ended December 31, 1998, and Quarterly Reports on Form 10-Q
for the three months ended March 31, 1999. The historical financial information
presented for Sonat includes certain reclassifications to conform to El Paso
Energy's presentation. These reclassifications have no impact on results of
operations or total stockholders' equity.
3
<PAGE> 4
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
AS OF MARCH 31, 1999
(IN MILLIONS)
ASSETS
<TABLE>
<CAPTION>
EL PASO SONAT COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Total current assets............................... $ 1,223 $ 639 $ -- $ 1,862
Property, plant and equipment, net................. 7,191 2,464 -- 9,655
Other.............................................. 2,052 863 -- 2,915
------- ------ ----- -------
Total assets............................. $10,466 $3,966 $ -- $14,432
======= ====== ===== =======
LIABILITIES & STOCKHOLDERS' EQUITY
Total current liabilities.......................... $ 1,935 $1,510 $ 133(a) $ 3,527
(51)(c)
------- ------ ----- -------
Long-term debt, less current maturities............ 3,082 1,098 -- 4,180
------- ------ ----- -------
Deferred income taxes.............................. 1,589 90 (22)(c) 1,657
------- ------ ----- -------
Other.............................................. 1,008 170 -- 1,178
------- ------ ----- -------
Company-obligated mandatorily redeemable
convertible preferred securities of El Paso
Energy Capital Trust I........................... 325 -- -- 325
------- ------ ----- -------
Minority interest.................................. 365 11 -- 376
------- ------ ----- -------
Stockholders' equity
Common stock..................................... 377 111 219(b) 707
Additional paid-in capital....................... 1,465 75 (279)(b) 1,261
Retained earnings................................ 494 968 (192)(a) 1,343
73(c)
Other............................................ (174) (67) 60(b) (122)
59(a)
------- ------ ----- -------
Total stockholders' equity............... 2,162 1,087 (60) 3,189
------- ------ ----- -------
Total liabilities and stockholders'
equity................................. $10,466 $3,966 $ -- $14,432
======= ====== ===== =======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Balance
Sheet.
4
<PAGE> 5
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
(a) Reflects estimated costs of $192 million associated with the merger of El
Paso Energy and Sonat. These costs consist of (1) $142 million of costs for
compensation related programs under which certain benefits of El Paso
Energy and Sonat personnel accelerate and vest as a result of the change in
control associated with the merger and (2) $50 million of transaction
costs, which include legal, accounting, and financial advisory services.
(b) Reflects the exchange of one share of El Paso Energy common stock for each
share of outstanding Sonat common stock, as provided in the merger
agreement and the cancellation of $60 million of Sonat treasury stock.
(c) Reflects the income tax consequences of the $192 million of costs
associated with the merger assuming an effective income tax rate of 38%.
5
<PAGE> 6
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31, 1999
(IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
<TABLE>
<CAPTION>
EL PASO SONAT COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................. $1,494 $ 774 $-- $2,268
------ ------ --- ------
Operating expenses
Cost of gas and other products................... 1,068 564 -- 1,632
Operation and maintenance........................ 183 77 -- 260
Depreciation, depletion and amortization......... 71 75 -- 146
Ceiling test charges............................. -- 352 -- 352
Other............................................ 27 12 -- 39
------ ------ --- ------
1,349 1,080 -- 2,429
------ ------ --- ------
Operating income (loss)............................ 145 (306) -- (161)
Interest and debt expense.......................... 73 35 -- 108
Other income, net.................................. (45) (15) -- (60)
------ ------ --- ------
Income (loss) before income taxes, minority
interest, and cumulative effect of accounting
change........................................... 117 (326) -- (209)
Income tax expense (benefit)....................... 40 (115) -- (75)
Minority interest.................................. 6 1 -- 7
------ ------ --- ------
Income (loss) before cumulative effect of
accounting change................................ 71 (212) -- (141)
Cumulative effect of accounting change, net of
income tax....................................... (13) -- -- (13)
------ ------ --- ------
Net income (loss).................................. $ 58 $ (212) $-- $ (154)
====== ====== === ======
Basic earnings per common share
Income (loss) before cumulative effect of
accounting change.............................. $ 0.62 $(0.62)
Cumulative effect of accounting change, net of
income tax..................................... (0.12) (0.06)
------ ------
Net income (loss)................................ $ 0.50 $(0.68)
====== ======
Diluted earnings per common share
Income (loss) before cumulative effect of
accounting change.............................. $ 0.58 $(0.62)(a)
Cumulative effect of accounting change, net of
income tax..................................... (0.10) (0.06)(a)
------ ------
Net income (loss)................................ $ 0.48 $(0.68)(a)
====== ======
Basic average common shares outstanding............ 116 110(b) 226
====== === ======
Diluted average common shares outstanding.......... 128 111(b) 239
====== === ======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements
of Income.
6
<PAGE> 7
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
<TABLE>
<CAPTION>
EL PASO SONAT COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................. $5,782 $3,710 $-- $9,492
------ ------ --- ------
Operating expenses
Cost of gas and other products................... 4,212 2,745 -- 6,957
Operation and maintenance........................ 707 281 -- 988
Depreciation, depletion and amortization......... 269 349 -- 618
Ceiling test charges............................. -- 1,035 -- 1,035
Other............................................ 88 63 -- 151
------ ------ --- ------
5,276 4,473 -- 9,749
------ ------ --- ------
Operating income (loss)............................ 506 (763) -- (257)
Interest and debt expense.......................... 267 137 -- 404
Other income, net.................................. (138) (67) -- (205)
------ ------ --- ------
Income (loss) before income taxes and minority
interest......................................... 377 (833) -- (456)
Income tax expense (benefit)....................... 127 (299) -- (172)
------ ------ --- ------
Income (loss) before minority interest............. 250 (534) -- (284)
Minority interest.................................. 25 (3) -- 22
------ ------ --- ------
Net income (loss).................................. $ 225 $ (531) $-- $ (306)
====== ====== === ======
Basic earnings (loss) per common share............ $ 1.94 $(1.35)
====== ======
Diluted earnings (loss) per common share.......... $ 1.85 $(1.35)(a)
====== ======
Basic average common shares outstanding............ 116 110(b) 226
====== === ======
Diluted average common shares outstanding.......... 126 111(b) 237
====== === ======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements
of Income.
7
<PAGE> 8
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
<TABLE>
<CAPTION>
EL PASO SONAT COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................. $5,638 $4,372 $-- $10,010
------ ------ --- -------
Operating expenses
Cost of gas and other products................... 4,125 3,174 -- 7,299
Operation and maintenance........................ 664 385 -- 1,049
Depreciation, depletion and amortization......... 236 398 -- 634
Other............................................ 92 43 -- 135
------ ------ --- -------
5,117 4,000 -- 9,117
------ ------ --- -------
Operating income................................... 521 372 -- 893
Interest and debt expense.......................... 238 110 -- 348
Other income, net.................................. (57) (66) -- (123)
------ ------ --- -------
Income before income taxes and minority interest... 340 328 -- 668
Income tax expense................................. 129 107 -- 236
------ ------ --- -------
Income before minority interest.................... 211 221 -- 432
Minority interest.................................. 25 3 -- 28
------ ------ --- -------
Net income......................................... $ 186 $ 218 $-- $ 404
====== ====== === =======
Basic earnings per common share.................... $ 1.64 $ 1.80
====== =======
Diluted earnings per common share.................. $ 1.59 $ 1.76
====== =======
Basic average common shares outstanding............ 114 110(b) 224
====== === =======
Diluted average common shares outstanding.......... 117 112(b) 229
====== === =======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements
of Income.
8
<PAGE> 9
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1996
(IN MILLIONS, EXCEPT PER COMMON SHARE DATA)
<TABLE>
<CAPTION>
EL PASO SONAT COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................. $3,012 $3,204 $-- $6,216
------ ------ --- ------
Operating expenses
Cost of gas and other products................... 2,277 2,039 -- 4,316
Operation and maintenance........................ 322 301 -- 623
Depreciation, depletion and amortization......... 101 384 -- 485
Employee separation and asset impairment
charge........................................ 99 -- -- 99
Other............................................ 43 48 -- 91
------ ------ --- ------
2,842 2,772 -- 5,614
------ ------ --- ------
Operating income................................... 170 432 -- 602
Interest and debt expense.......................... 110 101 -- 211
Other income, net.................................. (5) (53) -- (58)
------ ------ --- ------
Income before income taxes and minority interest... 65 384 -- 449
Income tax expense................................. 25 125 -- 150
------ ------ --- ------
Income before minority interest.................... 40 259 -- 299
Minority interest.................................. 2 3 -- 5
------ ------ --- ------
Net income......................................... $ 38 $ 256 $-- $ 294
====== ====== === ======
Basic earnings per common share.................... $ 0.53 $ 1.62
====== ======
Diluted earnings per common share.................. $ 0.52 $ 1.59
====== ======
Basic average common shares outstanding............ 72 110(b) 182
====== === ======
Diluted average common shares outstanding.......... 73 112(b) 185
====== === ======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma Condensed Combined Statements
of Income.
9
<PAGE> 10
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF INCOME
(a) As required by the accounting rules, we have excluded additional dilutive
securities such as options in determining diluted earnings (loss) per
common share. If we had included those securities, we would have shown less
of a loss per common share.
(b) The basic and diluted common shares adjustments reflect the exchange of one
share of El Paso Energy common stock for each share of Sonat common stock
contemplated by the merger agreement.
10
<PAGE> 11
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
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 1-14365
EL PASO ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0568816
(State or Other Jurisdiction of (I.R.S. Employer
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
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
<S> <C>
Common Stock, par value $3 per New York Stock Exchange
share...............................
Preferred Stock Purchase Rights....... New York Stock Exchange
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the 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 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. [X]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT.
Aggregate market value of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of March 5, 1999,
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $4,340,497,918
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Common Stock, par value $3 per share. Shares outstanding on March 5, 1999:
120,989,489
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: Portions of El Paso Energy Corporation's definitive Proxy
Statement for the 1999 Annual Meeting of Stockholders, to be filed not later
than 120 days after the end of the fiscal year covered by this report, are
incorporated by reference into Part III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 12
EL PASO ENERGY CORPORATION
TABLE OF CONTENTS
<TABLE>
<CAPTION>
CAPTION PAGE
------- ----
<S> <C> <C>
Glossary.............................................................. ii
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 13
Item 3. Legal Proceedings........................................... 13
Item 4. Submission of Matters to a Vote of Security Holders......... 13
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 14
Item 6. Selected Financial Data..................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 16
Risk Factors -- Cautionary Statement for Purposes of the
"Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995... 36
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 39
Item 8. Financial Statements and Supplementary Data................. 42
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 78
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 78
Item 11. Executive Compensation...................................... 78
Item 12. Security Ownership of a Certain Beneficial Owner and
Management................................................ 78
Item 13. Certain Relationships and Related Transactions.............. 78
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 78
Signatures.................................................. 82
</TABLE>
i
<PAGE> 13
GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
<TABLE>
<S> <C>
ALJ............................... Administrative Law Judge
BBtu(/d).......................... Billion British thermal units (per day)
Bcf(/d)........................... Billion cubic feet (per day)
Board............................. Board of directors of El Paso Energy Corporation
CAPSA............................. Companias Asociadas Petroleras SA, a privately held integrated
energy company in Argentina
Company........................... El Paso Energy Corporation and its subsidiaries which, on August 1,
1998, became the successor company to El Paso Natural Gas Company
Court of Appeals.................. United States Court of Appeals for the District of Columbia Circuit
DeepTech.......................... DeepTech International Inc., a wholly owned subsidiary of El Paso
Energy Corporation
Distributions..................... Various intercompany transfers and distributions which
restructured, divided and separated the business, assets and
liabilities of Old Tenneco and its subsidiaries so that all the
assets, liabilities and operations related to the automotive parts,
packaging and administrative services businesses and the
shipbuilding business were spun-off to Old Tenneco's then existing
common stockholders
Dynegy............................ Dynegy Inc., formerly known as NGC Corporation
EBIT.............................. Earnings before interest expense and income taxes, excluding
affiliated interest income
East Tennessee.................... East Tennessee Natural Gas Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
Edison............................ Southern California Edison Company
EPA............................... United States Environmental Protection Agency
EPEC.............................. El Paso Energy Corporation, unless the context otherwise requires
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 subsequent to August 1, 1998
EPTPC............................. El Paso Tennessee Pipeline Co. (formerly Tenneco Inc.), a direct
subsidiary of El Paso Energy Corporation
FERC.............................. Federal Energy Regulatory Commission
GSR............................... Gas supply realignment
IRS............................... Internal Revenue Service
Leviathan......................... Leviathan Gas Pipeline Partners, L.P., a publicly held Delaware
limited partnership
MBbls............................. Thousand barrels
Merger............................ The acquisition of El Paso Tennessee Pipeline Co. by
El Paso Natural Gas Company in December 1996
Mgal/d............................ Thousand gallons per day
Midwestern........................ Midwestern Gas Transmission Company, a wholly owned subsidiary of
El Paso Tennessee Pipeline Co.
</TABLE>
ii
<PAGE> 14
<TABLE>
<S> <C>
MMcf/d............................ Million cubic feet per day
Mdth/d............................ Thousand decatherms per day
MPC............................... Mojave Pipeline Company, a wholly owned indirect partnership of El
Paso Natural Gas Company
MW(s)............................. Megawatt(s)
New Tenneco....................... Tenneco Inc., subsequent to the Merger and Distributions,
consisting of the automotive parts, packaging and administrative
services businesses
Old Tenneco....................... Tenneco Inc. (renamed El Paso Tennessee Pipeline Co.), prior to its
acquisition by the Company
PCB(s)............................ Polychlorinated biphenyl(s)
PG&E.............................. Pacific Gas & Electric Company
PLN............................... Perusahaan Listrik Negara, the Indonesian government owned electric
utility
Program........................... Continuous Odd-Lot Stock Sales Program
PRP(s)............................ Potentially Responsible Party(ies)
SFAS.............................. Statement of Financial Accounting Standards
SoCal............................. Southern California Gas Company
TGP............................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
</TABLE>
iii
<PAGE> 15
PART I
ITEM 1. BUSINESS
GENERAL
On August 1, 1998, EPEC succeeded EPNG as the publicly traded parent
corporation in a holding company reorganization. In the reorganization, EPNG, a
Delaware corporation formed in 1928, and its subsidiaries became direct and
indirect subsidiaries of the Company. EPEC, also a Delaware corporation, was
incorporated in 1998. The New York Stock Exchange ticker symbol used by EPEC
following the reorganization remains unchanged as "EPG."
The Company's principal operations include the interstate and intrastate
transportation, gathering and processing of natural gas; the marketing of
natural gas, power, and other commodities; and the development and operation of
energy infrastructure facilities worldwide. The Company owns or has interests in
over 28,000 miles of interstate and intrastate pipeline connecting the nation's
principal natural gas supply regions to the four largest consuming regions in
the United States, namely the Gulf Coast, California, the Northeast and the
Midwest. The Company's natural gas transmission operations include one of the
nation's largest mainline natural gas transmission systems which is comprised of
five interstate pipeline systems: the El Paso Natural Gas pipeline, the
Tennessee Gas pipeline, the Midwestern Gas Transmission pipeline, the East
Tennessee Natural Gas pipeline, and the Mojave Pipeline.
In addition to its interstate transmission services, the Company provides
related services, including natural gas gathering, products extraction,
dehydration, purification, compression, and intrastate transmission. These
services include gathering of natural gas from more than 10,000 natural gas
wells with approximately 11,000 miles of gathering lines, and 23 natural gas
processing and treating facilities located in some of the most prolific and
active production areas of the United States, including the San Juan and Permian
Basins and in east Texas, south Texas, Louisiana, and the Gulf of Mexico. The
Company conducts intrastate transmission operations through its interests in
four Texas intrastate systems, which include the Oasis Pipeline running from
west Texas to Katy, Texas, the Channel Pipeline extending from south Texas to
the Houston Ship Channel, and the Shoreline and Tomcat gathering systems which
gather gas from offshore Texas. The Company's marketing activities include the
marketing and trading of natural gas, power, and petroleum products, as well as
providing integrated price risk management services associated with these
commodities. The Company also participates in the development and ownership of
domestic power generation facilities, and other power-related assets and joint
ventures.
The Company's international activities focus on the development and
operation of international energy infrastructure projects and include ownership
interests in three major operating natural gas transmission systems in Australia
and natural gas transmission systems and power generation facilities currently
in operation or under construction in Argentina, Bolivia, Brazil, Chile, the
Czech Republic, Hungary, Indonesia, Mexico, Pakistan, Peru, the United Kingdom,
Bangladesh, the Philippines and China. The Company also has an interest in three
operating domestic power generation plants.
In August 1998, the Company completed the acquisition of DeepTech by
merging DeepTech with a subsidiary of the Company. As a result of the
acquisition, the Company owns 100 percent of the general partner of Leviathan,
and a 27.3 percent effective ownership interest in Leviathan, with the remaining
interest held publicly. The acquisition was accounted for as a purchase with a
total purchase price of approximately $422 million, net of cash acquired.
Leviathan is the largest independent gatherer of natural gas in the Gulf of
Mexico and owns interests in pipeline systems which transported an average of
approximately 3.1 Bcf/d in 1998. These pipeline systems serve a large portion of
the outer continental shelf and provide access to the prolific deepwater trend
of the Gulf of Mexico. Leviathan has ownership interests in the High Island
Offshore system, the U-T Offshore system, the Stingray Pipeline system, the
Nautilus/Manta Ray Offshore system, the Viosca Knoll Gathering system and the
Poseidon Oil Pipeline system.
1
<PAGE> 16
In December 1996, the Company completed its $4 billion acquisition of EPTPC
in a transaction accounted for as a purchase. In the Merger, Old Tenneco changed
its name to EPTPC. Prior to the Merger, Old Tenneco and its subsidiaries
effected various intercompany transfers and restructurings so that in the
Distributions all the assets, liabilities and operations related to their
automotive parts, packaging, and administrative services businesses
(collectively, the "Industrial Business") and their shipbuilding business (the
"Shipbuilding Business") were spun-off to Old Tenneco's then existing common
stockholders. Following the Distributions, EPTPC's business consisted
principally of the regulated energy operations, including the interstate
transportation of natural gas, as well as non-regulated energy operations such
as gas marketing, intrastate pipelines, international pipelines and power
generation, and domestic power generation. This acquisition created the nation's
first coast-to-coast natural gas pipeline system and furthered the Company's
efforts to expand its presence in non-regulated portions of the energy industry.
EPEC owns 100 percent of the common equity and greater than 80 percent of the
combined equity value of EPTPC. The remaining combined equity of EPTPC consists
of $300 million of preferred stock issued in a public offering by Old Tenneco in
November 1996, which remains outstanding. For a further discussion of these
acquisitions, see Item 8, Financial Statements and Supplementary Data, Note 2.
SEGMENTS
Beginning in 1998, the Company segregated its business activities into five
segments: Tennessee Gas Pipeline segment, El Paso Natural Gas segment, El Paso
Field Services segment, El Paso Energy Marketing segment, and El Paso Energy
International segment. These segments are strategic business units that offer a
variety of different energy products and services. They are managed separately,
as each business unit requires different technology and marketing strategies.
For information relating to operating revenues, operating income, EBIT, and
identifiable assets attributable to each segment, see Item 8, Financial
Statements and Supplementary Data, Note 13.
Set forth below is a description of the principal business activities
conducted by each of the Company's segments:
<TABLE>
<CAPTION>
<S> <C>
Tennessee Gas Pipeline Provides interstate natural gas pipeline
transportation to the northeast, midwest and
mid-Atlantic sections of the U.S., including the
states of Tennessee and Virginia as well as the New
York City, Chicago and Boston metropolitan areas.
Such transportation is conducted through the
interstate pipeline systems of TGP, Midwestern and
East Tennessee.
El Paso Natural Gas Provides interstate natural gas pipeline
transportation primarily to the California market.
Such transportation is conducted by the EPNG and
MPC interstate pipeline systems.
El Paso Field Services Provides natural gas gathering, products
extraction, dehydration, purification, compression
and intrastate natural gas transmission services.
El Paso Energy Marketing Markets and trades natural gas, power and petroleum
products and provides integrated risk management
services.
El Paso Energy International Develops and operates energy infrastructure
facilities worldwide.
</TABLE>
In addition, the Company participates in the development and ownership of
domestic power generation projects.
2
<PAGE> 17
TENNESSEE GAS PIPELINE
The TGP system. The TGP system consists of approximately 14,700 miles of
pipeline with a design capacity of 5,512 MMcf/d. During 1998, TGP transported
natural gas volumes averaging approximately 80 percent of its capacity. The TGP
system serves the northeast section of the U.S., including the New York City and
Boston metropolitan areas. The multiple-line system begins in the gas-producing
regions of south Texas and Louisiana, including the Gulf of Mexico.
The Midwestern system. The Midwestern system consists of approximately 400
miles of pipeline with a design capacity of 785 MMcf/d. During 1998, Midwestern
transported natural gas volumes averaging approximately 35 percent of its
capacity. The Midwestern system extends from a connection with the TGP system at
Portland, Tennessee, to Chicago and principally serves the Chicago metropolitan
area.
The East Tennessee system. The East Tennessee system consists of
approximately 1,100 miles of pipeline with a design capacity of 675 MMcf/d.
During 1998, East Tennessee transported natural gas volumes averaging
approximately 45 percent of its capacity. The East Tennessee system serves the
states of Tennessee, Virginia and Georgia and connects with the TGP system in
Springfield and Lobelville, Tennessee.
Other. The Company increased its ownership interest in the Portland Natural
Gas Transmission ("Portland") system from 17.8 percent to approximately 19
percent in April 1998. Portland is a 292-mile interstate natural gas pipeline
with initial capacity of 178 MMcf/d extending from the Canadian border near
Pittsburg, New Hampshire to Dracut, Massachusetts. In April 1998, Portland
secured $256 million in non-recourse project financing. Construction started in
June 1998, with an estimated total cost of $423 million. Portland commenced
commercial operations in March of 1999.
From time to time, the Company holds open seasons in an effort to
capitalize on pipeline expansion opportunities. Currently, TGP has completed an
open season for the Eastern Express Project 2000 to provide gas transportation
for the growing markets in the northeast. As a result, TGP will be filing an
application before FERC for the expansion in the first quarter of 1999 to begin
service in 2000. TGP has also filed an application with FERC to construct an
international border crossing at Reynosa, Tamaulipas, Mexico, and interconnect
with Pemex Gas y Petroquimica Basica, a Mexican state-owned company ("Pemex") to
provide the import of gas from Mexico. The border crossing service is expected
to begin in 1999.
EL PASO NATURAL GAS
The EPNG system. The EPNG system consists of approximately 9,800 miles of
pipeline with a design capacity of 4,744 MMcf/d. During 1998, EPNG transported
natural gas volumes averaging approximately 77 percent of its capacity. The EPNG
system serves California, which is its single largest market, and also serves
markets in Nevada, Arizona, New Mexico, Texas, Oklahoma, and northern Mexico.
The EPNG system delivers natural gas from the San Juan Basin of northern New
Mexico and southern Colorado, and also accesses natural gas supplies in the
Permian and Anadarko Basins of West Texas.
The MPC system. The MPC system consists of approximately 400 miles of
pipeline with a design capacity of approximately 400 MMcf/d. During 1998, MPC
transported natural gas volumes averaging approximately 81 percent of its
capacity. The MPC system is connected with the EPNG transmission system at
Topock, Arizona and Kern River Gas Transmission Company in California and
extends to customers in the vicinity of Bakersfield, California.
REGULATORY ENVIRONMENT
The interstate systems are subject to the jurisdiction of FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978.
Industry Restructuring. In the mid-1980s, FERC initiated a series of
actions which ultimately had the effect of substantially removing interstate
pipelines from the gas purchase and resale business and confining their role to
transportation of gas owned by others. In Order No. 436, issued in 1985, FERC
began this transition by requiring interstate pipelines to provide
non-discriminatory access to their facilities for all
3
<PAGE> 18
transporters of natural gas. This requirement enabled consumers to purchase
their own gas and have it transported on the interstate pipeline system, rather
than purchase gas from the pipelines. The transition was completed with Order
No. 636, issued in 1992, in which FERC required all interstate pipelines to
"unbundle" their sales and transportation services so that the transportation
services they provided to third parties would be "comparable" to the
transportation services provided to gas owned by the pipeline. FERC's stated
purpose was to ensure that the pipelines' monopoly over the transportation of
natural gas did not distort the competition in the gas producer sales market,
which had, by then, been essentially deregulated.
One of the obstacles to this transition was the existence of long-term gas
purchase contracts between pipelines and producers which required the pipelines
to take or pay for a significant percentage of the gas the producer was capable
of delivering. While FERC did not deal with this issue initially, it eventually
adopted rate recovery procedures which facilitated negotiations between
pipelines and producers to address take-or-pay issues. Such procedures were
established in Order Nos. 500, 528 and 636, in the last of which FERC provided
that pipelines could recover 100 percent of the costs prudently incurred to
terminate their gas purchase obligations. In July 1996, the Court of Appeals
issued its decision upholding, in large part, Order No. 636.
TGP. In December 1994, TGP filed for a general rate increase with FERC and
in October 1996, FERC approved the settlement resolving that proceeding. The
settlement included a structural rate design change that resulted 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) and, at FERC's request, comments were filed in
January 1999.
EPNG. In June 1995, EPNG filed with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In March 1996, EPNG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996 through December 31, 1997. In April 1997, FERC
approved EPNG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rates it
directly pays EPNG. In July 1997, FERC issued an order denying requests for
rehearing of the April 1997 order, and the settlement was implemented effective
July 1, 1997. Hearings to determine Edison's rates were completed in May 1998,
and an initial decision was issued by the presiding ALJ in July 1998. EPNG and
Edison have filed exceptions to the decision with FERC. If the ALJ's decision is
affirmed by FERC, EPNG believes that the resulting rates to Edison would be such
that no significant, if any, refunds in excess of the amounts reserved would be
required. Pending the final outcome, Edison continues to pay the filed rates,
subject to refund, and EPNG continues to provide a reserve for such potential
refunds.
Edison filed with the Court of Appeals a petition for review of FERC's
April 1997 and July 1997 orders, in which it challenged the propriety of FERC's
approving the settlement over Edison's objections to the settlement in its
capacity as a customer of SoCal. In December 1998, the Court of Appeals issued
its decision vacating and remanding FERC's order. EPNG will file a motion with
FERC proposing procedures for FERC to address deficiencies which the Court of
Appeals found in FERC's earlier orders. EPNG cannot predict the outcome with
certainty but it believes that FERC will ultimately approve the settlement.
For a further discussion of regulatory matters related to TGP and EPNG, see
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MARKETS AND COMPETITION
The Interstate Systems face varying degrees of competition from alternative
energy sources, such as electricity, hydroelectric power, coal, and fuel oil.
The potential consequences of proposed and ongoing restructuring and
deregulation of the electric power industry are currently unclear. It may
benefit the natural gas industry by creating more demand for natural gas turbine
generated electric power, or it may hamper demand by allowing more effective use
of surplus electric capacity through increased wheeling as a result of open
access. At this time, the Company is not projecting a significant change in
natural gas demand as a result of such restructuring.
4
<PAGE> 19
The TGP System. Customers of TGP include natural gas producers, marketers
and end-users, as well as other gas transmission and distribution companies,
none of which individually represents more than 10 percent of the revenues on
TGP's system. Substantially all of the revenues of TGP are generated under
long-term natural gas transmission contracts. Contracts representing
approximately 70 percent of TGP's firm transportation capacity will be expiring
over the next two years, principally in 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, TGP cannot give
any assurance that it 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 number of key markets, TGP faces competitive pressure from other major
pipeline systems, enabling local distribution companies and end-users to choose
a supplier or switch suppliers based on the short-term price of natural gas and
the cost of transportation. Competition among pipelines is particularly intense
in TGP's supply areas, Louisiana and Texas. In some instances, TGP has had to
discount its transportation rates in order to maintain market share. The
renegotiation of TGP's expiring contracts may be adversely affected by the
foregoing competitive factors.
The EPNG System. EPNG faces significant competition from three other
companies -- Transwestern Pipeline Company, Kern River Gas Transmission Company,
and PG&E -- all of which transport natural gas to the California market. The
combined capacity of these three companies and EPNG to the California market is
approximately 6.9 Bcf/d. In 1998, the demand for interstate pipeline capacity to
California averaged 5.1 Bcf/d. Competition generally occurs on the basis of the
delivered cost of natural gas, including transportation costs, into the SoCal
and PG&E distribution systems. In addition to being the principal transporter to
certain markets east of California, EPNG maintains a significant competitive
position in the California market because its pipeline is currently the
lowest-cost transporter of, and the principal means of moving, natural gas from
the San Juan Basin to the California border. EPNG's current capacity to deliver
natural gas to California is approximately 3.3 Bcf/d, equivalent to
approximately 48 percent of the total interstate pipeline capacity serving that
state. Natural gas shipped to California across the EPNG System represented
approximately 33 percent of the natural gas consumed in the state in 1998. The
significant customers served by EPNG in California during 1998 include SoCal,
with capacity of 1,150 MMcf/d under contract until August 2006, and Dynegy, with
capacity of 1,311 MMcf/d under contract until December 1999.
Interstate pipeline capacity utilization to California is currently
approximately 74 percent and is not expected to reach 100 percent until sometime
in the next decade, assuming no new interstate pipeline construction. Currently,
EPNG has firm transportation contracts covering all of its available capacity to
California. As a part of its effort to remarket capacity relinquished by PG&E at
the end of 1997, EPNG entered into three contracts with Dynegy for the sale of
all of its then available firm capacity for a two-year period beginning January
1, 1998 at rates negotiated pursuant to EPNG's tariff provisions and FERC
policies. For a further discussion of capacity relinquishments, see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
EL PASO FIELD SERVICES
EPFS was formed for the purpose of owning, operating, acquiring and
constructing natural gas gathering, processing and other related facilities.
Effective January 1, 1996, EPNG transferred its non-regulated assets to EPFS.
These assets included major natural gas gathering systems in the San Juan and
Permian Basins. From this initial asset base, EPFS began to implement plans to
increase natural gas gathering and processing volumes through a strategy of
project development, acquisitions, and joint ventures.
EPFS provides its customers with wellhead-to-mainline field services,
including natural gas gathering and transportation, products extraction,
dehydration, purification and compression. EPFS also provides intrastate natural
gas transmission services. EPFS, together with EPEM, provides fully bundled
natural gas services with a broad range of pricing options as well as financial
risk management products. EPFS also provides well-ties
5
<PAGE> 20
and offers real-time information services, including electronic wellhead gas
flow measurement. EPFS services are provided under a variety of fee structures
including fixed fee per decatherm, floating fee per decatherm indexed to the
applicable local area price of gas, or percentage of products sold.
In August 1998, the Company completed the acquisition of DeepTech by
merging it with a subsidiary of EPEC. DeepTech's assets included a combined 27.3
percent ownership interest in Leviathan, a publicly traded master limited
partnership. The acquisition, valued at approximately $422 million, net of cash
acquired, was accounted for as a purchase. The Leviathan assets include
interests in eight natural gas pipeline systems with 1,167 miles of pipeline
capable of moving 6.5 Bcf/d, 316 miles of crude oil pipelines, five
multi-purpose platforms with processing capabilities, and four producing oil and
gas properties.
Additionally, in August 1998, the Company completed the expansion of the
Coyote Gulch Treating Plant which increased capacity from 120 MMcf/d to 240
MMcf/d, providing an additional outlet for coal seam gas production in
southwestern Colorado.
In September 1998, the Company completed the Global Compression project, a
$45 million capital investment that consists of 40,000 horsepower of
compression, gas dehydration facilities, and 54 miles of pipeline looping. The
project lowered wellhead pressures and increased production rates for 70 percent
of the wells from which EPFS gathers in the San Juan Basin.
In September 1998, EPFS sold its natural gas gathering, treating, and
processing assets in the Anadarko Basin to Midcoast Energy Resources, Inc. for
$35 million.
The following table provides information as of December 31, 1998,
concerning the natural gas gathering and transportation facilities, as well as
natural gas gathered/transported for the three years ended December 31:
<TABLE>
<CAPTION>
AVERAGE THROUGHPUT
MILES THROUGHPUT (BBTU/D)
OF CAPACITY ---------------------
GATHERING & TREATING PIPELINE(1) (MMCF/D)(2) 1998 1997 1996
-------------------- ----------- ----------- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Western Division...................... 5,555 1,200 1,191 1,167 1,139
Eastern Division...................... 955 910 282 252 149
Central Division...................... 1,266 933 427 408 373
Offshore Division..................... 410 2,040 780 314 --
Joint Owned Division.................. 750 900 564 6 --
</TABLE>
The following table provides information concerning the processing
facilities for the three years ended December 31:
<TABLE>
<CAPTION>
AVG INLET VOLUME AVERAGE NGLS SALES
(BBTU/D) (MGAL/D)
INLET ------------------ ------------------
PROCESSING PLANTS CAPACITY(2) 1998 1997 1996 1998 1997 1996
----------------- ----------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
Western Division..................... 600 586 551 557 370 505 352
Eastern Division..................... 207 109 126 75 275 229 115
Central Division..................... 278 269 58 19 208 94 39
Joint Owned Division................. 199 51 102 -- 74 167 --
</TABLE>
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<PAGE> 21
The following table provides information concerning natural gas gathering
and transportation facilities in which EPFS owns a minority interest and
accounts for under the equity method:
<TABLE>
<CAPTION>
AVERAGE
AVERAGE THROUGHPUT THROUGHPUT THROUGHPUT
PERCENT OF MILES THROUGHPUT (BBTU/D) CAPACITY MBBLS
OWNERSHIP OF CAPACITY ------------------- MBBLS OIL OIL/D
INTEREST PIPELINE(1) (MMCF/D)(2) 1998(3) 1997(4) PER DAY(2) 1998(3)
---------- ----------- ----------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Leviathan............ 27.3 1,358 1,198 593 -- 58 17
Oasis................ 35.0 608 350 289 338 -- --
Coyote Gulch......... 50.0 -- 120 69 42 -- --
Viosca Knoll......... 50.0 125 500 287 205 -- --
</TABLE>
- ------------
(1) Mileage amounts are approximate for the total systems and have not been
reduced to reflect EPFS's net ownership.
(2) All capacity information reflects EPFS's net interest and is subject to
increases or decreases depending on operating pressures and point of
delivery into or out of the system.
(3) Throughput for Leviathan is averaged since its acquisition on August 14,
1998.
(4) Throughput for Oasis was in El Paso Energy Marketing segment in 1997.
In January 1999, the Company and Leviathan entered into an agreement where
the Company will sell, for approximately $85 million, all of its interest in
Viosca Knoll Gathering Company to Leviathan except for a 1 percent interest in
profits and capital. The transaction was approved by Leviathan's board of
directors in January 1999, and at a special meeting held March 5, 1999, the
Leviathan unitholders approved an increase in the authorized number of common
units required to complete the acquisition. The transaction is expected to close
in the second quarter of 1999. As a result of this transaction, the Company's
combined ownership interest in Leviathan will increase to approximately 35
percent.
Competition
EPFS operates in a highly competitive environment that includes independent
natural gas gathering and processing companies, intrastate pipeline companies,
natural gas marketers, and oil and gas producers. EPFS competes for throughput
primarily based on price, efficiency of facilities, gathering system line
pressures, availability of facilities near drilling activity, service, and
access to favorable downstream markets.
EL PASO ENERGY MARKETING
EPEM, the Company's merchant services and trading business, utilizes its
extensive knowledge of the marketplace, natural gas pipeline and power
transmission infrastructure, supply aggregation, transportation management and
valuation, storage and integrated price risk management to provide customers
with flexible solutions to meet their energy supply and financial risk
management requirements. EPEM markets and trades natural gas, power, and
petroleum products in the United States, Canada and Mexico. EPEM has emerged as
one of North America's largest energy marketing and trading companies.
EPEM contracts to purchase specific natural gas volumes from suppliers at
various times and points of receipt, arranges for the aggregation and
transportation of such natural gas, and negotiates the sale of these volumes to
utilities (including local distribution companies and power plants),
municipalities, and a variety of industrial and commercial end users. EPEM seeks
to maintain a balanced portfolio of supply and demand contracts and a diverse
natural gas supplier and customer base. During 1998, it served over 400
producers/suppliers and approximately 2,000 sales customers in 26 states and
shipped natural gas supplies on 65 pipelines.
EPEM utilizes a broad range of risk management instruments to manage its
fixed-price purchase and sales commitments and reduce its exposure to market
price volatility. EPEM trades futures contracts and options on the New York
Mercantile Exchange and trades swaps and options in over-the-counter financial
markets with other major energy merchants. Market risks are managed on a
portfolio basis, subject to parameters established by a risk control committee
that operates independently from commercial operations
7
<PAGE> 22
and reports directly to the Board. Market risk in EPEM's commodity derivative
portfolio is measured on a daily basis utilizing a Value-at-Risk (VAR) model to
determine the maximum potential one-day unfavorable impact on its earnings. For
additional information regarding the use of financial instruments, see Item 7A,
Quantitative and Qualitative Disclosures About Market Risk and Item 8, Financial
Statements and Supplementary Data, Note 5.
Set forth below are the marketed gas, power and petroleum volumes for the
years ended December 31:
<TABLE>
<CAPTION>
1998 1997 1996(1)
------ ------ -------
<S> <C> <C> <C>
Natural gas volumes marketed (Bbtu/d)(2)................... 11,540 6,969 4,568
Power volumes marketed (Thousand MW hours)................. 44,677 12,969 3,878
Petroleum volumes marketed (MBbls per year)(2)............. 21,717 80,641 54,913
</TABLE>
- ---------------
(1) Average daily volumes for the gas marketing activities of EPTPC, acquired in
December 1996, are reflected from the date of acquisition in 1996 and for
the full year of 1997 and 1998.
(2) Includes financial trades.
Competition
EPEM operates in a highly competitive environment. Its primary competitors
include: (i) marketing affiliates of major oil and gas producers; (ii) marketing
affiliates of large local distribution companies; (iii) marketing affiliates of
other interstate and intrastate pipelines; and (iv) independent energy marketers
with varying scopes of operations and financial resources. EPEM competes on the
basis of price, access to production, understanding of pipeline and transmission
networks, imbalance management, and experience in the marketplace.
EL PASO ENERGY INTERNATIONAL
EPEI was formed for the purpose of investing in integrated energy projects
with an emphasis on developing infrastructure to gather, transport and use
natural gas in northern Mexico and certain Latin American countries. With the
combination of EPTPC's international activities, the focus of international
project pursuit has expanded to include power generation and to include
investments located in Australia, Asia, Europe and other Latin American
countries. Set forth below are brief descriptions, by region, of the projects
that are either operational or in various stages of development.
Acquisitions and greenfield development projects are subject to a higher
level of commercial and financial risk in foreign countries. Accordingly, EPEI
has adopted a risk mitigation strategy to reduce risks to more acceptable and
manageable levels. EPEI's practice is to select experienced partners with a
history of success in commercial operations. Individual partners are generally
chosen based on the complementary competencies which they offer to the various
joint ventures formed or to be formed. EPEI designs and implements a formal due
diligence plan on every project it pursues, and contracts are negotiated to
secure fuel supply, manage operating and maintenance costs and, when possible,
index revenues and denominate transactions in U.S. dollars. EPEI also obtains
political risk insurance when deemed appropriate, through the Overseas Private
Investment Corporation, the Multilateral Investment Guarantee Agency, or a
private insurer.
Latin America and Mexico
Samalayuca Power Project -- The Company owns a 30 percent interest in a 700
MW combined cycle gas fired power plant in Samalayuca, Mexico. The first,
second, and third units commenced commercial operations in May, September, and
December 1998, respectively. Comision Federal de Electricidad, the Mexican
government-owned electric utility ("CFE") operates the plant under a 20-year
lease. Upon expiration of the lease term, ownership of the plant will be
transferred to CFE.
Samalayuca Pipeline -- This 45-mile 212 MMcf/d pipeline system commenced
gas deliveries in December 1997. The pipeline delivers natural gas to the
Samalayuca Power Project from EPNG's existing pipeline system in West Texas and
Pemex's pipeline system in northern Mexico. This system consists of
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<PAGE> 23
22 miles of pipeline in the U.S. (currently owned by EPNG) and 23 miles of
pipeline in Mexico
(currently 50 percent owned by the Company).
Aguaytia Project -- The Company owns a 24 percent interest in an integrated
natural gas and power generation project near Pucallpa, located in central Peru.
The project consists of a 302 Bcf natural gas field, a natural gas processing
facility, a 71-mile natural gas liquids pipeline to a fractionation facility, a
126-mile natural gas pipeline to a 155 MW simple cycle power plant, and a
250-mile 220 KV power transmission line interconnecting with the Peruvian grid
at Paramonga. The project began operations in July 1998.
CAPSA -- The Company has an effective 45 percent interest in CAPSA, a
privately held integrated energy company in Argentina. CAPSA was incorporated in
1977 for the purpose of producing, selling and exploring for liquid
hydrocarbons. CAPSA's assets include a 100 percent ownership interest in the
Diadema Oil Field and a 55 percent ownership interest in CAPEX, a publicly
traded company on the Argentine and Luxembourg stock exchanges that owns the 382
MW (currently being expanded to 650 MW) Agua del Cajon gas fired power plant in
western Argentina. This plant has been fully operational since 1995 and buys
natural gas from CAPEX's Agua del Cajon gas field. CAPEX also owns a 24 percent
interest in the 76 MW Energia del Sur gas fired power plant in southern
Argentina.
Triunion Energy Company -- In January 1998, the Company, CAPEX and
InterEnergy formed a new development company named Triunion Energy Company
("Triunion Energy") to identify and develop new energy related projects in Latin
America. Triunion Energy currently owns a 20 percent interest in an exploration
and production project in Charagua, Bolivia, as well as a 22 percent interest in
an approved project to build a $380 million, 325 mile, natural gas pipeline that
will cross the Andes Mountains connecting natural gas production in Argentina's
Neuquen Basin to customers in Concepcion, Chile. Construction of the pipeline
commenced in early 1998 and is expected to be completed in late 1999.
Manaus Power Project -- The Company owns 100 percent of a 250 MW power
plant in Manaus, the capital city of the state of Amazonas in northern Brazil.
Power from the plant is currently sold under a four-year contract to
Electronorte, the local electric company. The first phase of the project
commenced operations in February 1998. The second phase commenced operations in
March 1998 and the third phase commenced operations in June 1998. See Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations for additional discussion of the Manaus power project.
Bolivia to Brazil Pipeline -- The Company is part of a consortium that is
constructing a 2,000 mile pipeline from Santa Cruz, Bolivia to Sao Paulo,
Brazil, with a southern lateral to Porto Alegre, Brazil. The pipeline will
transport natural gas to the largest unserved market in the western hemisphere
(approximately 100 million people). The pipeline is expected to be in service in
early 1999. The Company's interest in the project is approximately 8 percent.
Parana Power Project -- The Company has an approximate 30 percent interest
in a consortium to build a 480 MW natural gas fired power plant in the state of
Parana, in southern Brazil. The power plant will be located in Araucaria,
Brazil. The electricity will be purchased by Companhia Paranaense de Energia, an
integrated electric utility providing generation, transmission, and distribution
of electricity to all regions of the state of Parana. The plant will be fueled
by natural gas provided from the Bolivia to Brazil pipeline. Final negotiation
and signing of a power purchase agreement will take place in early 1999 with
financial close expected in the fourth quarter of 1999. Commercial operations
are expected to commence in late 2000.
Costanera -- In July 1998, the Company acquired 100 percent of KLT Power,
Inc., the international business unit of Kansas City Power and Light Company.
KLT Power, was established in 1993, to develop, finance, own, and operate
independent power projects in selected markets worldwide. KLT Power owns a 12
percent interest in Central Costanera, the largest thermal-power plant in
Argentina consisting of 2,167 MW of power generation and a 7.8 percent interest
in Central Termoelectrica Buenos Aires, S.A., a 328 MW combined cycle power
plant in Buenos Aires.
9
<PAGE> 24
Europe
EMA Power -- The Company owns a 50 percent controlling interest in a 70 MW
power plant located in Dunaujvaros, Hungary. The electricity generated at the
plant is consumed by Dunaferr Kft., the largest steel mill in Hungary. Approval
has been given to expand the capacity of the electric generating plant to 140 MW
and construction is scheduled to commence in late 1999.
Kladno Power -- In May 1997, the Company acquired a 31 percent interest in
a 338 MW natural gas and coal fired expansion and upgrade of an existing 25 MW
cogeneration facility located approximately 19 miles northwest of Prague, in the
Czech Republic. The Company sold a 13 percent interest in the project to one of
the original partners under a buy back option granted by the Company in June
1997. The Company expects to purchase a similar amount in 1999 from another
partner under a similar option agreement. Non-recourse project financing was
finalized in June 1997, and commercial operations are expected to commence in
the fourth quarter of 1999.
Fife Power -- In September 1998, the Company acquired a 50 percent interest
in the first Scottish independent power project located in Fife. The existing
plant consists of a simple cycle natural gas fired turbine generating 75 MW,
which commenced operations in the fourth quarter of 1998. Under Phase II, a
steam turbine will be added to produce a total combined-cycle generating
capacity of 115 MW. Financial close for Phase II is expected to occur in early
1999, and commercial operation is expected to commence in early 2001.
Enfield -- In December 1998, the Company acquired a 25 percent interest in
Enfield Energy Center Limited. The 396 MW combined cycle natural gas turbine
power plant is under construction near London, England and is expected to be
operational by October 1999.
Asia Pacific
Australian Pipelines -- The Company owns a 30 percent interest in the
Moomba to Adelaide pipeline system, a 488-mile natural gas pipeline in southern
Australia and the Ballera to Wallumbilla pipeline system, a 470-mile natural gas
pipeline in southwestern Queensland.
In March 1998, the Company, through its 33.3 percent interest in Epic
Energy (WA) Pipeline Trust venture, purchased the 925-mile Dampier-to-Bunbury
natural gas pipeline in western Australia. This 550 MMcf/d pipeline system
serves a number of western Australian markets, including industrial end-users.
An expansion of the Dampier-to-Bunbury pipeline is currently underway to supply
additional natural gas to Alcoa, Worsley and Wesfarmers. The expansion,
scheduled for completion in fourth quarter of 1999, will expand the pipeline
capacity to 635 MMcf/d.
Sengkang Project -- The Company has a 50 percent interest in a producing
natural gas field with proven reserves of 533 Bcf and a 47.5 percent interest in
a 135 MW power plant in Sengkang, South Sulawesi, Indonesia. The electricity
produced by the power plant is sold to PLN, the national electric utility, under
a long-term power purchase agreement. The power plant began simple cycle
commercial operation in September 1997, making it one of the first independent
power plants to operate in Indonesia. Combined cycle completion was in September
1998. For a discussion related to the effects on the project of the devaluation
of the Indonesian rupiah, see Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations.
Kabirwala Power -- The Company owns a 42 percent interest in a 151 MW
natural gas fired power plant currently under construction in Kabirwala,
Pakistan. Commercial operation is expected to commence in the second quarter of
1999. The power plant will sell electricity to the State Water and Power
Development Authority.
Haripur -- The Company owns a 50 percent interest in a consortium formed to
construct a 115 MW oil and gas-fired power generation facility in Haripur,
Bangladesh. The plant will sell power to the Bangladesh Power Development Board
under a 15-year power purchase agreement. The plant is expected to be in service
by the end of May 1999.
10
<PAGE> 25
East Asia Power -- In 1998, the Company executed agreements to acquire a 46
percent interest in East Asia Power Resources Corporation ("EAPRC"), a publicly
traded company in the Philippines. EAPRC owns and operates three power
generation facilities in the Philippines and owns an interest in one power
generation facility in China, with a total generating capacity of 289 MW. EAPRC
also has options to acquire two additional power generation facilities in the
Philippines with an aggregate generating capacity of 123 MW. Electric power
generated by the facilities is supplied to a diversified base of customers
including NPC, the state-owned utility, private distribution companies and
industrial users. This acquisition was completed in February 1999.
Other Projects
The Company owns interests in three operating domestic power generation
plants consisting of a 17.5 percent interest in a 240 MW power plant in
Springfield, Massachusetts and a 50 percent interest in two additional
cogeneration projects in Florida with a combined generating capacity of 220 MW.
CORPORATE AND OTHER OPERATIONS
In February 1998, El Paso Power Services ("EPPS") was formed to manage,
acquire, and develop power-related assets and joint ventures. EPPS participates
in the development, construction, and operation of domestic power generation
projects as well as provides restructuring services to electric utilities,
non-utility and merchant generators, fuel suppliers, and large industrial
concerns to achieve lower costs in the transition to a more competitive business
environment.
EPPS has a 56 percent interest in a 270 MW natural gas-fired combined cycle
power generation facility under construction in Agawam, Massachusetts
("Berkshire") which is expected to commence commercial operation in December
1999. Berkshire has entered into a fuel management agreement to purchase all
natural gas and fuel oil used to operate the facility at market rates from EPEM
through December 2019. In addition, Berkshire has entered into a power marketing
agreement to sell all power produced by the facility to EPPS at market rates
through December 2019.
In December 1998, EPPS purchased a 100 percent interest in a 150 MW natural
gas-fired combined cycle electric generation facility in Brush, Colorado ("Brush
I"). Brush I consists of two natural gas turbines, which currently operate
alternately, and a steam turbine. The gas and steam turbines together generate
electricity and provide radiant heating for a greenhouse complex.
During 1998, EPPS activities were included with Corporate operations. As
EPPS operations increase, they may be reported as a separate business segment or
combined with El Paso Energy Marketing segment.
As a result of the Merger, the Company holds certain limited assets and is
responsible for certain liabilities of EPTPC's existing and discontinued
operations and businesses. In addition, the Company, through its corporate and
other segment, performs management, legal, financial, tax, consultative,
administrative and other services for the operating business segments of the
Company.
ENVIRONMENTAL
A description of the Company's environmental activities is included in Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operations, and is incorporated by reference herein.
EMPLOYEES
The Company had approximately 3,600 full-time employees on December 31,
1998. The Company has no collective bargaining arrangements and no significant
changes in the workforce have occurred since December 31, 1998. During 1997, the
Company reduced its workforce by approximately 800 employees as a result of a
program to streamline operations and reduce operating costs in connection with
the acquisition of EPTPC.
11
<PAGE> 26
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPEC as of March 10, 1999, are set forth below.
For dates prior to
August 1, 1998 (the date of the holding company reorganization), references to
positions held with EPEC refer instead to positions held with EPNG.
<TABLE>
<CAPTION>
OFFICER
NAME OFFICE SINCE AGE
---- ------ ------- ---
<S> <C> <C> <C>
William A. Wise.............. Chairman of the Board, President, and Chief 1983 53
Executive Officer of EPEC
H. Brent Austin.............. Executive Vice President and Chief Financial 1992 44
Officer of EPEC
Joel Richards III............ Executive Vice President of EPEC 1990 52
Britton White, Jr............ Executive Vice President and General Counsel 1991 55
of EPEC
Mark A. Searles.............. Senior Vice President of EPEC 1995 42
Richard Owen Baish........... President of EPNG 1987 52
John D. Hushon............... President of EPEI 1996 53
Greg G. Jenkins.............. President of EPEM 1996 41
Robert G. Phillips........... President of EPFS 1995 44
John W. Somerhalder II....... President of TGP 1990 43
</TABLE>
Mr. Wise has been Chairman of the Board since January 1994 and Chief
Executive Officer since January 1990. In July 1998, Mr. Wise also became the
President of the Company. He was President of EPEC from April 1989 to April
1996. From March 1987 until April 1989, Mr. Wise was an Executive Vice President
of EPEC. From January 1984 to February 1987, he was a Senior Vice President of
EPEC. Mr. Wise is a member of the Board of Directors of Battle Mountain Gold
Company and is the Chairman of the Board of EPNG, EPTPC, and Leviathan Gas
Pipeline Company, the general partner of Leviathan.
Mr. Austin has been Executive Vice President of EPEC since May 1995. He has
been Chief Financial Officer of EPEC since April 1992. He was Senior Vice
President of EPEC from April 1992 to April 1995. He was Vice President, Planning
and Treasurer of Burlington Resources Inc. ("BR") from November 1990 to March
1992 and Assistant Vice President, Planning of BR from January 1989 to October
1990.
Mr. Richards has been Executive Vice President of EPEC since December 1996.
From January 1991 until December 1996, he was Senior Vice President of EPEC. He
was Vice President from June 1990 to December 1990. He was Senior Vice
President, Finance and Human Resources of Meridian Minerals Company, a wholly
owned subsidiary of BR, from October 1988 to June 1990.
Mr. White has been Executive Vice President of EPEC since December 1996 and
General Counsel of EPEC since March 1991. He was Senior Vice President and
General Counsel of EPEC from March 1991 until December 1996. From March 1991 to
April 1992, he was also Corporate Secretary of EPEC. For more than five years
prior to that time, Mr. White was a partner in the law firm of Holland & Hart.
Mr. Searles has been Senior Vice President of EPEC since April 1998. He was
Executive Vice President of EPEM from June 1997 to June 1998. He was President
of EPFS from December 1996 to June 1997 and was President of EPEM from September
1995 to December 1996. From March 1994 to September 1995, Mr. Searles was
President and Chief Operating Officer of Eastex Energy, Inc. For more than five
years prior to that he held various management positions with Enron Corp.
Mr. Baish has been President of EPNG since April 1996. From September 1994
until April 1996, he was Executive Vice President of EPNG and was Senior Vice
President from November 1990 to August 1994. He was General Counsel and
Corporate Secretary from November 1990 to December 1990 and Vice President and
Associate General Counsel from March 1987 to October 1990.
12
<PAGE> 27
Mr. Hushon has been President of EPEI since April 1996. He was Senior Vice
President of EPEI from September 1995 to April 1996. For more than five years
prior to that time, Mr. Hushon was a senior partner in the law firm of Arent Fox
Kintner Plotkin & Kahn.
Mr. Jenkins has been President of EPEM since December 1996. He was Senior
Vice President and General Manager of Entergy Corp. from May 1996 to December
1996 and President and Chief Executive Officer of Hadson Gas Services Company
from December 1993 to January 1996. For more than five years prior to that time,
Mr. Jenkins was in various managerial positions with Santa Fe Energy Resources,
Inc.
Mr. Phillips has been President of EPFS since June 1997. He was President
of El Paso Energy Resources Company from December 1996 to June 1997, President
of EPFS from April 1996 to December 1996 and was a Senior Vice President of EPEC
from September 1995 to April 1996. For more than five years prior to that time,
Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.
Mr. Somerhalder has been President of TGP since December 1996. He was
President of El Paso Energy Resources Company from April 1996 to December 1996
and Senior Vice President of EPEC from August 1992 to April 1996. From January
1990 to July 1992, he was Vice President of EPEC.
Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
ITEM 2. PROPERTIES
A description of the Company's properties is included in Item 1, Business
and is incorporated by reference herein.
The Company is of the opinion that it has generally satisfactory title to
the properties owned and used in its businesses, subject to the liens for
current taxes, liens incident to minor encumbrances, and easements and
restrictions that do not materially detract from the value of such property or
the interests therein or the use of such properties in its businesses. The
Company believes that its physical properties are adequate and suitable for the
conduct of its business in the future.
ITEM 3. LEGAL PROCEEDINGS
See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, Commitments and Contingencies, Legal Proceedings which is
incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
13
<PAGE> 28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
EPEC's common stock is traded on the New York Stock Exchange. As of March
5, 1999, the number of holders of record of common stock was approximately
72,000. This does not include individual participants on whose behalf a clearing
agency, or its nominee, holds EPEC's common stock.
The following table reflects the high and low sales prices for EPEC's
common stock for the periods indicated based on the daily composite listing of
stock transactions for the New York Stock Exchange and cash dividends declared
during those periods.
<TABLE>
<CAPTION>
HIGH LOW DIVIDENDS
-------- -------- ---------
(PER SHARE)
<S> <C> <C> <C>
1998
First Quarter....................................... $35.6250 $31.1250 $0.19125
Second Quarter...................................... 38.9375 35.4375 0.19125
Third Quarter....................................... 38.6250 24.6875 0.19125
Fourth Quarter...................................... 36.8125 30.1250 0.19125
1997
First Quarter....................................... $28.5000 $24.4375 $0.18250
Second Quarter...................................... 30.3125 27.1250 0.18250
Third Quarter....................................... 30.3436 26.5000 0.18250
Fourth Quarter...................................... 33.7500 28.8750 0.18250
</TABLE>
In January 1999, the Board declared a quarterly dividend of $0.20 per share
on EPEC's common stock, payable on April 1, 1999, to stockholders of record on
March 5, 1999. The declaration of future dividends will be dependent upon
business conditions, earnings, the cash requirements of EPEC, and other relevant
factors.
In January 1998, the Board declared a two-for-one stock split in the form
of a 100 percent stock dividend (on a per share basis). In March 1998, the
stockholders approved an increase in the Company's authorized common stock,
which was necessary to effect the stock split. The stock dividend was paid on
April 1, 1998 to stockholders of record on March 13, 1998. All presentations
herein are made on a post-split basis. Separately, the Board also approved a new
10 million common stock repurchase authority that replaced the repurchase
authority approved by the Board in November 1994. The timing and amount of
additional share repurchases, if any, will depend upon the availability and
alternate uses of capital, market conditions and other factors.
EPEC has made available a continuous odd-lot stock sales program (the
"Program"), in which stockholders of EPEC owning beneficially fewer than 100
shares of EPEC's common stock ("Odd-Lot-Holders") are offered a convenient
method of disposing of all their shares without incurring any brokerage costs
associated with the sale of an odd-lot. Only Odd-Lot Holders are eligible to
participate in the Program. The Program is strictly voluntary, and no Odd-Lot
Holder is obligated to sell pursuant to the Program. A brochure and related
materials describing the Program were sent to Odd-Lot Holders in February 1994.
The Program currently does not have a termination date, but EPEC may suspend the
Program at any time. Inquiries regarding the Program should be directed to
Boston EquiServe.
EPEC has made available a dividend reinvestment and common stock purchase
plan (the "Plan"), which provides all stockholders of record a convenient and
economical means of increasing their holdings in EPEC's common stock. A
stockholder who owns shares of common stock in street name or broker name and
who wishes to participate in the Plan will need to have his or her broker or
nominee transfer the shares into the stockholder's name. The Plan is strictly
voluntary, and no stockholder of record is obligated to participate in the Plan.
The Plan currently does not have a termination date, but EPEC may suspend the
Plan at any time. Inquiries regarding the Plan should be directed to Boston
EquiServe.
14
<PAGE> 29
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1998 1997 1996 1995 1994
-------- ------- ------- -------- -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Operating Results Data(a):
Operating revenues.................................. $5,782 $5,638 $3,012 $1,038 $ 870
Employee separation and asset impairment
charge(b)........................................ -- -- 99 -- --
Net income.......................................... 225 186 38 85 90
Basic earnings per common share(b).................. 1.94 1.64 .53 1.24 1.23
Diluted earnings per common share................... 1.85 1.59 .52 1.24 1.23
Cash dividends declared per common share............ .76 .73 .70 .66 .61
Basic average common shares outstanding............. 116 114 72 69 73
Diluted average common shares outstanding........... 126 117 73 69 73
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------
1998 1997 1996 1995 1994
------- ------ ------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Financial Position Data(a):
Total assets....................................... $10,069 $9,532 $8,843 $2,535 $2,332
Long-term debt..................................... 2,552 2,119 2,215 772 779
Preferred stock of subsidiary...................... 300 300 296 -- --
Other minority interest............................ 65 65 39 -- --
Stockholders' equity............................... 2,108 1,959 1,638 712 710
</TABLE>
- ---------------
(a) Reflects the acquisition in September 1995 of Eastex Energy, Inc., in
December 1995 of Premier Gas Company, in June 1996 of Cornerstone Natural
Gas, Inc., in December 1996 of EPTPC, and in August 1998 of DeepTech. All
acquisitions were accounted for as purchases and therefore operating results
are included prospectively from the date of acquisition.
(b) Reflects a charge in 1996 of $99 million pre-tax ($60 million after tax) to
reflect costs associated with the implementation of a workforce reduction
plan and the impairment of certain long-lived assets. Basic earnings per
common share for the year ended December 31, 1996 before giving effect to
this charge and an $8 million pre-tax ($5 million after tax) charge taken in
the fourth quarter for relocating the corporate headquarters from El Paso,
Texas to Houston, Texas in connection with the acquisition of EPTPC, would
have been $1.43 (compared to $0.53).
15
<PAGE> 30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
For the past four years, the Company has engaged in numerous activities and
transactions designed to significantly improve its ability to compete
effectively in the rapidly evolving world energy industry. In late 1995, the
Company acquired two energy marketing businesses, Eastex Energy Inc. and Premier
Gas Company. During the first quarter of 1996, the Company completed its
organizational review and workforce reduction program, reducing the total
workforce from 2,400 to about 1,600. During May 1996, the Company completed and
placed in service the Chaco Plant, the largest facility of its kind in the
continental U.S. In June 1996, the Company acquired Cornerstone Natural Gas,
Inc., expanding its gathering and processing operations into Louisiana and East
Texas. The Company completed its $4 billion acquisition of EPTPC in December
1996, expanding its natural gas pipeline systems from coast to coast and
continuing the expansion of the non-regulated business operations. In connection
with the EPTPC acquisition, the Company completed a workforce reduction program
in the first quarter of 1997, reducing the workforce of the combined companies
by approximately 800 from about 4,300 following the acquisition of EPTPC to
about 3,500. In late 1997, the Company acquired additional natural gas gathering
and processing assets by completing the purchases of Gulf States Gas Pipeline
Company and certain Texas Gulf Coast subsidiaries of PacifiCorp ("TPC"). In
August 1998, the Company acquired DeepTech. Additionally, throughout 1996, 1997
and 1998, the Company's international operations were expanding into Latin and
South America, the Asia Pacific region, Australia, and Europe.
These changes in the make-up of the Company significantly increased the
Company's operating results, its ability to generate operating cash flows and
its needs for cash for investment opportunities. Consequently, the Company's
credit facilities were substantially expanded during this period to meet those
needs.
The Company adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, effective January 1, 1998.
Accordingly, the Company has segregated its business activities into five
segments: Tennessee Gas Pipeline segment, El Paso Natural Gas segment, El Paso
Field Services segment, El Paso Energy Marketing segment, and El Paso Energy
International segment. These segments are strategic business units that offer a
variety of different energy products and services. They are managed separately
as each business segment requires different technology and marketing strategies.
Certain business segments' earnings are largely derived from the earnings of
equity investments. Accordingly, the Company evaluates segment performance based
on EBIT.
HOLDING COMPANY REORGANIZATION AND TAX-FREE INTERNAL REORGANIZATION
Effective August 1, 1998, the Company reorganized into a holding company
organizational structure, whereby EPEC, a Delaware corporation, became the
parent holding company. See Item 8, Financial Statements and Supplementary Data,
Note 1, for further discussion of the holding company reorganization. On
December 31, 1998, the Company completed a tax-free internal reorganization of
its assets and operations and those of its subsidiaries in accordance with a
private letter ruling received from the IRS. In the reorganization, a
substantial number of subsidiaries were transferred to or from the Company
and/or other entities owned by the Company. Neither the creation of the holding
company structure nor the tax-free internal reorganization had any impact on the
presentation herein.
RESULTS OF OPERATIONS
Consolidated EBIT for the year ended December 31, 1998, increased 11
percent to $644 million compared to $578 million in the year ago period.
Consolidated EBIT for the year ended December 31, 1997, was $403 million higher
than for the same period of 1996. Variances are discussed in the segment results
below.
16
<PAGE> 31
SEGMENT RESULTS
To the extent practicable, results of operations for 1997 and 1996 have
been reclassified to conform to the current business segment presentation,
although such results are not necessarily indicative of the results which would
have been achieved had the revised business segment structure been in effect
during those periods. Operating revenues and expenses by segment include
intersegment sales and expenses which are eliminated in consolidation. Because
of energy commodity price volatility, the Company believes that gross margin
(revenue less cost of sales), rather than operating revenue, provides a more
accurate indicator for the El Paso Field Services and the El Paso Energy
Marketing segments. For a further discussion of the individual segments, see
Item 8, Financial Statements and Supplementary Data, Note 13.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Tennessee Gas Pipeline...................................... $ 358 $ 318 $ 16
El Paso Natural Gas......................................... 217 260 223
----- ----- -----
Regulated segments........................................ 575 578 239
----- ----- -----
El Paso Field Services...................................... 75 74 35
El Paso Energy Marketing.................................... 9 (28) 24
El Paso Energy International................................ 25 2 (4)
----- ----- -----
Non-regulated segments.................................... 109 48 55
----- ----- -----
Corporate expenses, net..................................... (40) (48) (119)
----- ----- -----
Consolidated EBIT......................................... $ 644 $ 578 $ 175
===== ===== =====
</TABLE>
TENNESSEE GAS PIPELINE
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues.......................................... $ 766 $ 798 $ 48
Operating expenses.......................................... (434) (494) (34)
Other -- net................................................ 26 14 2
----- ----- -----
EBIT...................................................... $ 358 $ 318 $ 16
===== ===== =====
</TABLE>
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $32 million
lower than for the same period of 1997 primarily because of lower throughput
resulting from warmer average temperatures in the northeastern and midwestern
markets and a downward revision in the amount of recoverable interest on GSR
costs.
Operating expenses for the year ended December 31, 1998, were $60 million
lower than for the same period of 1997 primarily due to lower system fuel usage
associated with operating efficiencies attained during the period of lower
throughput, reduced operation and maintenance expenses largely due to lower
payroll costs, and lower franchise taxes.
Other -- net for the year ended December 31, 1998, was $12 million higher
than for the same period of 1997 due to interest income on a favorable sales and
use tax settlement and gains on the sale of assets.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
The results of operations for 1996 represents EPEC's ownership of this
segment for 20 days after the EPTPC Merger in December 1996.
Operating revenues for the year ended December 31, 1997, were $750 million
higher than for the same period of 1996 due to the acquisition of EPTPC in
December 1996.
17
<PAGE> 32
Operating expenses for the year ended December 31, 1997, were $460 million
higher than for the same period of 1996 due to the acquisition of EPTPC in
December 1996.
Other -- net for the year ended December 31, 1997, was $12 million higher
than for the same period of 1996 due to the acquisition of EPTPC in December
1996.
EL PASO NATURAL GAS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues.......................................... $ 475 $ 520 $ 511
Operating expenses.......................................... (260) (265) (302)
Other -- net................................................ 2 5 14
----- ----- -----
EBIT...................................................... $ 217 $ 260 $ 223
===== ===== =====
</TABLE>
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $45 million
lower than for the same period of 1997 primarily due to lower net revenues
resulting from the PG&E contract expiration which was effective December 31,
1997. The decrease in revenues from the loss of the PG&E contract was
significantly offset by risk sharing revenue, other non-traditional revenues
including revenue from the sale of capacity to Dynegy, and the favorable
resolution of a contested rate matter. (See Commitments and Contingencies, Rates
and Regulatory Matters, below for a discussion of the Dynegy contracts.)
Operating expenses for the year ended December 31, 1998, were $5 million
lower than for the same period of 1997 primarily due to lower fuel costs and
recovery of a receivable previously deemed uncollectible. Partially offsetting
the decrease were higher operating and depreciation expenses.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Operating revenues for the year ended December 31, 1997, were $9 million
higher than for the same period of 1996 primarily due to higher accruals for
take-or-pay issues in 1996 and an increase in non-traditional revenues
associated with a system expansion. This increase was partially offset by lower
revenues resulting from contract expirations occurring in late 1996 and early
1997.
Operating expenses for the year ended December 31, 1997, were $37 million
lower than for the same period of 1996 primarily due to lower labor, benefits,
and payroll tax expenses in 1997 which resulted from a reduction in staffing
levels during 1996.
Other -- net for the year ended December 31, 1997, was $9 million lower
than for the same period of 1996 due to gains on the disposition of assets in
1996.
EL PASO FIELD SERVICES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Gathering and treating margin............................... $ 150 $ 119 $ 87
Processing margin........................................... 48 55 46
Other margin................................................ 3 6 1
----- ----- -----
Total gross margin................................ 201 180 134
Operating expenses.......................................... (141) (114) (99)
Other -- net................................................ 15 8 --
----- ----- -----
EBIT...................................................... $ 75 $ 74 $ 35
===== ===== =====
</TABLE>
18
<PAGE> 33
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total gross margin for the year ended December 31, 1998, was $21 million
higher than for the same period of 1997. The increase in the gathering and
treating margin primarily resulted from higher gathering rates compared to 1997,
an increase in gathering and treating volumes largely attributable to the
acquisition of TPC in December 1997, and the inclusion of the results of
operations of Channel Pipeline ("Channel"), in El Paso Field Services segment
beginning January 1998 versus El Paso Energy Marketing segment. The decrease in
the processing margin was largely attributable to lower liquids prices during
1998 compared to the same period of 1997. Liquids prices directly impact EPFS's
processing revenues. During 1998, liquids prices were at their lowest level
since 1990, and the Company expects this trend to continue through 1999. The
Company attempts to mitigate the impact of lower liquids prices by utilizing
hedging strategies where possible.
Operating expenses for the year ended December 31, 1998, were $27 million
higher than for the same period of 1997 primarily as a result of additional
expenses associated with the addition of TPC and Channel as well as higher
general and administrative expenses.
Other -- net for the year ended December 31, 1998, was $7 million higher
than for the same period of 1997 reflecting higher earnings from equity
investments and higher capitalized interest.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Total gross margin for the year ended December 31, 1997, was $46 million
higher than for the same period of 1996. The increase in the gathering and
treating margin and the processing margin was primarily the result of higher
natural gas prices in the San Juan Basin and an increase in gathering and
treating volumes due to the acquisitions of EPTPC in December 1996 and
Cornerstone Natural Gas, Inc. in June 1996.
Operating expenses for the year ended December 31, 1997, were $15 million
higher than for the same period of 1996 primarily due to the acquisition of
EPTPC and Cornerstone Natural Gas, Inc.
Other -- net for the year ended December 31, 1997, was $8 million higher
than for the same period of 1996 primarily due to the acquisition of EPTPC.
EL PASO ENERGY MARKETING
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Natural gas margin.......................................... $ 26 $ 25 $ 46
Power margin................................................ 16 -- (3)
Petroleum products margin................................... 1 (3) 3
---- ---- ----
Total gross margin................................ 43 22 46
Operating expenses.......................................... (38) (53) (23)
Other -- net................................................ 4 3 1
---- ---- ----
EBIT...................................................... $ 9 $(28) $ 24
==== ==== ====
</TABLE>
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total gross margin for the year ended December 31, 1998, was $21 million
higher than for the same period of 1997. Increases in total gross margin in 1998
reflect a fundamental shift in focus initiated by the energy marketing business
segment from a short-term positional trading operation to a long-term,
asset-based origination, trading, and risk management operation. In 1998, such
energy activities emphasized long-term power and gas contract management and
related energy services for power and natural gas customers, including
independent power producers, utilities and end users. Trading activities, while
substantially increasing in volume in 1998, are primarily used to manage risk in
long-term contract positions. Partially offsetting the increase in gross margin
was the impact of reporting the operations of Channel in El Paso Field Services
segment versus El Paso Energy Marketing segment beginning in January 1998.
19
<PAGE> 34
Operating expenses for the year ended December 31, 1998, were $15 million
lower than for the same period of 1997. The decrease was attributable to the
1997 restructuring of the marketing organization following the EPTPC acquisition
and the transfer of Channel operations as mentioned above.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Total gross margin for the year ended December 31, 1997, was $24 million
lower than for the same period of 1996. The decrease resulted from generally
lower industry-wide gas marketing margins in the second quarter of 1997, as well
as extreme market volatility which negatively impacted the Company's natural gas
marketing activities and trading positions during the first quarter of 1997.
Operating expenses for the year ended December 31, 1997, were $30 million
higher than for the same period of 1996 primarily due to the costs associated
with the marketing activities of EPTPC which were acquired in December 1996.
EL PASO ENERGY INTERNATIONAL
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues.......................................... $ 58 $ 13 $--
Operating expenses.......................................... (86) (37) (3)
Other -- net................................................ 53 26 (1)
---- ---- ---
EBIT...................................................... $ 25 $ 2 $(4)
==== ==== ===
</TABLE>
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $45 million
higher than for the same period of 1997 due to the consolidation for financial
reporting purposes of the Manaus Power project in May 1998 after acquiring an
additional ownership interest and an increase in revenue attributable to the EMA
Power project which the Company began reporting on a consolidated basis in July
1997.
Operating expenses for the year ended December 31, 1998, were $49 million
higher than for the same period of 1997 primarily due to costs related to the
consolidation of the EMA Power and Manaus Power projects and increased general
and administrative expenses largely due to higher project development costs
reflecting an increase in project-related activities in 1998.
Other -- net for the year ended December 31, 1998, was $27 million higher
than for the same period of 1997 primarily due to increased equity earnings, a
gain on the sale of surplus power equipment, and the recognition of certain net
gains from project-related activities.
As EPEI's projects move from the development stage to the operational
stage, it is common to recognize one-time gains and fees, which may include
management fees, development fees, financing fees, and gains on the sell-down of
ownership interests. The Company anticipates additional one-time events may
result in the recognition of income or expense in the future.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
EBIT for the year ended December 31, 1997, was $6 million higher than for
the same period of 1996. During 1997, EPEI completed its first full year of
operations following the EPTPC acquisition, which represented a significant
increase in international project development activities. Because of this
increase in development activities, operating results likewise increased
substantially over 1996.
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<PAGE> 35
CORPORATE EXPENSES, NET
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Net corporate expenses for the year ended December 31, 1998, were $8
million lower than for the same period of 1997. The decrease results from lower
benefits costs and non-recurring gains, partially offset by administrative costs
associated with the formation and startup of EPPS, a power services group
established in the first quarter of 1998, and costs associated with the
Company's Year 2000 project.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Net corporate expenses for the year ended December 31, 1997, were $71
million lower than for the same period of 1996 primarily as a result of a $99
million employee separation and asset impairment charge recorded in the first
quarter of 1996 and an $8 million charge in the fourth quarter of 1996 for
relocating the Company's headquarters from El Paso, Texas to Houston, Texas in
connection with the acquisition of EPTPC. The decrease was partially offset by
additional costs related to the discontinued operations assumed as part of the
EPTPC acquisition.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Interest and debt expense for the year ended December 31, 1998, was $29
million higher than for the same period of 1997 primarily because of increased
borrowings to fund capital expenditures, acquisitions, and other investing
expenditures and a higher average effective interest rate during 1998 generally
resulting from the higher rates associated with the March 1997 issuance of TGP
long-term debt of approximately $883 million. These increases were partially
offset by higher interest expense in 1997 incurred on rate refunds paid to
EPNG's customers in 1998.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Interest and debt expense for the year ended December 31, 1997, was $128
million higher than for the same period of 1996 due primarily to the level of
debt assumed in connection with the acquisition of EPTPC and the Company's debt
and capital realignment efforts.
INCOME TAX EXPENSE
The effective tax rate for 1998 was 34 percent compared to 38 percent in
1997 and 1996. The lower rate in 1998 is due to an increase in the level of
foreign income in 1998, which is subject to foreign tax rates that differ from
U.S. tax rates, increases in permanently reinvested equity income from
unconsolidated foreign affiliates for which no provision for U.S. income tax is
required, and lower state income taxes.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $61 million lower for the
year ended December 31, 1998, compared to the same period of 1997. The decrease
was primarily attributable to working capital changes, a take-or-pay refund paid
to EPNG's customers in February 1998, lower GSR collections in 1998, and
prepayments of risk sharing revenues in 1997. The decrease was partially offset
by higher net tax refunds in 1998 and rate refunds paid to TGP's customers in
March 1997 and EPNG's customers in August 1997.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was approximately $1 billion for the
year ended December 31, 1998. Investment activities included the August 1998
acquisition of DeepTech (see Item 8, Financial Statements and Supplementary
Data, Note 2), as well as expenditures for joint ventures, equity investments,
and
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<PAGE> 36
expansion and construction projects. Expenditures related to joint ventures and
equity investments were primarily attributable to the EPEI segment. Internally
generated funds, supplemented by other financing activities, were used to fund
these expenditures.
The Company's planned capital and investment expenditures for 1999 of
approximately $900 million are primarily for expansion of international
operations and domestic unregulated operations, pipeline systems activities and
other facilities, and computer and communication system enhancements.
Funding for capital expenditures, acquisitions, and other investing
expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
CASH FROM FINANCING ACTIVITIES
Net cash provided by financing activities was $463 million for the year
ended December 31, 1998. In March 1998, Trust Convertible Preferred Securities
were issued (see Item 8, Financial Statements and Supplementary Data, Note 3)
for net proceeds of $317 million. In October 1998, TGP issued debentures due
2028 for net proceeds of $391 million. These proceeds, supplemented by
internally generated funds, were used to retire long-term debt, pay dividends,
acquire treasury stock, fund capital and equity investments, and for other
corporate purposes.
Since November 1994, the Company has been authorized by the Board to
repurchase shares of its common stock. Shares repurchased are held in EPEC's
treasury and are expected to be used in conjunction with EPEC stock compensation
plans and for other corporate purposes. Pursuant to the November 1994
authorization, the Company had repurchased 9.4 million shares as of December 31,
1997. In January 1998, the Board approved a new 10 million common stock
repurchase authority that replaced the November 1994 repurchase authority. The
10 million share repurchase authority reflects the two-for-one stock split as
discussed in Item 5, Market for Registrant's Common Equity and Related
Stockholder Matters. In 1998, the Company repurchased 995,600 common shares at a
weighted average cost of $35.77 per share. The timing and amount of future share
repurchases, if any, will depend upon the availability and alternate uses of
capital, market conditions and other factors.
Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
LIQUIDITY
The Company relies on cash generated from internal operations as its
primary source of liquidity, supplemented by its available credit facilities and
commercial paper program. In October 1997, EPNG established a new $750 million
five-year revolving credit and competitive advance facility and a new $750
million 364-day renewable revolving credit and competitive advance facility
(collectively, the "Revolving Credit Facility"). In connection with the
establishment of the Revolving Credit Facility, EPTPC's revolving credit
facility was also terminated, and the outstanding balance of $417 million was
financed under the five-year portion of the new Revolving Credit Facility with
TGP designated as the borrower. The availability under the Revolving Credit
Facility is expected to be used for general corporate purposes including, but
not limited to, backstopping EPNG's and TGP's $1 billion commercial paper
programs.
In August 1998, EPEC became a guarantor of EPNG's Revolving Credit
Facility. In October 1998, the $750 million 364-day portion of the Revolving
Credit Facility was amended to extend the termination date to October 27, 1999.
In addition, in October 1998, the Revolving Credit Facility was amended to
permit TGP to issue commercial paper, provided that the total amount of
commercial paper outstanding at EPNG and TGP is equal to or less than the unused
capacity under the Revolving Credit Facility. In December 1998, EPEC became a
borrower under the Revolving Credit Facility. The interest rate on the Revolving
Credit Facility is 40 basis points above LIBOR, with the spread varying based on
EPEC's long-term debt credit rating.
The availability of borrowings under the Company's credit agreements is
subject to specified conditions, which management believes the Company currently
meets. These conditions include compliance with the
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<PAGE> 37
financial covenants and ratios required by such agreements, absence of default
under such agreements, and continued accuracy of the representations and
warranties contained in such agreements (including the absence of any material
adverse changes since the specified dates).
All of the Company's senior debt issues have been given investment grade
ratings by Standard & Poors and Moody's. The Company must comply with various
restrictive covenants contained in its debt agreements which include, among
others, maintaining a consolidated debt and guarantees to capitalization ratio
no greater than 70 percent. In addition, the Company's subsidiaries on a
consolidated basis (as defined in the agreements) may not incur debt obligations
which would exceed $300 million in the aggregate, excluding acquisition debt,
project financing, and certain refinancings. As of December 31, 1998, EPEC's
consolidated debt and guarantees to capitalization ratio (as defined in the
agreements) was 55 percent and debt obligations of EPEC subsidiaries in excess
of permitted debt did not exceed $300 million on a consolidated basis.
In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2%
debentures due 2017, $300 million aggregate principal amount of 7% debentures
due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due
2037. Proceeds of approximately $883 million, net of issuance costs, were used
to repay a portion of EPTPC's credit facility and for general corporate
purposes.
In December 1997, EPEC filed a shelf registration statement pursuant to
which EPEC may offer up to $900 million (including $250 million transferred from
prior shelf registrations) of common or preferred equities, various forms of
debt securities (including convertible debt securities), and various types of
trust securities from time to time as determined by market conditions. In March
1998, the El Paso Energy Capital Trust I, a Delaware business trust sponsored by
the Company, issued 6.5 million 4 3/4% Trust Convertible Preferred Securities.
The sole assets of the trust are approximately $335 million principal amount of
4 3/4% convertible subordinated debentures due 2028 of the Company. As a result
of such offering, EPEC has approximately $565 million of capacity remaining
under its existing shelf registration to issue public securities registered
thereunder.
In September 1998, TGP filed a shelf registration permitting TGP to offer
up to $600 million (including $100 million carried forward from a prior shelf
registration) of debt securities. In October 1998, TGP issued $400 million
aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were
approximately $391 million, net of issuance cost. Approximately $300 million of
the proceeds were used to repay TGP's short-term indebtedness under the
Revolving Credit Facility and the remainder were used by TGP for general
corporate purposes. After this issuance, TGP has $200 million of capacity
remaining under its shelf registration.
In March 1998, EPNG retired its outstanding 8 5/8% debentures in the amount
of $17 million and in August 1998, EPTPC retired its outstanding 10% debentures
in the amount of $38 million. In February 1999, DeepTech retired its 11% senior
subordinated promissory note due 2000 in the amount of $16 million.
COMMITMENTS AND CONTINGENCIES
Indonesia
The Company owns a 47.5 percent 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 significantly increased. PLN is currently
unable to pass this increase in cost on to its customers without creating
further political instability. 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, with a commitment to pay the balance when financial aid is
received. The difference between the current and prior exchange rate has
resulted in an outstanding balance due from PLN of $9.4 million at December 31,
1998. The Company continues to meet with PLN on a regular basis to resolve the
payment in arrears issue but has been unsuccessful to date. Recently, the
Company has met and discussed its situation and concerns with the World
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<PAGE> 38
Bank, the International Monetary Fund, the Overseas Private Investment
Corporation, and the U.S. Treasury Department in an attempt to achieve a
resolution through the Indonesian Minister of Finance. The Company will meet
with PLN in April 1999 to discuss payments in arrear and the terms of a contract
rationalization process proposed by PLN. The Company has informed PLN that all
payments in arrear must first be received as a prerequisite to any further
discussions on contract rationalization. The Company cannot predict with
certainty the outcome of such discussions. The Company's total investment in the
Sengkang project was approximately $25 million at December 31, 1998.
Additionally, the Company has provided specific recourse guarantees of up to $6
million for loans from the project lenders. All other project debt is
non-recourse. 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 250 MW power plant in Manaus, Brazil.
Power from the plant is currently sold under a four-year contract to
Electronorte, denominated in Brazilian real. Due to the devaluation of the real
in January 1999, Manaus suffered an $831,000 exchange loss on the December
invoice. There is no provision in the contract to recover the effects of the
devaluation on this invoice. However, future invoices are covered under a
provision in the contract entitling the Company to recover a substantial portion
of any future devaluation. 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.
The contract for the Manaus power project provides for delay damages to be
paid to Electronorte if the specified construction schedule was not met.
Completion of the project was delayed beyond the originally scheduled completion
dates provided in the contract and such delays have resulted in a claim by
Electronorte for delay damages. The Company is in discussions with Electronorte
regarding such claim. In any event, the Company has the right under its
construction contract to assert claims against the construction contractor for
such delay damages and believes that any such damages will not have a material
adverse effect on the Company's financial position, results of operations, or
cash flows.
Capital Commitments
At December 31, 1998, the Company had capital and investment commitments of
$245 million, which are expected to be funded through internally generated funds
and/or incremental borrowings. The Company's other planned capital and
investment projects are discretionary in nature, with no substantial capital
commitments made in advance of the actual expenditures.
Purchase Obligations
In connection with the financing commitments of certain joint ventures, TGP
has entered into unconditional purchase obligations for products and services
totaling $77 million at December 31, 1998. TGP's annual obligations under these
agreements are $21 million for the years 1999 and 2000, $11 million for the year
2001, $4 million for the years 2002 and 2003, and $16 million in total
thereafter. Excluded from these amounts is TGP's obligation to purchase 30
percent of the output of the Great Plains coal gasification project's original
design capacity through July 2009. In January 1997, TGP executed a settlement of
this contract as part of its GSR negotiations, recorded the related liability,
and, in the third quarter of 1997, purchased an annuity for $42 million to fund
the expected remaining monthly demand requirements of the contract which, under
the settlement, continue through January 2004.
Operating Leases
The Company leases certain property, facilities and equipment under various
operating leases. In addition, in 1995, El Paso New Chaco Company ("EPNC")
entered into an unconditional lease for the Chaco Plant. The lease term expires
in 2002, at which time EPNC has an option, and an obligation upon the occurrence
of certain events, to purchase the plant for a price sufficient to pay the
amount of the $77 million
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<PAGE> 39
construction financing, plus interest and certain expenses. If EPNC does not
purchase the plant at the end of the lease term, it has an obligation to pay a
residual guaranty amount equal to approximately 87 percent of the amount
financed, plus interest. The Company unconditionally guaranteed all obligations
of EPNC under the lease.
Minimum annual rental commitments at December 31, 1998, were as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
<S> <C>
1999..................................................... $ 18
2000..................................................... 18
2001..................................................... 18
2002..................................................... 17
2003..................................................... 13
Thereafter............................................... 56
----
Total............................................. $140
====
</TABLE>
Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $15 million due in the future under noncancelable
subleases.
Rental expense for operating leases for the years ended December 31, 1998,
1997, and 1996 was $27 million, $23 million, and $14 million, respectively.
Guarantees
At December 31, 1998, the Company had parental guarantees of up to $486
million in connection with its international development activities, as well as
$181 million related to various other projects. The Company also had letters of
credit of approximately $80 million outstanding at December 31, 1998.
Rates and Regulatory Matters
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it seeks 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.
Comments on the NOPR and NOI are due in April 1999, and it is unclear when and
what action, if any, FERC will take in connection with the NOPR and NOI and the
comments received in response to them.
TGP -- 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 December 31, 1998, the demand portion had been fully collected
and $41 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
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<PAGE> 40
of TGP's customers. Under the terms of the GSR Stipulation and Agreement, TGP is
required to refund to customers amounts collected in excess of each customer's
share of transition costs.
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. Under
the stipulation, TGP's refund obligation was approximately $185 million,
inclusive of interest, of which $161 million was refunded to customers in March
1997 and June 1997 with the remaining $24 million refund obligation offset
against GSR recoveries in accordance with particular customer elections. TGP
provided a reserve for these rate refunds as revenues were collected. 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.
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 but clarifying that,
among other things, although the ultimate resolution as to the proper allocation
of costs would be applied retroactively to July 1, 1995, the cost of service
settlement does not allow TGP to recover from other customers any amounts that
TGP may ultimately be required to refund. In 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. Certain parties
have requested rehearing of that order, and the matter is currently pending
before FERC.
TGP has filed cash out reports for the period September 1993 through August
1998. TGP's filings showed a cumulative loss through August of 1998 of $3
million. TGP has reached a settlement in principle with its customers to resolve
outstanding FERC proceedings related to these filed cash out reports. The
reports, as well as the accounting for customer imbalances, had been challenged
by TGP's customers. Upon FERC's approval, the settlement will provide for a new
mechanism for accounting for TGP's cash out program.
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 be expiring over the next two years,
principally in 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.
EPNG -- In June 1995, EPNG filed with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In March 1996, EPNG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996, through December 31, 1997. In April 1997, FERC
approved EPNG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rates it
ultimately pays EPNG. In July 1997, FERC issued an order denying the requests
for rehearing of the April 1997 order and the settlement was implemented
effective July 1, 1997. Hearings to determine Edison's rates were completed in
May 1998, and an initial decision was issued by the presiding ALJ in July 1998.
EPNG and Edison have filed exceptions to the decision with FERC. If the ALJ's
decision is affirmed by FERC, EPNG believes that the resulting rates to Edison
would be such that no
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<PAGE> 41
significant, if any, refunds in excess of the amounts reserved would be
required. Pending the final outcome, Edison continues to pay the originally
filed rates, subject to refund, and EPNG continues to provide a reserve for such
potential refunds.
Edison filed with the Court of Appeals a petition for review of FERC's
April 1997 and July 1997 orders, in which it challenged the propriety of FERC's
approving the settlement over Edison's objections to the settlement as a
customer of SoCal. In December 1998, the Court of Appeals issued its decision
vacating and remanding FERC's order. EPNG will file a motion with FERC proposing
procedures to address deficiencies which the Court of Appeals found in FERC's
earlier orders. EPNG cannot predict the outcome with certainty, but it believes
that FERC will ultimately approve the settlement.
The rate settlement establishes, among other things, base rates through
December 31, 2005. Such rates escalate annually beginning in 1998. In addition,
the settlement provides for settling customers to (i) pay $295 million
(including interest) as a risk sharing obligation, which approximates 35 percent
of anticipated revenue shortfalls over an 8 year period, resulting from the
contract reductions and expirations referred to above, (ii) receive 35 percent
of additional revenues received by EPNG, above a threshold, for the same
eight-year period, and (iii) have the base rates increase or decrease if certain
changes in laws or regulations result in increased or decreased costs in excess
of $10 million a year. In accordance with the terms of the rate settlement,
EPNG's refund obligation (including interest) was approximately $194 million.
EPNG refunded $61 million to customers in August 1997 and, in accordance with
certain customers' elections, the remaining $133 million of refund obligation
was applied towards their $295 million risk sharing obligation. Through December
31, 1998, an additional $94 million of the risk sharing obligation was paid and
the remaining $68 million balance, including interest, will be collected by the
end of 2003. From 1996 through December 31, 1998, $69 million of the risk
sharing obligation had been recognized as revenue. The remaining unearned risk
sharing amounts, totaling $226 million, excluding interest, will be recognized
ratably through the year 2003.
In addition to other arrangements to offset the effects of the reduction in
firm capacity commitments referred to above, EPNG entered into three contracts
with Dynegy for the sale of substantially all of its turned back firm capacity
available to California as of January 1, 1998, (approximately 1.3 Bcf) for a
two-year period beginning January 1, 1998, at rates negotiated pursuant to
EPNG's tariff provisions and FERC policies. EPNG realized $29 million in revenue
in 1998 and anticipates realizing at least $41 million in revenues in 1999
(which are and will be subject to the revenue sharing provisions of the rate
settlement) for this capacity. The contracts have a transport-or-pay provision
requiring Dynegy to pay a minimum charge equal to the reservation component of
the contractual charge on at least 50 percent of the contracted volumes in each
month in 1998 and on at least 72 percent of the contracted volumes each month in
1999. In the third quarter of 1999, EPNG intends to remarket this capacity
pursuant to EPNG's tariff provisions and FERC regulations, subject to Dynegy's
right of first refusal.
In December 1997, EPNG filed to implement several negotiated rate
contracts, including those with Dynegy. In a protest to this filing, three
shippers (producers/marketers) requested that FERC require EPNG to eliminate
certain provisions from the Dynegy contracts, to publicly disclose and repost
the contracts for competitive bidding, and to suspend their effectiveness. In an
order issued in January 1998, FERC rejected several of the arguments made in the
protest and allowed the contracts to become effective as of January 1, 1998,
subject to refund, and to the outcome of a technical conference, which was held
in March 1998. In June 1998, FERC issued an order rejecting the protests to the
Dynegy contracts, but required EPNG to file modifications with FERC to the
contracts clarifying the credits under the reservation reduction mechanism and
the recall rights of certain capacity. In addition, EPNG agreed to separately
post capacity covered by the Dynegy contracts which becomes available in the
future. Several parties have protested EPNG's compliance filing and/or requested
rehearing of FERC's June 1998 order. In June 1998, EPNG filed a letter agreement
in compliance with the June 1998 FERC order. In September 1998, FERC issued an
order accepting the letter agreement subject to EPNG making additional
modifications. The additional modifications to the letter agreement required
further clarification of credits available to Dynegy under the reservation
reduction mechanism and the recall rights of certain capacity. In October 1998,
EPNG filed a revised letter agreement with FERC and requested rehearing of the
September 1998 order.
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<PAGE> 42
Under the revenue sharing provisions of its rate case settlement, EPNG is
obligated to return approximately $12 million of non-traditional revenues to
certain customers. Approximately $5 million had been credited to such customers'
transportation invoices at December 31, 1998, and the balance of the $7 million
has been or will be credited ratably over January, February, and March 1999. At
December 31, 1998, EPNG had a reserve for the $7 million.
Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. Certain parties
sought review in the Court of Appeals of FERC's determination in an October 1992
order that certain buy-down/buy-out costs were eligible for recovery. In January
1996, the Court of Appeals remanded the order to FERC with direction to clarify
the basis for its decision that the take-or-pay buy-down/buy-out costs were
eligible for recovery. In March 1997, following a technical conference and the
submission of statements of position and replies, FERC issued an order
determining that the costs related to all but one of EPNG's disputed contracts
were eligible for recovery. The costs ruled ineligible for recovery totaled
approximately $3 million, including interest, and were refunded to customers in
the second quarter of 1997. In October 1997, FERC issued an order denying the
challenging parties' request for rehearing of the March 1997 order in most
respects, but determined that the costs incurred pursuant to two additional EPNG
contracts were ineligible for recovery. These costs, including interest, totaled
approximately $9 million and were refunded to customers in February 1998. The
challenging parties, which claim that EPNG should be required to refund up to an
additional $31 million filed a petition for review of the FERC order in the
Court of Appeals. In February 1999, the Court of Appeals affirmed FERC's October
1997 order.
In November 1996, GPM Corporation filed a complaint, as amended, with FERC
alleging that EPNG's South Carlsbad compression facilities were gathering
facilities and were improperly functionalized by EPNG as transmission
facilities. In accordance with the FERC orders, the South Carlsbad compressor
facilities were transferred to EPFS in April 1998.
In a November 1997 order, FERC reversed its previous decision and found
that EPNG's Chaco Station should be functionalized as gathering, not
transmission, facility and should be transferred to EPFS. FERC has denied all
requests for rehearing. EPNG and two other parties filed petitions for review
with the Court of Appeals. The matter has been briefed and will be argued in
September 1999. In accordance with the FERC orders, the Chaco Station was
transferred to EPFS in April 1998.
FERC Compliance Audits
TGP and EPNG, as interstate pipelines, are subject to FERC audits of their
books and records. EPNG currently has an open audit covering the years 1990
through 1995. FERC is expected to issue its audit report in 1999. Both EPNG's
and TGP's property retirements are currently under review by the FERC audit
staff.
Management believes the ultimate resolution of the aforementioned rate and
regulatory 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 November 1993, TransAmerican filed a complaint in a Texas state court,
TransAmerican Natural Gas Corporation v. El Paso Natural Gas Company, et al.,
alleging fraud, tortious interference with contractual relationships, negligent
misrepresentation, economic duress, civil conspiracy, and violation of state
antitrust laws arising from a settlement agreement entered into by EPNG,
TransAmerican Natural Gas Corporation ("TransAmerican"), and others in 1990 to
settle litigation then pending and other potential claims. The complaint, as
amended, seeks actual damages of $1.5 billion and exemplary damages of $6
billion. EPNG is defending the matter in the State District Court of Dallas
County, Texas. In April 1996, a former employee of TransAmerican filed a related
case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al.
(including EPNG), seeking indemnification and other damages in unspecified
amounts relating to litigation consulting work allegedly performed for various
entities, including EPNG, in cases involving TransAmerican. EPNG filed a motion
for summary judgment in the TransAmerican case arguing that
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plaintiff's claims are barred by a prior release executed by TransAmerican, by
statutes of limitations, and by the final court judgment ending the original
litigation in 1990. Following a hearing in January 1998, the court granted
summary judgment in EPNG's favor on TransAmerican's claims based on economic
duress and negligent misrepresentation, but denied the motion as to the
remaining claims. In February 1998, EPNG filed a motion for summary judgment in
the Stone litigation arguing that all claims are baseless, barred by statutes of
limitations, subject to executed releases, or have been assigned to
TransAmerican. In June 1998, the court granted EPNG's motion in its entirety and
dismissed all the remaining claims in the Stone litigation. In August 1998, the
court denied Stone's motion for a new trial seeking reconsideration of that
ruling. Stone has appealed the court's ruling to the Texas Court of Appeals in
Houston, Texas. The TransAmerican trial is set to commence in September 1999.
Based on information available at this time, management believes that the claims
asserted against it in both cases have no factual or legal basis and 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 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 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 relevant states
regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies to specify the remediation
requirements at the Pennsylvania and New York stations. Remediation activities
in Pennsylvania are complete with the exception of some long-term groundwater
monitoring requirements. Remediation and characterization work at the compressor
stations under its consent order with the EPA and the jurisdiction of the New
York Department of Environmental Conservation is ongoing. 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
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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, both wholly owned and partially owned, as
well as Leviathan, have been named defendants in United States ex rel Grynberg
v. El Paso Natural Gas Company, et al. Generally, the complaint in this motion
alleges 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. The complaint remains sealed. The
Company believes the complaint to be without merit.
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 December 31, 1998, the Company had a reserve of
approximately $255 million for expected remediation costs and associated onsite,
offsite and groundwater technical studies of approximately $239 million; and
other costs of approximately $16 million which the Company anticipates incurring
through 2027.
In addition, the Company estimates that its subsidiaries will make capital
expenditures for environmental matters of approximately $6 million in 1999.
Capital expenditures will range from approximately $60 million to $85 million in
the aggregate for the years 2000 through 2007. These expenditures primarily
relate to compliance with air regulations and, to a lesser extent, control of
water discharges.
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 separate Stipulation and Agreement (the "Environmental Stipulation") that
establishes a mechanism for recovering a substantial portion of the
environmental costs identified in the internal project. In November 1995, FERC
issued an order approving the Environmental Stipulation. Although one shipper
filed for rehearing, FERC denied rehearing of its order in February 1996. The
Environmental Stipulation was effective July 1, 1995. As of December 31, 1998, a
balance of $2 million remains to be collected under the 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 30 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. As of December 31, 1998, the
Company has estimated its share of the remediation costs at these sites to be
between $62 million and $75 million and has provided reserves that it believes
are adequate for such 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
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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 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 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 reserve is
adequate.
For a further discussion of specific environmental matters, see Legal
Proceedings above.
OTHER
Acquisition of CE Generation LLC
In March 1999, EPPS purchased a 50 percent ownership interest in CE
Generation LLC. The equity investment in CE Generation LLC of approximately $260
million, subject to certain adjustments, will be accounted for under the equity
method. CE Generation LLC owns 12 power generation projects, which are
qualifying facilities under the Public Utility Regulatory Policy Act, and two
additional generating facilities currently under construction in southern
California. Collectively, the 14 power projects have a combined electric
generating capacity of approximately 896 MW and include ten geothermal projects
near the Imperial Valley in southern California and four natural gas-fired
cogeneration projects in New York, Pennsylvania, Texas and Arizona.
PPN Power Project
In March 1999, the Company signed a sale and purchase agreement to acquire
a 26 percent interest in a $295 million power plant in Tamil Nadu, India. The
project consists of a 346 MW 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. Transfer of
the funds to complete the acquisition is expected to be finalized by the end of
March 1999.
Acquisition of DeepTech
In August 1998, the Company completed its acquisition of DeepTech by
merging DeepTech with a subsidiary of EPEC. DeepTech's assets included a
combined 27.3 percent ownership interest in Leviathan. The acquisition was
accounted for as a purchase with a total purchase price, net of cash received,
of approximately $422 million. The Company recorded $214 million of goodwill in
connection with the acquisition which will be amortized using the straight-line
method over a period of 40 years. The amount allocated to goodwill is based on
the excess of the total purchase price over the estimated fair value of assets
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and liabilities at the acquisition date. The amounts may be adjusted in the
final purchase price allocation. Management does not expect the ultimate
resolution of the purchase price allocation to materially impact the Company's
financial position, results of operations, or cash flows. The operating results
of DeepTech are included in the Company's Consolidated Statements of Income
beginning on August 15, 1998.
Year 2000
The Company 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 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 (which was previously included as a component of the
Company's implementation phase).
In recognition of the importance of Year 2000 issues and their potential
impact to the Company, 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 the Company 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, and embedded chips is substantially complete. The Company
estimates that it has finished more than three-fourths of the portion of the
assessment to determine the nature and impact of the Year 2000 date change for
third-party-developed software. 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. To
date, the responses from such third parties, although generally encouraging, are
inconclusive. As a result, the Company cannot predict the potential consequences
if these or other third parties or their products are not Year 2000 compliant.
The Company is currently evaluating the exposure associated with such business
partner relationships.
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 Company estimates that approximately one-half of the work of these phases
remains, and expects each to be substantially completed by mid-1999.
The implementation phase involves placing the converted or replaced key
automated systems into operation. In some cases, this phase will also involve
the implementation of contingency plans needed to support business functions and
processes that may be interrupted by Year 2000 failures that are outside of the
Company's control. The Company has completed more than one-fourth of the
implementation phase, which is expected to be substantially completed by
mid-1999.
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 the
impact of a significant failure. The Company plans to have its contingency plan
completed by
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mid-1999. The Year 2000 contingency plan will continue to be 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, and systems within the
Company's control may 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 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 believes 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 intends to
incorporate this possibility into the relevant contingency plans.
While the total cost of the Company's Year 2000 project is still being
evaluated, the Company estimates that the costs 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 $14 million and $26 million. Of
these estimated costs, the Company expects between $6 million and $14 million to
be capitalized and the remainder to be expensed. As of December 31, 1998, the
Company has incurred expenses of approximately $6 million. The Company has
previously only traced incremental expenses related to its 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 most of the costs
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reported above in the remediation, implementation and contingency planning
phases of the project. 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 occurrence of Year 2000
disruption or expense include the failure of the Company of 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's outside consultants to complete the remediation in a timely manner
(due to shortages of qualified labor or other factors), 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 avoid Year 2000 failures.
Employee Separation and Asset Impairment Charge
During the first quarter of 1996, the Company adopted a program to reduce
operating costs through work force reductions and improved work processes and
adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of. As a result of the workforce reduction
program and the adoption of SFAS No. 121, the Company recorded a special charge
of $99 million ($47 million for employee separation costs and $52 million for
asset impairments) in the first quarter of 1996. For a further discussion, see
Item 8, Financial Statements and Supplementary Data, Note 11.
Management is not aware of other commitments or contingent liabilities
which would have a materially adverse effect on the Company's financial
condition, results of operations, or cash flows.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for the Costs of Computer Software Developed or Obtained for
Internal Use
In March 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use. This statement provides guidance on
accounting for such costs, and also defines internal-use computer software. The
statement is effective for fiscal years beginning after December 15, 1998. The
application of this pronouncement will not have a material impact on the
Company's financial position, results of operations, or cash flows.
Reporting on the Costs of Start-Up Activities
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 to 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 statement is effective for fiscal years beginning after
December 15, 1998. The Company will adopt this pronouncement effective January
1, 1999, and expects to report a charge in the range of $7 million to $12
million, net of income taxes, in the first quarter of 1999 as a cumulative
effect of a change in accounting principle.
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Accounting for Derivative Instruments and Hedging Activities
In June 1998, SFAS 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. SFAS No. 133 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 is effective for all quarters in fiscal years
beginning after June 15, 1999. The Company is currently evaluating the effects
of this pronouncement.
Disclosure relating to Euro Conversion
In July 1998, the Securities and Exchange Commission issued Staff Legal
Bulletin No. 6 to provide guidance for disclosure related to the Euro
Conversion. The guidance primarily focuses on disclosure in the Management's
Discussion and Analysis of Financial Condition and Results of Operations, as
well as Description of Business. The Company currently has no investments in the
countries affected by the Euro Conversion.
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities
In November 1998, the Emerging Issues Task Force reached a consensus on
EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. EITF 98-10 requires energy trading contracts to be
recorded at fair value on the balance sheet, with the changes in fair value
included in earnings. EITF 98-10 is effective for fiscal years beginning after
December 15, 1998. The Company adopted the provisions of EITF 98-10 in January
1999. The application of this pronouncement did not have a material impact on
the Company's financial position, results of operations, or cash flows.
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RISK FACTORS -- CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference 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, we caution 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, we or our management express 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.
With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf:
OUR INDUSTRY IS HIGHLY COMPETITIVE
The hydrocarbons that we transport, gather, process and store are owned by
third parties. As a result, the volume of hydrocarbons involved in such
activities is dependent upon the actions of those third parties, and are beyond
our control. Further, our ability to maintain or increase current transmission,
gathering, processing, and sales volumes or to remarket unsubscribed capacity,
is subject to the impact of the following:
- future weather conditions, including those that favor hydroelectric
generation or other alternative energy sources;
- price competition;
- drilling activity and supply availability;
- expiration of the Dynegy contracts at the end of 1999; and
- service competition, especially due to current excess pipeline capacity
into California.
Our future profitability may be affected by our ability to compete with the
services offered by other energy enterprises which may be larger, offer more
services, and possess greater resources.
Seventy percent of TGP's contracts are expiring over the next two years,
principally in November 2000. Our ability to negotiate new contracts and to
renegotiate existing contracts could be adversely affected by factors we cannot
control, including:
- the proposed construction by other companies of additional pipeline
capacity in the markets served by TGP;
- reduced demand due to higher gas prices;
- the availability of alternative energy sources; and
- the viability of our expansion projects.
For a further discussion see Item 1, Business, Natural Gas Transmission,
Markets and Competition.
FLUCTUATIONS IN NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY
AFFECT OUR BUSINESS
Our ability to compete with other transporters is impacted by natural gas
prices in the supply basins connected to our pipeline systems as compared to
prices in other gas producing regions, especially Canada. Revenues generated by
our gathering and processing contracts are dependent upon volumes and rates,
both of which can be affected by the prices of natural gas and natural gas
liquids. The success of our expanding gathering and processing operations in the
offshore Gulf of Mexico is subject to continued development of
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additional oil and gas reserves in the vicinity of our facilities and our
ability to access such additional reserves to offset the natural decline from
existing wells connected to our systems. A decline in energy prices could
precipitate a decrease in such development activities and could cause a decrease
in the volume of reserves available for gathering and processing through our
offshore facilities. Fluctuations in energy prices, which may impact gathering
rates and investments by third parties in the development of new oil and gas
reserves connected to our gathering and processing facilities, are caused by a
number of factors, including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation facilities;
- energy legislation;
- federal or state taxes, if any, on the sale or transportation of natural
gas and natural gas liquids and the price; and
- abundance of supplies of alternative energy sources.
If there are reductions in the average volume of the natural gas we transport,
gather and process for a prolonged period, our results of operations and
financial position could be materially adversely affected.
THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES
Some of our non-regulated subsidiaries are engaged in the gathering,
processing and marketing of natural gas and other energy commodities and utilize
futures and option contracts traded on the New York Mercantile Exchange and
over-the-counter options and price and basis swaps with other gas merchants and
financial institutions. These instruments are intended to reduce our exposure to
short-term volatility in changes in commodities prices. We could, however, incur
financial losses in the future as a result of volatility in the market values of
the underlying commodities or if one of our counterparties fails to perform
under a contract. For additional information concerning our derivative financial
instruments, see item 7A, Quantitative and Qualitative Disclosures About Market
Risks and Item 8, Financial Statements and Supplementary Data, Note 5.
ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE
Our ability to grow will depend, in part, upon our ability to identify and
complete attractive acquisition and investment opportunities. Opportunities for
growth through acquisitions and investments in joint ventures, and the future
operating results and success of such acquisitions and joint ventures within and
outside the U.S. may be subject to the effects of, and changes in the following:
- U.S. and foreign trade and monetary policies;
- laws and regulations;
- political and economic developments;
- inflation rates;
- taxes; and
- operating conditions.
OUR FOREIGN INVESTMENTS INVOLVE SPECIAL RISKS
Our activities in areas outside the U.S. are subject to the risks inherent
in foreign operations, including:
- loss of revenue, property and equipment as a result of hazards such as
expropriation, nationalization, wars, insurrection and other political
risks, and
- the effects of currency fluctuations and exchange controls (such as the
recent devaluation of the Indonesian and Brazilian currencies and other
economic problems).
37
<PAGE> 52
Such legal and regulatory events and other unforeseeable obstacles may be beyond
our control or ability to manage.
WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES
We 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. For
additional information concerning the Company's environmental matters, see the
section of this item entitled "Environmental."
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
While we maintain insurance against certain of the risks normally
associated with the transportation, gathering and processing of natural gas,
including explosions, pollution and fires, the occurrence of a significant event
that is not fully insured against could have a material adverse effect on our
business.
THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EPTPC
The amount of the actual and contingent liabilities of EPTPC, which
remained the liabilities of EPNG after it acquired EPTPC, could vary materially
from the amount we estimated, which was based upon assumptions which could prove
to be inaccurate. If New Tenneco or Newport News Shipbuilding Inc. were unable
or unwilling to pay their respective liabilities, a court could require us,
under certain legal theories which may or may not be applicable to the
situation, to assume responsibility for such obligations. If we were required to
assume these obligations, it could have a material adverse effect on our
financial condition, results of operations or cash flows.
THERE REMAIN POTENTIAL FEDERAL INCOME TAX LIABILITIES RELATED TO THE ACQUISITION
OF EPTPC
In connection with the acquisition of EPTPC and the Distributions made by
EPTPC prior to that acquisition, the IRS issued a private letter ruling to Old
Tenneco, in which it ruled that for U.S. federal income tax purposes the
Distributions would be tax-free to Old Tenneco and, except to the extent cash
was received in lieu of fractional shares, to its then existing stockholders;
the Merger would constitute a tax-free reorganization; and that certain other
transactions effected in connection with the Merger and Distribution would be
tax-free. If the Distributions were not to qualify as tax-free distributions,
then a corporate level federal income tax would be assessed to the consolidated
group of which Old Tenneco was the common parent. This corporate level federal
income tax would be payable by EPTPC. Under certain limited circumstances,
however, New Tenneco and Newport News Shipbuilding Inc. have agreed to indemnify
EPTPC for a defined portion of such tax liabilities.
WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS
Our business and operating results can be adversely affected by factors
such as the availability or cost of capital, changes in interest rates, changes
in the tax rates due to new tax laws, market perceptions of the natural gas
industry or EPEC, or credit ratings.
WE ARE SUBJECT TO RISKS ASSOCIATED WITH YEAR 2000 ISSUES
We are taking steps to mitigate any adverse effects of the Year 2000 date
change on our customers and business operations including the assessment,
remediation, testing of our applications, hardware and software, and the
implementation of necessary change. Nevertheless, our failure, or the failure of
third-parties with whom we deal, to achieve Year 2000 compliance may adversely
affect our business. For additional information on our Year 2000 strategy and
specific factors that may affect our ability to achieve Year 2000 compliance,
see the section of this item entitled "Other -- Year 2000."
38
<PAGE> 53
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities and interest and foreign
currency exchange rates. The Company's primary market risk exposure is to
changing commodity prices. Market risks are monitored by a corporate risk
management committee that operates independently from the business segments that
create or actively manage these risk exposures to ensure compliance with the
Company's stated risk management policies as approved by the Board. These
policies are set forth in Item 8, Financial Statements and Supplementary Data,
Note 1.
TRADING COMMODITY PRICE RISK
EPEM is exposed to certain market risks inherent in its financial
instruments entered into for trading purposes associated with natural gas, power
and petroleum products. EPEM marks to market all energy trading activities,
including transportation capacity and storage. EPEM's policy is to manage
commodity price risks through a variety of financial instruments, including
forward contracts involving cash settlements or physical delivery of an energy
commodity, swap contracts which require payment to (or receipts from)
counterparties based on the differential between a fixed and variable price for
the commodity, exchange-traded options, over-the-counter options and other
contractual arrangements. EPEM manages its markets risk on a portfolio basis,
subject to parameters established by the risk management committee.
Comprehensive risk management processes, policies, and procedures have been
established to monitor and control its market risk. The Company's risk
management committee also continually reviews these policies to ensure they are
responsive to changing business conditions.
EPEM measures the risk in its commodity and energy related contract
portfolio on a daily basis utilizing a Value-at-Risk ("VAR") model to determine
the maximum potential one-day unfavorable impact on its earnings from its
existing portfolio due to normal market movements and monitors its risk in
comparison to established thresholds. The VAR computations are based on
historical simulation, which utilizes price movements over a specified period to
simulate forward price curves in the energy markets, and several key
assumptions, including the selection of a confidence level for expected losses
and the holding period for liquidation. EPEM also utilizes other measures
outside the VAR methodology to monitor the risk in its commodity and energy
related contract portfolio on a monthly basis, including stress testing,
position limit control and credit, liquidity and event risk management. EPEM
previously utilized sensitivity analysis to report market risk based on a ten
percent change in commodity prices. The uncertainty of the market place,
increased trading of derivative instruments, and the complexity of these
instruments created the demand for a more comprehensive portfolio level
quantitative measure of market risk. Accordingly, EPEM converted from utilizing
sensitivity analysis to the VAR model during 1998.
Assuming a confidence level of 95 percent and a one-day holding period,
EPEM's estimated potential one-day unfavorable impact on income before income
taxes and minority interest, as measured by VAR, related to its commodity and
energy related contracts held for trading purposes was approximately $3 million
and $2 million at December 31, 1998, and 1997, respectively. VAR was implemented
on April 1, 1998, therefore volatilities and correlations applicable on April 1,
1998, were used to provide comparative data for December 31, 1997. Actual losses
could exceed those measured by VAR.
NON-TRADING COMMODITY PRICE RISK
The estimated potential one-day unfavorable impact on income before income
taxes and minority interest, as measured by VAR, related to EPEM's non-trading
commodity activities was immaterial at December 31, 1998, and 1997.
INTEREST RATE RISK
The Company's debt financial instruments are sensitive to market
fluctuations in interest rates. The table below presents principal cash flows
and related weighted average interest rates by expected maturity dates. As of
December 31, 1998, and 1997, the carrying amounts of short-term borrowings are
representative of fair
39
<PAGE> 54
values because of the short-term maturity of these instruments. The fair value
of the long-term debt has been estimated based on quoted market prices for the
same or similar issues.
The Company's non-trading derivative financial instruments, including
interest rate and equity swaps are also sensitive to market fluctuations in
interest rates. The interest rate swap agreements entered into by MPC
effectively convert $114 million of floating-rate debt to fixed-rate debt (see
Item 8, Financial Statements and Supplementary Data, Note 4). MPC makes payments
to counterparties at fixed rates and in return receives payments at floating
rates. The two swap agreements were entered into in March 1992 and have
remaining terms of approximately 1 year and 3 years, respectively. This
transaction is recorded using accrual accounting. In addition, in March 1997,
the Company purchased a 10.5 percent interest in CAPSA for approximately $57
million. In connection with this acquisition, the Company entered into an equity
swap transaction associated with an additional 18.5 percent of CAPSA's then
outstanding stock. Under the equity swap, the Company pays interest to the
counterparty, on a quarterly basis, on a notional amount of $100 million at a
rate of LIBOR plus 0.85 percent. In exchange, the Company receives dividends on
the CAPSA stock to the extent of the counterparty's equity interest of 18.5
percent. In February 1999, the Company extended the term of the swap for two and
a half years. For the interest rate and equity swaps, the table below presents
notional amounts and weighted average interest rates by expected or contractual
maturity dates. Notional amounts are used to calculate the contractual payments
to be exchanged under the contact. The fair value of the derivative financial
instruments is the estimated amount at which management believes they could be
liquidated over a reasonable period of time, based on quoted market prices,
current market conditions, or other estimates obtained from third-party dealers.
The tabular presentation related to activities other than commodity
trading, as of December 31, 1998, and 1997, is illustrated below:
<TABLE>
<CAPTION>
DECEMBER 31, 1998
--------------------------------------------------------------------
EXPECTED FISCAL YEAR OF MATURITY
--------------------------------------------------------------------
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
---- ----- ---- ---- ---- ---------- ------ ----------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES:
Short-term debt -- variable
rate.............................. $750 $ 750 $ 750
- ------------------------------------
Average interest rate........ 5.8%
Long-term debt, including
-----------------------------
current portion -- fixed
rate......................... $ 62 $ 125 $ 52 $240 $215 $1,920 $2,614 $2,795
----------------------------------
Average interest rate........ 8.0% 10.5% 7.3% 7.8% 7.8% 7.8%
INTEREST RATE DERIVATIVES:
Interest rate swap
--------------------
Variable to fixed
rate -- notional amounts..... $ 29 $ 85 $ 114 $ (9)
Average interest rate........ 8.3% 8.4% 8.4% 8.4%
Average received rate(a)..... 4.9% 5.0% 5.1% 5.1%
Net cash flow effect......... $ (4) $ (3) $ (3) $ (3)
Equity swap
--------------
Interest to
dividend -- notional
amount....................... $100 $ 100 $ 3
Average interest rate(a)..... 6.5%
Received dollars(b).......... --
Net cash flow effect......... (7)
</TABLE>
40
<PAGE> 55
<TABLE>
<CAPTION>
DECEMBER 31, 1997
----------------------
TOTAL FAIR VALUE
------ ----------
(DOLLARS IN MILLIONS)
<S> <C> <C>
LIABILITIES:
Short-term debt -- variable rate.......................... $ 813 $ 813
Average interest rate paid in 1998..................... 5.8%
Long-term debt, including current portion -- fixed rate... $2,191 $2,334
Average interest rate paid in 1998................... 7.8%
INTEREST RATE DERIVATIVES:
Interest rate swap
Variable to fixed rate -- notional amounts............. $ 114 $ (9)
Average interest rate paid in 1998................... 8.3%
Average received rate in 1998(a)..................... 5.8%
Net cash flow effect for 1998........................ $ (3)
Equity swap
Interest to dividend -- notional amount................ $ 100 $ 8
Average interest rate paid in 1998(a)................ 6.6%
Received dollars in 1998(b).......................... --
Net cash flow effect for 1998........................ $ (7)
</TABLE>
- ---------------
(a) The variable rates presented are the average forward rates for the remaining
term of each contract.
(b) The Company receives dividends, to the extent paid, on the CAPSA stock to
the extent of the counterparty's equity interest of 18.5 percent. No
dividends were received in 1998 and no dividends are expected for 1999.
41
<PAGE> 56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Operating revenues
Transportation............................................ $1,194 $1,200 $ 534
Natural gas, liquids and power............................ 4,370 4,110 2,359
Gathering and processing.................................. 141 204 85
Other..................................................... 77 124 34
------ ------ ------
5,782 5,638 3,012
------ ------ ------
Operating expenses
Cost of gas and other products............................ 4,212 4,125 2,277
Operation and maintenance................................. 707 664 322
Depreciation, depletion, and amortization................. 269 236 101
Employee separation and asset impairment charge........... -- -- 99
Taxes, other than income taxes............................ 88 92 43
------ ------ ------
5,276 5,117 2,842
------ ------ ------
Operating income............................................ 506 521 170
------ ------ ------
Other (income) and expense
Interest and debt expense................................. 267 238 110
Other, net................................................ (138) (57) (5)
------ ------ ------
129 181 105
------ ------ ------
Income before income taxes and minority interest............ 377 340 65
Income tax expense.......................................... 127 129 25
------ ------ ------
Income before minority interest............................. 250 211 40
Minority interest
Preferred stock dividend of subsidiary.................... 25 25 2
------ ------ ------
Net income.................................................. $ 225 $ 186 $ 38
====== ====== ======
Basic earnings per common share............................. $ 1.94 $ 1.64 $ 0.53
====== ====== ======
Diluted earnings per common share........................... $ 1.85 $ 1.59 $ 0.52
====== ====== ======
Basic average common shares outstanding..................... 116 114 72
====== ====== ======
Diluted average common shares outstanding................... 126 117 73
====== ====== ======
</TABLE>
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
42
<PAGE> 57
EL PASO ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1998 1997
------------ ------------
<S> <C> <C>
Current assets
Cash and temporary investments............................ $ 90 $ 116
Accounts and notes receivable, net
Customer................................................ 557 737
Other................................................... 176 252
Inventories............................................... 49 68
Deferred income taxes..................................... 81 168
Assets from price risk management activities.............. 181 96
Regulatory assets......................................... 9 116
Prepaid expenses.......................................... 40 28
Other..................................................... 26 48
------- ------
Total current assets............................... 1,209 1,629
------- ------
Property, plant, and equipment, net......................... 7,341 7,116
Investments in unconsolidated affiliates.................... 600 373
Intangibles, net............................................ 537 117
Other....................................................... 382 297
------- ------
Total assets....................................... $10,069 $9,532
======= ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade................................................... $ 547 $ 787
Other................................................... 177 99
Short-term borrowings (including current maturities of
long-term debt)......................................... 812 885
Accrual for regulatory issues............................. 37 22
Liabilities from price risk management activities......... 127 73
Other..................................................... 462 598
------- ------
Total current liabilities.......................... 2,162 2,464
------- ------
Long-term debt, less current maturities..................... 2,552 2,119
------- ------
Deferred income taxes....................................... 1,564 1,550
------- ------
Postretirement benefits..................................... 248 285
------- ------
Other....................................................... 745 790
------- ------
Commitments and contingencies (See Note 6)
Company-obligated mandatorily redeemable convertible
preferred securities of El Paso Energy Capital Trust I.... 325 --
------- ------
Minority interest
Preferred stock of subsidiary............................. 300 300
------- ------
Other minority interest................................... 65 65
------- ------
Stockholders' equity
Common stock, par value $3 per share; authorized
275,000,000 shares; issued 124,434,110 and 122,581,816
shares, respectively.................................... 373 368
Additional paid-in capital................................ 1,436 1,389
Retained earnings......................................... 460 327
Accumulated comprehensive income.......................... (14) (7)
Treasury stock (at cost) 4,149,099 and 2,946,832 shares,
respectively............................................ (90) (47)
Deferred compensation..................................... (57) (71)
------- ------
Total stockholders' equity......................... 2,108 1,959
------- ------
Total liabilities and stockholders' equity......... $10,069 $9,532
======= ======
</TABLE>
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
43
<PAGE> 58
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
----- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities
Net income................................................ $ 225 $ 186 $ 38
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion, and amortization.............. 269 236 101
Deferred income taxes (benefit)........................ 128 195 (5)
Gain on disposition of property........................ (20) (2) --
Undistributed earnings in equity investees............. (28) (3) 16
Amortization of deferred compensation.................. 24 19 5
Risk-sharing revenue................................... (31) -- --
Net employee separation and asset impairment charge.... -- -- 76
Working capital changes, net of non-cash transactions
Accounts and notes receivable........................ 250 342 (168)
Inventories.......................................... 19 16 (5)
Net price risk management activities................. (32) 16 (39)
Regulatory asset..................................... 124 19 --
Other current assets................................. 11 47 77
Accrual for regulatory issues........................ 16 (266) 135
Accounts payable..................................... (178) (249) 65
Other current liabilities............................ (143) 11 (8)
Other..................................................... (124) 4 3
----- ------- -------
Net cash provided by operating activities......... 510 571 291
----- ------- -------
Cash flows from investing activities
Capital expenditures...................................... (406) (293) (119)
Investment in joint ventures and equity investees......... (447) (239) (24)
Net cash flow impact of acquisitions...................... (373) (213) (35)
Proceeds from disposal of property and investments........ 74 14 190
Proceeds from equity investment project financing......... 153 53 --
Other..................................................... -- (28) (17)
----- ------- -------
Net cash used in investing activities............. (999) (706) (5)
----- ------- -------
Cash flows from financing activities
Net commercial paper borrowings (repayments).............. 14 326 (203)
Revolving credit borrowings............................... 610 70 400
Revolving credit repayments............................... (687) (1,200) (1,022)
Long-term debt retirements................................ (72) (124) (24)
Long-term debt issuance, net.............................. 391 883 396
Proceeds from issuance of El Paso Energy Capital Trust I
preferred securities, net of issuance costs............ 317 -- --
Acquisition of treasury stock............................. (36) -- --
Dividends paid............................................ (91) (77) (53)
Proceeds from stock issuance, net of issuance costs....... -- 152 --
Proceeds from project financing........................... -- -- 310
Other..................................................... 17 21 71
----- ------- -------
Net cash provided by (used in) financing
activities...................................... 463 51 (125)
----- ------- -------
Increase (decrease) in cash and temporary investments....... (26) (84) 161
Cash and temporary investments
Beginning of period....................................... 116 200 39
----- ------- -------
End of period............................................. $ 90 $ 116 $ 200
===== ======= =======
</TABLE>
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
44
<PAGE> 59
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL ACCUMULATED TREASURY STOCK
--------------- PAID-IN RETAINED COMPREHENSIVE --------------- DEFERRED
SHARES AMOUNT CAPITAL EARNINGS INCOME SHARES AMOUNT COMPENSATION
------ ------ ---------- -------- ------------- ------ ------ ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
January 1, 1996............. 75 $224 $ 343 $240 $ -- (6) $(95) $ --
Net income................ 38
Common stock dividend
($0.695 per share)...... (50)
Issuance of common stock
for acquisition of
EPTPC................... 37 113 800
Restricted stock
issuances............... 23 2 41 (74)
Amortization of deferred
compensation............ 5
Options exercised......... 1 3 18 (1) 1 9
Other..................... 1
--- ---- ------ ---- ---- -- ---- ----
December 31, 1996........... 113 340 1,185 227 -- (3) (45) (69)
Net income................ 186
Common stock dividend
($0.730 per share)...... (86)
Issuance of common stock,
net of related costs.... 7 20 152
Restricted stock
issuances............... 1 4 20 -- 1 (23)
Restricted stock
forfeitures............. -- (3) 2
Amortization of deferred
compensation............ 19
Options exercised......... 2 4 21
Income tax benefit of
stock-based compensation
plans................... 11
Comprehensive income...... (7)
--- ---- ------ ---- ---- -- ---- ----
December 31, 1997........... 123 368 1,389 327 (7) (3) (47) (71)
Net income................ 225
Common stock dividend
($0.765 per share)...... (92)
Issuance of common stock
for acquisition of
DeepTech................ -- -- 2
Restricted stock
issuances............... -- 2 23 (14)
Restricted stock
forfeitures............. -- (4) 4
Restricted stock used for
tax withholdings........ -- (1)
Amortization of deferred
compensation............ 24
Options exercised......... 1 3 13 -- (2)
Income tax benefit of
stock-based compensation
plans................... 9
Open market stock
repurchases............. (1) (36)
Comprehensive income...... (7)
--- ---- ------ ---- ---- -- ---- ----
December 31, 1998........... 124 $373 $1,436 $460 $(14) (4) $(90) $(57)
=== ==== ====== ==== ==== == ==== ====
<CAPTION>
TOTAL
STOCKHOLDERS'
EQUITY
-------------
<S> <C>
January 1, 1996............. $ 712
Net income................ 38
Common stock dividend
($0.695 per share)...... (50)
Issuance of common stock
for acquisition of
EPTPC................... 913
Restricted stock
issuances............... (10)
Amortization of deferred
compensation............ 5
Options exercised......... 29
Other..................... 1
------
December 31, 1996........... 1,638
Net income................ 186
Common stock dividend
($0.730 per share)...... (86)
Issuance of common stock,
net of related costs.... 172
Restricted stock
issuances............... 2
Restricted stock
forfeitures............. (1)
Amortization of deferred
compensation............ 19
Options exercised......... 25
Income tax benefit of
stock-based compensation
plans................... 11
Comprehensive income...... (7)
------
December 31, 1997........... 1,959
Net income................ 225
Common stock dividend
($0.765 per share)...... (92)
Issuance of common stock
for acquisition of
DeepTech................ 2
Restricted stock
issuances............... 11
Restricted stock
forfeitures............. --
Restricted stock used for
tax withholdings........ (1)
Amortization of deferred
compensation............ 24
Options exercised......... 14
Income tax benefit of
stock-based compensation
plans................... 9
Open market stock
repurchases............. (36)
Comprehensive income...... (7)
------
December 31, 1998........... $2,108
======
</TABLE>
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
45
<PAGE> 60
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN MILLIONS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1998 1997 1996
----- ----- -----
<S> <C> <C> <C>
Net income.................................................. $225 $186 $38
Foreign currency translation adjustments.................... (7) (7) --
---- ---- ---
Comprehensive income........................................ $218 $179 $38
==== ==== ===
</TABLE>
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
46
<PAGE> 61
EL PASO ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries of the Company after the elimination of
all significant intercompany accounts and transactions. Investments in companies
where the Company has the ability to exert significant influence over, but not
control operating and financial policies are accounted for using the equity
method. The financial statements for previous periods include certain
reclassifications that were made to conform to the current year presentation.
Such reclassifications have no impact on reported net income or stockholders'
equity.
Holding Company Reorganization
Effective August 1, 1998, the Company reorganized into a holding company
organizational structure, whereby EPEC, a Delaware corporation, became the
holding company. The holding company organizational structure was effected by a
merger conducted pursuant to Section 251(g) of the Delaware General Corporation
Law, which provides for the formation of a holding company structure without a
vote of the stockholders of EPNG. In the merger, El Paso Energy Merger Company,
a Delaware corporation and wholly owned subsidiary of EPEC, merged with and into
EPNG, with EPNG as the surviving corporation. By virtue of the reorganization,
EPNG became a direct, wholly owned subsidiary of EPEC, and all of EPNG's
outstanding capital stock was converted, on a share for share basis, into
capital stock of EPEC. As a result of such restructuring, each outstanding share
of $3.00 par value common stock of EPNG was converted into one share of $3.00
par value common stock of EPEC, and each one-half outstanding preferred stock
purchase right of EPNG was converted into one preferred stock purchase right of
EPEC common stock, with such right representing the right to purchase one
two-hundredth (subject to adjustment) of a share of Series A Junior
Participating Preferred Stock of EPEC. Because the reorganization was with
companies under common control, the stockholders' equity and components thereof
of EPNG became the basis for EPEC stockholders' equity. In addition to the
holding company formation, EPEC assumed ownership of the Trust (as defined in
Note 3) as well as EPNG's obligations related to the Trust. See Note 3, Trust
Preferred Securities for a further discussion. Finally, EPEC became the
successor to EPNG's previous shelf registration in the amount of $565 million.
The New York Stock Exchange ticker symbol used by EPEC following the
reorganization remains unchanged as "EPG."
Tax-free Internal Reorganization
On December 31, 1998, the Company effected a tax-free internal
reorganization of its assets and operations and those of a majority of its
subsidiaries in accordance with a private letter ruling received from the IRS.
In the internal reorganization, a substantial number of subsidiaries were
transferred to or from the Company and/or other entities owned by the Company.
The tax-free internal reorganization had no impact on the presentation herein.
Stock Split
On January 21, 1998, the Board approved a two-for-one stock split of EPNG's
common stock (the "Stock Split"), subject to stockholder approval of an
amendment to EPNG's Restated Certificate of Incorporation to increase the number
of authorized shares of EPNG's common stock to 275,000,000 shares (the
"Amendment"). EPNG's stockholders approved the Amendment on March 2, 1998. In
connection with the Amendment, the Board increased the number of authorized
shares of EPNG's preferred stock designated as Series A Junior Participating
Preferred Stock to 1,375,000 shares. Prior to the holding company
reorganization, the designated number of Series A Junior Participating Preferred
Stock was increased to 2,750,000. The Stock Split was effected in the form of a
stock dividend of an aggregate of 60,944,417 shares of
47
<PAGE> 62
EPNG's common stock, which was paid on April 1,1998, to stockholders of record
on March 13, 1998. All common shares and per common share amounts have been
adjusted to give effect to the Stock Split.
After giving effect to the Stock Split in accordance with the adjustment
provisions of the Amended and Restated Shareholder Rights Agreement, dated as of
July 23, 1997, between the Company and BankBoston, N.A. as Rights Agent, the
number of rights to purchase one one-hundredth of a share of the Series A Junior
Participating Preferred Stock associated with each share of common stock was
adjusted to become one-half of such right (see Holding Company Reorganization
above, for the impact of the holding company reorganization).
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities that exist at
the date of the financial statements. Actual results are likely to differ from
those estimates.
Accounting for Regulated Operations
The Company's businesses that are subject to the regulations and accounting
requirements of FERC have followed the accounting requirements of SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation, which may differ from
the accounting requirements of the Company's non-regulated entities.
Transactions that have been recorded differently as a result of regulatory
accounting requirements include: GSR costs to be recovered under a demand and
interruptible surcharge, environmental costs to be recovered under a demand
surcharge, and certain benefits and other costs and taxes included in or
expected to be included in future rates, including costs to refinance debt. When
the accounting method followed is prescribed by or allowed by the regulatory
authority for rate-making purposes, such method conforms to the generally
accepted accounting principle of matching costs with the revenues to which they
apply.
Cash and Temporary Investments
Short-term investments purchased with an original maturity of three months
or less are considered cash equivalents.
Allowance for Doubtful Accounts and Notes Receivable
The Company has established a provision for losses on accounts and notes
receivable, as well as for gas imbalances due from shippers and operators, which
may become uncollectible. Collectibility is reviewed regularly, and the
allowance is adjusted as necessary primarily under the specific identification
method. The balances of this provision at December 31, 1998 and 1997, were $15
million and $17 million, respectively.
Gas Imbalances
The Company values gas imbalances due to or due from shippers and operators
at the appropriate index price. Natural gas imbalances are settled in cash or
made up in-kind.
Inventories
Inventories, consisting of materials and supplies and natural gas in
storage, are valued at the lower of cost or market with cost determined using
the average cost method.
Property, Plant, and Equipment
Included in the Company's property, plant, and equipment is construction
work in progress of approximately $392 million and $276 million at December 31,
1998, and 1997, respectively. An allowance for both debt and equity funds used
during construction of regulated projects is included in the cost of the
Company's property, plant, and equipment.
48
<PAGE> 63
Accounting for a substantial portion of property, plant, and equipment is
subject to regulation by the FERC. The objectives of this regulation are to
ensure the proper recovery of capital investments in rates. Such recovery is
generally accomplished by allowing a return of the investment through inclusion
of depreciation expense in the cost of service. Rates also allow for a return on
the net unrecovered rate base. Specific procedures are prescribed by FERC to
control capitalized costs, depreciation, and the disposal of assets. SFAS No. 71
specifically acknowledges the obligation of regulated companies to comply with
regulated accounting procedures, even when they conflict with other generally
accepted accounting principle pronouncements.
Regulated property, plant, and equipment is recorded at original cost of
construction or, on acquisition, the cost of first party committing the asset to
utility services. Construction cost includes direct labor and materials, as well
as indirect charges such as overheads and allowance for funds used during
construction. Replacements or betterments of major units of property are
capitalized. Replacements or additions of minor units of property are expensed.
Depreciation for regulated property, plant, and equipment is calculated
using the composite method. Assets with similar economic characteristics are
grouped. The depreciation rate prescribed in the rate settlement is applied to
the gross investment for the group until net book value of the group is equal to
the salvage value. Currently, depreciation rates vary from 1 percent to 33
percent. This results in remaining economic lives of groups ranging from 2 to 36
years. Depreciation rates are reevaluated in conjunction with the rate making
process.
When regulated property, plant, and equipment is retired, due to
abandonment or replacement, the original cost, plus the cost of retirement, less
salvage, is charged to accumulated depreciation and amortization. No gain or
loss is recognized unless an entire operating unit, as defined by FERC, has been
retired. Gains or losses on dispositions of operating units are included in
income.
Additional acquisition cost assigned to utility plant primarily represents
the excess of allocated purchase costs over historical costs that resulted from
the December 1996 acquisition of EPTPC. These costs are being amortized on a
straight-line basis using FERC approved rates.
Depreciation of the Company's non-regulated properties is provided using
the straight line or composite method which, in the opinion of management, is
adequate to allocate the cost of properties over their estimated useful lives.
Non-regulated properties have expected lives of 5 to 40 years.
The Company evaluates impairment of its property, plant, and equipment in
accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of.
Intangible Assets
Intangible assets are amortized using the straight-line method over periods
ranging from 5 years to 40 years. Accumulated amortization of intangible assets
was $24 million and $21 million for 1998 and 1997, respectively.
The Company evaluates impairment of goodwill in accordance with SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of.
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments indicate that
remediation efforts are probable and the costs can be reasonably estimated.
Estimates of the liability are based upon currently available facts, existing
technology and presently enacted laws and regulations taking into consideration
the likely effects of inflation and other societal and economic factors, and
include estimates of associated legal costs. All available evidence is
considered including prior experience in remediation of contaminated sites,
other companies' clean-up experience and data released by the EPA or other
organizations. These estimated liabilities are subject to
49
<PAGE> 64
revision in future periods based on actual costs or new circumstances. These
liabilities are included in the balance sheets at their undiscounted amounts.
Recoveries are evaluated separately from the liability and, when recovery is
assured, are recorded and reported separately from the associated liability in
the consolidated financial statements as an asset.
Price Risk Management Activities
The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities, and interest rates. In its
commodity price risk management activities, the Company engages in both trading
and non-trading activities.
Activities for trading purposes consist of services provided to the energy
sector, and all energy trading activities, including transportation capacity and
storage, are accounted for using the mark-to-market method of accounting. Such
trading activities are conducted through a variety of financial instruments,
including forward contracts involving cash settlement or physical delivery of an
energy commodity, swap contracts which require payments to (or receipts from)
counterparties based on the differential between a fixed and variable price for
the commodity, exchange-trade options, over-the-counter options, and other
contractual arrangements.
Under mark-to-market accounting, commodity and energy related contracts are
reflected at estimated market value with resulting gains and losses recorded in
operating income in the Consolidated Statements of Income. The net gains or
losses recognized in the current period result primarily from transactions
originating within the period and the impact of price movements on transactions
originating in previous periods. The assets and liabilities resulting from
mark-to-market accounting are presented as assets and liabilities from price
risk management activities in the Consolidated Balance Sheets. Terms regarding
cash settlement of the contracts vary with respect to the actual timing of cash
receipts and payments. Receivables and payables resulting from these timing
differences are presented in accounts receivable, and accounts payable in the
Consolidated Balance Sheets. Cash inflows and outflows associated with these
price risk management activities are recognized in operating cash flow as the
settlements of transactions occur.
The market value of these commodity and energy related contracts reflects
management's best estimate considering various factors including closing
exchange and over-the-counter quotations, time value and volatility factors
underlying the commitments. The values are adjusted to reflect the potential
impact of liquidating the Company's position in an orderly manner over a
reasonable period of time under present market conditions.
Derivative and other financial instruments are also utilized in connection
with non-trading activities. The Company enters into forwards, swaps, and other
contracts to hedge the impact of market fluctuations on assets, liabilities, or
other contractual commitments. Derivatives held for non-trading price risk
management activities are not recorded on the balance sheet. Net periodic
settlements are recorded as a gain or loss in operating income in the
consolidated statements of income, and cash inflows and outflows are recognized
in operating cash flow as the settlements of the transactions occur. See Note 5
for a further discussion of the Company's price risk management activities.
In late 1998, the Emerging Issues Task Force reached a consensus which
supported the Company's accounting policy as described above.
Income Taxes
Income taxes are based on income reported for tax return purposes along
with a provision for deferred income taxes. Deferred income taxes are provided
to reflect the tax consequences in future years of differences between the
financial statement and tax bases of assets and liabilities at each year end.
Tax credits are accounted for under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
Deferred tax assets are reduced by a valuation allowance when, based upon
management's estimates, it is more likely than not that a portion of the
deferred tax assets will not be realized
50
<PAGE> 65
in a future period. The estimates utilized in the recognition of deferred tax
assets are subject to revision in future periods based on new facts or
circumstances.
In connection with the Merger, EPTPC entered into a tax sharing agreement
with Newport News Shipbuilding Inc., New Tenneco and the Company, as successor
to EPNG. This tax sharing agreement provides, among other things, for the
allocation among the parties of tax assets and liabilities arising prior to, as
a result of, and subsequent to the Distributions. Generally, EPTPC will be
liable for taxes imposed on itself. With respect to periods prior to the
consummation of the Distributions, in the case of federal income taxes imposed
on the combined activities of Old Tenneco and other members of its consolidated
group prior to giving effect to the Distributions, New Tenneco and Newport News
Shipbuilding Inc. will be liable to EPTPC for federal income taxes attributable
to their activities, and each will be allocated an agreed-upon share of
estimated tax payments made by EPTPC for Old Tenneco. Pursuant to the tax
sharing agreement, EPTPC paid New Tenneco in 1997 for the tax benefits realized
from the deduction of 1996 taxable losses generated by a debt realignment in
accordance with the Merger.
Treasury Stock
Treasury stock is accounted for using the cost method and is shown as a
reduction to stockholders' equity in the consolidated balance sheets. Treasury
stock sold or issued is valued on a first-in, first-out basis. Included in
treasury stock at December 31, 1998, and 1997, were 1,360,000 shares of common
stock that were reserved for use under certain of the Company's benefit plans.
Stock-Based Compensation
As allowed under SFAS No. 123, the Company has elected to continue to apply
the provisions of Accounting Principles Board Opinion No. 25 and related
interpretations in accounting for its stock compensation plans. The Company uses
fixed and variable plan accounting for fixed and variable
compensation plans, respectively. Accordingly, compensation expense is not
recognized for stock options unless the options were granted at an exercise
price lower than market on the grant date.
New Accounting Pronouncements Not Yet Adopted
See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, New Accounting Pronouncements Not Yet Adopted, which is
incorporated herein by reference.
51
<PAGE> 66
2. ACQUISITIONS
DeepTech
In August 1998, the Company completed its acquisition of DeepTech by
merging DeepTech with a subsidiary of EPEC. DeepTech's assets include a 27.3
percent ownership interest in Leviathan. The acquisition was accounted for as a
purchase with a total purchase price of approximately $422 million, net of cash
acquired. The Company recorded $214 million of goodwill in connection with the
acquisition which will be amortized using the straight-line method over a period
of 40 years. The amount allocated to goodwill is based on an estimate of the
excess of the total purchase price over the fair value of assets and liabilities
at the acquisition date. The amounts may be adjusted in the final purchase price
allocation. Management does not expect the ultimate resolution of the purchase
price allocation to materially impact the Company's financial position, results
of operations, or cash flows. The operating results of DeepTech are included in
the Company's Consolidated Statements of Income beginning on August 15, 1998.
The components of the purchase price are as follows:
<TABLE>
<CAPTION>
(IN MILLIONS)
<S> <C>
Fair value of assets acquired............................... $ 338
Goodwill.................................................... 214
Fair value of liabilities assumed........................... (101)
Cash acquired............................................... (29)
-----
Purchase price, net of cash acquired.............. 422
Affiliated receivable extinguished.......................... (77)
Issuance of common stock.................................... (2)
-----
Net cash consideration paid....................... $ 343
=====
</TABLE>
In accordance with the DeepTech merger agreement, the Company has executed
a guarantee with regard to DeepTech's 12% senior notes due 2000. The following
table contains summarized financial information of DeepTech. Information as of
and for the twelve months ended June 30, 1998, 1997, and 1996 are for pre-merger
periods. The information for December 31, 1998, is for the post-merger period
and the information for the six months ended December 31, 1998, is part
post-merger and part pre-merger.
<TABLE>
<CAPTION>
FOR THE SIX FOR THE TWELVE MONTHS
MONTHS ENDED ENDED JUNE 30,
DECEMBER 31, ---------------------
1998(a) 1998 1997 1996
------------ ------- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Operating results data:
Operating revenue......................................... $ 15 $ 69 $120 $ 55
Operating expenses........................................ $ 25 $ 74 $132 $ 50
Net income (loss)......................................... $ 11 $ (2) $(20) $ 4
</TABLE>
<TABLE>
<CAPTION>
JUNE 30,
DECEMBER 31, ---------------------
1998(b) 1998 1997 1996
------------ ------- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Financial position data:
Total assets.............................................. $551 $181 $228 $156
Short term debt (including current maturities of long-term
debt).................................................. $ 17 $ 12 $ 25 $ 46
Long term debt............................................ $ 90 $ 96 $165 $ 98
Stockholder's equity...................................... $444 $ 47 $ 6 $ 12
</TABLE>
- ---------------
(a) Unaudited
(b) Reflects the allocation of the purchase price to the assets acquired and
liabilities assumed in connection with the Company's acquisition of DeepTech
in August 1998.
52
<PAGE> 67
TPC
In December 1997, the Company completed its purchase of gathering
facilities consisting of 360 miles of natural gas pipeline and a natural gas
cryogenic processing plant through the acquisition of 100 percent of the stock
of TPC at a cash price of approximately $195 million. This transaction was
accounted for as a purchase.
Gulf States
In October 1997, the Company completed the acquisition of Gulf States Gas
Pipeline Company. The assets purchased include a 175-mile natural gas gathering
and intrastate transmission system in Northwest Louisiana with a capacity of 250
MMcf/d. The purchase price was approximately $39 million, which included the
issuance of $21 million of common stock of the Company. This transaction was
accounted for as a purchase.
EPTPC
On December 12, 1996, the Company completed the acquisition of EPTPC in a
transaction accounted for as a purchase. The purchase price was assigned to the
assets and liabilities acquired based upon the estimated fair value of those
assets and liabilities as of the acquisition date. Substantially all of the
excess of the total purchase price over historical carrying amounts of the net
assets acquired was allocated to property, plant and equipment of EPTPC's
interstate pipeline systems. Such allocation was confirmed by an independent
appraisal of the property acquired.
In the Merger, Old Tenneco changed its name to EPTPC. Prior to the Merger,
Old Tenneco and its subsidiaries completed various intercompany transfers and
distributions which restructured, divided and separated their businesses, assets
and liabilities so that all the assets, liabilities and operations related to
the Industrial Business and the Shipbuilding Business were spun-off to Old
Tenneco's then existing common stockholders. The Distributions were effected on
December 11, 1996 pursuant to the Distribution Agreement dated as of November 1,
1996. Following the Distributions, the remaining operations of Old Tenneco
consisted primarily of activities related to the transmission and marketing of
natural gas. Results of operations of EPTPC were included in the Company's
Consolidated Statements of Income for the last 20 days of 1996.
On October 30, 1996, the IRS issued a private letter ruling to Old Tenneco,
in which it ruled that for U.S. federal income tax purposes the Distributions
would be tax-free to Old Tenneco and, except to the extent cash is received in
lieu of fractional shares, to its then existing stockholders; the Merger would
constitute a tax-free reorganization; and certain other transactions effected in
connection with the Merger and Distributions would be tax-free. If the
Distributions were not to qualify as tax-free distributions, then a corporate
level federal income tax would be assessed to the consolidated group of which
Old Tenneco was the common parent. This corporate level federal income tax would
be payable by EPTPC. Under certain limited circumstances, however, New Tenneco
and Newport News Shipbuilding Inc. have agreed to indemnify EPTPC for a defined
portion of such tax liabilities.
The consideration paid by the Company in the Merger consisted of:
- the retention after the Merger of approximately $2.6 billion of debt and
preferred stock obligations of Old Tenneco, subject to certain
adjustments (which consisted, in part, of (i) approximately $200 million
of public debt of Old Tenneco outstanding at the effective time of the
Merger, (ii) $2.1 billion of debt of Old Tenneco outstanding at the
effective time of the Merger
under a $3 billion Revolving Credit and Competitive Advance Facility
Agreement, dated as of
November 4, 1996 (the "Credit Facility"), among Old Tenneco, certain banks
and other financial institutions and The Chase Manhattan Bank, as agent),
and (iii) $300 million of Old Tenneco preferred stock);
- the issuance of 37.6 million shares of common stock of the Company valued
at approximately $913 million, based on a closing price per share of
common stock on the New York Stock Exchange of $24.3125 on December 9,
1996, to Old Tenneco's then existing common and preferred stockholders;
and
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<PAGE> 68
- the retention of approximately $600 million of estimated liabilities
related to certain discontinued businesses of Old Tenneco.
The number of shares of the Company's common stock issued in the Merger to
stockholders of Old Tenneco was determined pursuant to formulas set forth in the
Merger Agreement. In the Merger, (i) a holder of Old Tenneco's common stock
received 0.186 of a share of the Company's common stock for each share of
Tenneco common stock, (ii) a holder of Old Tenneco's $7.40 Cumulative Preferred
Stock received 4.73 shares of the Company's common stock for each such share of
$7.40 Cumulative Preferred Stock, and (iii) a holder of Old Tenneco's $4.50
Cumulative Preferred Stock received 4.73 shares of the Company's common stock
for each such share of $4.50 Cumulative Preferred Stock.
At December 31, 1998, the Company owns 100 percent of the common equity and
more than 80 percent of the combined equity value of EPTPC. The remaining
combined equity of EPTPC consists of $300 million of preferred stock issued in a
public offering by Old Tenneco on November 18, 1996, which remains outstanding.
Assets acquired, liabilities assumed, and consideration received are as
follows:
<TABLE>
<CAPTION>
(IN MILLIONS)
<S> <C>
Fair value of assets acquired............................... $ 6,649
Cash acquired............................................... (75)
Fair value of liabilities assumed........................... (5,724)
Issuance of common stock.................................... (913)
-------
Net cash consideration received................... $ (63)
=======
</TABLE>
The following unaudited pro forma information presents a summary of what
the consolidated results of operations would have been on a pro forma basis for
the year ended December 31, 1996, assuming the EPTPC acquisition had been in
effect throughout 1996:
<TABLE>
<CAPTION>
1996
--------------------
(IN MILLIONS, EXCEPT
PER SHARE AMOUNTS)
<S> <C>
Operating revenue........................................... $5,281
Net income.................................................. $ 183
Basic earnings per common share............................. $ 1.61
</TABLE>
In December 1996, subsequent to the Merger, TGP sold 70 percent of its
interests in two natural gas pipeline systems in Australia to CNGI Australia
Pty. Limited, a wholly owned indirect subsidiary of Consolidated Natural Gas
Company, and four Australian investors for approximately $400 million, inclusive
of related debt financing, and completed the sale of its oil and gas
exploration, production and financing unit, formerly known as Tenneco Ventures,
for approximately $105 million. After consideration of the purchase price
allocation adjustments, there was no gain or loss recognized on these
transactions.
Effective June 1996, the Company acquired Cornerstone Natural Gas, Inc. in
a transaction accounted for as a purchase. The purchase price of approximately
$94 million, exclusive of acquisition costs, was financed through internally
generated funds and short-term borrowings. Acquisition costs of approximately $5
million were capitalized. The cost of the acquisition was allocated on the basis
of the estimated fair value of the assets acquired and the liabilities assumed,
resulting in goodwill of approximately $59 million which is being amortized over
40 years using the straight-line method. Results of operations of Cornerstone
Natural Gas, Inc. are included in the Company's Consolidated Statements of
Income beginning in June 1996.
3. TRUST PREFERRED SECURITIES
In March 1998, El Paso Energy Capital Trust I (the "Trust") issued 6.5
million of 4 3/4% trust convertible preferred securities (the "Trust Preferred
Securities") for $325 million ($317 million, net of issuance costs).
54
<PAGE> 69
In addition, the Trust issued trust convertible common securities of
approximately $10 million to EPNG. The net proceeds were used by EPNG to pay
down commercial paper. The Trust exists for the sole purpose of issuing Trust
Preferred Securities and investing the proceeds in 4 3/4% convertible
subordinated debentures due 2028 (the "Trust Debentures") of EPNG, the Trust's
sole asset. EPNG executed a guarantee with regard to the Trust Preferred
Securities. The guarantee, when taken together with EPNG's obligations under the
Trust Debentures, the indenture pursuant to which the Trust Debentures were
issued, and the applicable trust document, provides a full and unconditional
guarantee of the Trust's obligations under the Trust Preferred Securities.
As a result of the holding company reorganization discussed in Note 1, EPEC
assumed ownership of the Trust, as well as the obligations of the Trust
Debentures, and the guarantee of the Trust's obligations under the Trust
Preferred Securities. The results of the Trust are consolidated with those of
the Company and, therefore, the Trust Debentures are eliminated and the Trust
Preferred Securities are reflected as company-obligated mandatorily redeemable
convertible preferred securities of El Paso Energy Capital Trust I in the
Consolidated Balance Sheets. Distributions on the Trust Preferred Securities are
included in interest and debt expense in the Consolidated Statements of Income.
The Trust Preferred Securities are non-voting (except in limited
circumstances), pay quarterly distributions at an annual rate of 4 3/4%
commencing on June 30, 1998, carry a liquidation value of $50 per security plus
accrued and unpaid distributions and are convertible into the Company's common
shares at any time prior to the close of business on March 31, 2028, at the
option of the holder at a rate of 1.2022 common shares for each Trust Preferred
Security (equivalent to a conversion price of $41.59 per common share), subject
to adjustment in certain circumstances.
4. FINANCING TRANSACTIONS
The average interest rate of short-term borrowings was 5.8% and 5.9% at
December 31, 1998, and 1997, respectively. The Company had short-term
borrowings, including current maturities of long-term debt, at December 31, 1998
and December 31, 1997, as follows:
<TABLE>
<CAPTION>
1998 1997
------ ------
(IN MILLIONS)
<S> <C> <C>
EPNG Revolving Credit Facility.............................. $ -- $ 45
EPNG Revolving Credit Facility with TGP designated as
borrower.................................................. -- 417
EPNG Revolving Credit Facility with EPEC designated as
borrower.................................................. 350 --
Commercial paper............................................ 340 326
Other credit facilities..................................... 60 25
Current maturities of other long-term debt.................. 62 72
------ ------
$ 812 $ 885
====== ======
</TABLE>
55
<PAGE> 70
Long-term debt outstanding at December 31, 1998 and 1997, consisted of the
following:
<TABLE>
<CAPTION>
1998 1997
------ ------
(IN MILLIONS)
<S> <C> <C>
Long-term debt
TGP
Debentures due 2011, average effective interest rates
of 7.5% in 1998 and 7.9% in 1997, net of unamortized
discount of $10.6 in 1998 ($11.1 in 1997)............. $ 75 $ 75
Debentures due 2017, average effective interest rates
of 7.7% in 1998 and 7.8% in 1997, net of unamortized
discount of $4.7 in 1998 ($5.0 in 1997)............... 295 295
Debentures due 2027, average effective interest rates
of 7.1% in 1998 and 7.2% in 1997, net of unamortized
discount of $3.6 in 1998 ($3.7 in 1997)............... 296 296
Debentures due 2028, average effective interest rate of
7.2% in 1998, net of unamortized discount of $8.9 in
1998.................................................. 391 --
Debentures due 2037, average effective interest rates
of 7.8% in 1998 and 7.9% in 1997, net of unamortized
discount of $6.3 in 1998 ($6.5 in 1997)............... 294 293
EPNG
Debentures due 2012 through 2026, average effective
interest rates of 8.4% in 1998 and 8.3% in 1997, net
of unamortized discount of $1.3 in 1998 ($1.4 in
1997)................................................. 459 475
Notes due 1999 through 2003, average effective interest
rates of 7.7% in 1998 and 7.6% in 1997, net of
unamortized discount of $0.5 in 1998 ($0.7 in 1997)... 462 462
EPTPC
Debentures due 2008 through 2025, average effective
interest rates of 7.3% in 1998 and 7.2% in 1997, net
of unamortized premium of $3.5 in 1998 ($4.0 in
1997)................................................. 54 55
Notes due 1998 through 2005, average effective interest
rates of 6.5% in 1998 and 6.4% in 1997, net of
unamortized premium of $2.3 in 1998 ($4.1 in 1997).... 48 87
EPEC Corporation, successor to El Paso Energy Credit
Corporation
Senior notes due 2001, average effective interest rates
of 6.6% in 1998 and 6.0% in 1997, net of unamortized
premium of $0.9 in 1998 ($1.2 in 1997)................ 14 15
Subordinated notes due 1998, average effective interest
rate of 6.5% in 1997, net of unamortized premium of
$0.2 in 1997.......................................... -- 7
MPC
Project financing loan, due 1998 through March 2007,
average effective interest rates of 9.7% in 1998 and
9.4% in 1997.......................................... 117 126
DeepTech
Senior notes due 2000, average effective interest rate
of 11% from merger date to December 31, 1998, net of
unamortized premium of $6.7........................... 89 --
Senior subordinated promissory note due 2000, average
effective interest rate of 10.3% from merger date to
December 31, 1998, net of unamortized premium of
$.8................................................... 16 --
</TABLE>
56
<PAGE> 71
<TABLE>
<CAPTION>
1998 1997
------ ------
(IN MILLIONS)
<S> <C> <C>
Other
Notes due 2000 through 2014, average effective interest
rates of 7.5% in 1998 and 8.7% in 1997................ 4 5
------ ------
2,614 2,191
Less current maturities................................... 62 72
------ ------
Long-term debt, less current maturities........... $2,552 $2,119
====== ======
</TABLE>
The following are aggregate maturities of long-term debt for the next 5
years and in total thereafter:
<TABLE>
<CAPTION>
(IN MILLIONS)
-------------
<S> <C>
1999........................................................ $ 62
2000........................................................ 125
2001........................................................ 52
2002........................................................ 240
2003........................................................ 215
Thereafter.................................................. 1,920
------
Total long-term debt, including current
maturities....................................... $2,614
======
</TABLE>
Other Financing Arrangements
In October 1997, EPNG established a new $750 million five-year revolving
credit and competitive advance facility and a new $750 million 364-day renewable
revolving credit and competitive advance facility. In connection with the
establishment of the Revolving Credit Facility, EPTPC's revolving credit
facility was also terminated, and the outstanding balance of $417 million was
financed under the five-year portion of the new Revolving Credit Facility with
TGP designated as the borrower. The availability under the Revolving Credit
Facility is expected to be used for general corporate purposes including, but
not limited to, backstopping EPNG's and TGP's $1 billion commercial paper
programs.
In August 1998, EPEC became a guarantor of the Revolving Credit Facility.
In October 1998, the $750 million 364-day portion of the Revolving Credit
Facility was amended to extend the termination date to October 27, 1999. In
addition, in October 1998, the Revolving Credit Facility was amended to permit
TGP to issue commercial paper, provided that the total amount of commercial
paper outstanding at EPNG and TGP is equal to or less than the unused capacity
under the Revolving Credit Facility. In December 1998, EPEC became a borrower
under the Revolving Credit Facility. The interest rate is 40 basis points above
LIBOR, with the spread varying based on EPEC's long-term debt credit rating.
The availability of borrowings under the Company's credit agreements is
subject to specified conditions, which management believes the Company currently
meets. These conditions include compliance with the financial covenants and
ratios required by such agreements, absence of default under such agreements,
and continued accuracy of the representations and warranties contained in such
agreements (including the absence of any material adverse changes since the
specified dates).
All of the Company's senior debt issues have been given investment grade
ratings by Standard & Poors and Moody's. The Company must comply with various
restrictive covenants contained in its debt agreements which include, among
others, maintaining a consolidated debt and guarantees to capitalization ratio
no greater than 70 percent. In addition, the Company's subsidiaries on a
consolidated basis (as defined in the agreements) may not incur debt obligations
which would exceed $300 million in the aggregate, excluding acquisition debt,
project financing, and certain refinancings. As of December 31, 1998, EPEC's
consolidated debt and guarantees to capitalization ratio (as defined in the
agreements) was 55 percent and debt obligations of EPEC subsidiaries in excess
of permitted debt did not exceed $300 million on a consolidated basis.
57
<PAGE> 72
In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2%
debentures due 2017, $300 million aggregate principal amount of 7% debentures
due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due
2037. Proceeds of approximately $883 million, net of issuance costs, were used
to repay a portion of EPTPC's credit facility and for general corporate
purposes.
In December 1997, EPEC filed a shelf registration statement pursuant to
which EPEC may offer up to $900 million (including $250 million transferred from
prior shelf registrations) of common or preferred equities, various forms of
debt securities (including convertible debt securities), and various types of
trust securities from time to time as determined by market conditions. In March
1998, the El Paso Energy Capital Trust I, a Delaware business trust sponsored by
the Company, issued 6.5 million 4 3/4% Trust Convertible Preferred Securities.
The sole assets of the trust are approximately $335 million principal amount of
4 3/4% convertible subordinated debentures due 2028 of the Company. As a result
of such offering, EPEC has approximately $565 million of capacity remaining
under its existing shelf registration to issue public securities registered
thereunder.
In September 1998, TGP filed a shelf registration permitting TGP to offer
up to $600 million (including $100 million carried forward from a prior shelf
registration) of debt securities. In October 1998, TGP issued $400 million
aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were
approximately $391 million, net of issuance cost. Approximately $300 million of
the proceeds were used to repay TGP's short-term indebtedness under the
Revolving Credit Facility and the remainder were used by TGP for general
corporate purposes. After this issuance, TGP has $200 million of capacity
remaining under its shelf registration.
In March 1998, EPNG retired its outstanding 8 5/8% debentures in the amount
of $17 million and in August 1998, EPTPC retired its outstanding 10% debentures
in the amount of $38 million. In February 1999, DeepTech retired its 11% senior
subordinated promissory note due 2000 in the amount of $16 million.
5. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is presented in accordance with the requirements of SFAS No. 107.
The estimated fair value amounts have been determined by the Company using
available market information and valuation methodologies.
As of December 31, 1998, and 1997, the carrying amounts of certain
financial instruments held by the Company, including cash, cash equivalents,
short-term borrowings and investments, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments. The fair value of long-term debt with variable interest rates is
the carrying value because of the variable nature of the respective debt's
interest rate, and the fair value of debt with fixed interest rates has been
estimated based on quoted market prices for the same or similar issues. The
project financing debt is at market interest rates and therefore, the fair value
of the project financing debt is representative of the carrying amount. The fair
value of all derivative financial instruments is the estimated amount at which
management believes the instruments could be liquidated over a reasonable period
of time, based on quoted market prices, current market conditions, or other
estimates obtained from third-party brokers or dealers.
58
<PAGE> 73
The following table reflects the carrying amount and estimated fair value
of the Company's financial instruments at December 31:
<TABLE>
<CAPTION>
1998 1997
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Balance sheet financial instruments:
Long-term debt, excluding project financing.......... $2,497 $2,678 $2,065 $2,208
Project financing debt............................... 117 117 126 126
Other financial instruments:
Trading
Futures contracts................................. (4) (4) (3) (3)
Option contracts.................................. 77 77 3 3
Swap and forward contracts........................ (28) (28) 23 23
Non-Trading
Interest rate swap agreements..................... -- (9) -- (9)
Equity swap....................................... 3 3 6 8
Commodity option contracts........................ -- 1 -- 1
Commodity swap and forward contracts.............. -- (14) -- 4
</TABLE>
Trading Commodity Activities
The Company, through its merchant services business, offers integrated
price risk management services to the energy sector. These services primarily
relate to energy related commodities including natural gas, power, and petroleum
products. The Company provides these services through a variety of contracts
entered into for trading purposes including forward contracts involving cash
settlements or physical delivery of an energy commodity, swap contracts, which
require payments to (or receipt of payments from) counterparties based on the
differential between a fixed and variable price for the commodity, options and
other contractual arrangements. The Company recognized gross margin of $40
million and $17 million during 1998 and 1997, respectively, arising from its
trading activities.
The fair value of commodity and energy related contracts entered into for
trading purposes as of December 31, 1998, and 1997, and the average fair value
of those instruments held during the years ended December 31, 1998, and 1997 are
set forth below. At December 31, 1998, $92 million of assets from price risk
management activities are included in other assets and $42 million of
liabilities from price risk management activities are included in other
liabilities in the Consolidated Balance Sheets.
<TABLE>
<CAPTION>
AVERAGE FAIR
VALUE FOR THE
YEAR ENDED
ASSETS LIABILITIES DECEMBER 31,(A)
------ ----------- ---------------
(IN MILLIONS)
<S> <C> <C> <C>
1998
Futures contracts................................. $ 2 $ (6) $ (5)
Option contracts.................................. 153 (17) 30
Swap and forward contracts........................ 118 (146) (31)
1997
Futures contracts................................. $ 4 $ (7) $ --
Option contracts.................................. 15 (12) 2
Swap and forward contracts........................ 77 (54) 13
</TABLE>
- ---------------
(a) computed using the net asset balance at each month end.
59
<PAGE> 74
Notional Amounts and Terms
The notional amounts and terms of these financial instruments at December
31, 1998, and 1997 are set forth below (natural gas volumes in trillions of
British thermal units, power volumes in millions of megawatt hours, petroleum
products volumes in millions of British thermal units):
<TABLE>
<CAPTION>
FIXED PRICE FIXED PRICE MAXIMUM
PAYOR RECEIVER TERMS IN YEARS
----------- ----------- --------------
<S> <C> <C> <C>
1998
Energy Commodities:
Natural gas.................................. 9,605 8,866 20
Power........................................ 22 28 20
Petroleum products........................... 67 72 2
1997
Energy Commodities:
Natural gas.................................. 4,079 3,584 20
Power........................................ 12 13 1
Petroleum products........................... 197 195 2
</TABLE>
Notional amounts reflect the volume of transactions but do not represent
the amounts exchanged by the parties. Accordingly, notional amounts are an
incomplete measure of the Company's exposure to market or credit risks. The
maximum terms in years detailed above are not indicative of likely future cash
flows as these positions may be offset or cashed-out in the markets at any time
based on the Company's risk management needs and liquidity in the commodity
markets.
The weighted average maturity of the Company's entire portfolio of price
risk management activities was approximately two years as of December 31, 1998
and 1997, respectively.
Market and Credit Risks
The Company serves a diverse customer group that includes independent power
producers, industrial companies, gas and electric utilities, oil and gas
producers, financial institutions and other energy marketers. This broad
customer mix generates a need for a variety of financial structures, products
and terms. This diversity requires the Company to manage, on a portfolio basis,
the resulting market risks inherent in these transactions subject to parameters
established by the Company's risk management committee. Market risks are
monitored by a risk control committee operating independently from the units
that create or actively manage these risk exposures to ensure compliance with
the Company's stated risk management policies.
The Company measures and adjusts the risk in its portfolio in accordance
with mark-to-market and other risk management methodologies which utilize
forward price curves in the energy markets to estimate the size and probability
of future potential exposure.
60
<PAGE> 75
Credit risk relates to the risk of loss that the Company would incur as a
result of non-performance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with regard to
its counterparties to minimize overall credit risk. These policies require an
evaluation of potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances (including cash in
advance, letters of credit, and parental guarantees), and the use of
standardized agreements which allow for the netting of positive and negative
exposures associated with a single counterparty. The counterparties associated
with the Company's assets from price risk management activities as of December
31, 1998, and 1997 are summarized as follows:
<TABLE>
<CAPTION>
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
AS OF DECEMBER 31, 1998
---------------------------------------------------
BELOW
INVESTMENT GRADE(a) INVESTMENT GRADE TOTAL(b)
------------------- ---------------- --------
(IN MILLIONS)
<S> <C> <C> <C>
Energy marketers.......................... $ 71 $ 5 $ 76
Financial institutions.................... 21 -- 21
Oil and gas producers..................... 37 5 42
Gas and electric utilities................ 104 6 110
Industrials............................... 18 -- 18
Other..................................... 4 2 6
---- --- ----
Total assets from price risk
management activities......... $255 $18 $273
==== === ====
</TABLE>
<TABLE>
<CAPTION>
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
AS OF DECEMBER 31, 1997
---------------------------------------------------
BELOW
INVESTMENT GRADE(a) INVESTMENT GRADE TOTAL(b)
------------------- ---------------- --------
(IN MILLIONS)
<S> <C> <C> <C>
Energy marketers.......................... $21 $ 3 $24
Financial institutions.................... 20 20
Oil and gas producers..................... 14 4 18
Gas and electric utilities................ 16 2 18
Industrials............................... 6 1 7
Other..................................... 8 1 9
--- --- ---
Total assets from price risk
management activities......... $85 $11 $96
=== === ===
</TABLE>
- ---------------
(a) "Investment Grade" is primarily determined using publicly available credit
ratings along with consideration of collateral, which encompass standby
letters of credit, parent company guarantees and property interest,
including oil and gas reserves. Included in Investment Grade are
counterparties with a minimum Standard & Poor's or Moody's rating of BBB-
or Baa3, respectively, or minimum implied (through internal credit
analysis) Standard & Poor's equivalent rating of BBB-.
(b) Two customers' exposure at December 31, 1998, and 1997 comprise greater
than 5 percent of assets from price risk management activities. These
customers have Investment Grade ratings.
This concentration of counterparties may impact the Company's overall
exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes in economic, regulatory or
other conditions. Based on the Company's policies, risk exposure, and reserves,
the Company does not anticipate a material adverse effect on its financial
position, or results of operations, or cash flows as a result of counterparty
nonperformance.
61
<PAGE> 76
Non-Trading Price Risk Management Activities
MPC has entered into interest rate swap agreements which effectively
convert $114 million of floating-rate debt to fixed-rate debt (see Note 4). MPC
makes payments to counterparties at fixed rates and in return receives payments
at floating rates. The two swap agreements were entered into in March 1992 and
have remaining terms of approximately 1 year and 3 years, respectively. This
transaction is recorded using accrual accounting. Interest expense and cash
requirements were $3 million higher in 1998, 1997, and 1996, respectively, as a
result of these swaps.
In March 1997, the Company purchased a 10.5 percent interest in CAPSA, a
privately held Argentine company engaged in power generation and oil and gas
production for approximately $57 million. In connection with this acquisition,
the Company entered into an equity swap transaction associated with an
additional 18.5 percent of CAPSA's then outstanding stock. Under the swap, the
Company pays interest to the counterparty, on a quarterly basis, on a notional
amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the
Company receives dividends on the CAPSA stock to the extent of the
counterparty's equity interest of 18.5 percent. The Company also fully
participates in the market appreciation or depreciation of the underlying
investment whereby the Company will realize appreciation or fund any
depreciation attributable to the actual sale of the stock upon termination or
expiration of the swap transaction. The initial term of the swap was two years,
and in February 1999, was extended for an additional two and one-half years.
Upon maturity or termination of the swap, the Company has a right of first
refusal to purchase the counterparty's 18.5 percent investment in CAPSA common
stock at the fair value of the stock at that date or at a later date at a price
offered by a good faith buyer. This transaction is recorded using mark-to-market
accounting.
6. COMMITMENTS AND CONTINGENCIES
See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, Commitments and Contingencies and Environmental, which
are incorporated herein by reference.
7. INCOME TAXES
The following table reflects the components of income tax expense for the
years ended December 31:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Current
Federal................................................... $ 6 $(45) $23
State..................................................... (12) (21) 7
Foreign................................................... 5 -- --
---- ---- ---
(1) (66) 30
---- ---- ---
Deferred
Federal................................................... 116 164 (4)
State..................................................... 14 31 (1)
Foreign................................................... (2) -- --
---- ---- ---
128 195 (5)
---- ---- ---
Total tax expense................................. $127 $129 $25
==== ==== ===
</TABLE>
62
<PAGE> 77
Tax expense of the Company differs from the amount computed by applying the
statutory federal income tax rate (35 percent) to income before taxes. The
following table outlines the reasons for the differences for the periods ended
December 31:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Tax expense at the statutory federal rate of 35%............ $132 $119 $22
Increase (decrease)
State income tax, net of federal income tax benefit....... 1 7 4
Other..................................................... (6) 3 (1)
---- ---- ---
Income tax expense.......................................... $127 $129 $25
==== ==== ===
Effective tax rate.......................................... 34% 38% 38%
==== ==== ===
</TABLE>
The following table reflects the components of the net deferred tax
liability at December 31:
<TABLE>
<CAPTION>
1998 1997
------ ------
(IN MILLIONS)
<S> <C> <C>
Deferred tax liabilities
Property, plant, and equipment............................ $2,012 $1,982
Regulatory and other assets............................... 474 393
------ ------
Total deferred tax liability...................... 2,486 2,375
------ ------
Deferred tax assets
U.S. net operating loss and tax credit carryovers......... 85 113
Accrual for regulatory issues............................. 266 226
Postretirement benefits................................... 116 123
Other liabilities......................................... 542 539
Valuation allowance....................................... (5) (8)
------ ------
Total deferred tax asset.......................... 1,004 993
------ ------
Net deferred tax liability(a)............................... $1,482 $1,382
====== ======
</TABLE>
- ---------------
(a) As of December 31, 1998, $1 million of non-current foreign deferred income
taxes are included in other assets in the Consolidated Balance Sheets.
The cumulative undistributed earnings of certain foreign subsidiaries and
foreign corporate joint ventures were approximately $35 million as of December
31, 1998. Since the earnings have been or are intended to be indefinitely
reinvested in foreign operations, no provision has been made for any U.S. taxes
or foreign withholding taxes that may be applicable upon actual or deemed
repatriation. If a distribution of such earnings were to be made, the Company
may be subject to both foreign withholding taxes and U.S. income taxes, net of
any allowable foreign tax credits or deductions. However, an estimate of such
taxes is not practicable. For the same reasons, the Company has not provided for
any U.S. taxes on the foreign currency translation adjustments recognized in
comprehensive income.
The tax benefit associated with the exercise of non-qualified stock options
and restricted stock as well as restricted stock dividends, reduced taxes
payable by $9 million in 1998 and $11 million in 1997. Such benefits are
included in additional paid-in capital in the Consolidated Balance Sheets.
As of December 31, 1998, approximately $45 million of alternative minimum
tax credits were available to offset future regular tax liabilities. These
alternative minimum tax credit carryovers have no expiration date. Additionally,
at December 31, 1998, approximately $1 million of general business credit, $102
million of net operating loss, and $9 million of capital loss carryovers were
available to offset future tax liabilities. The general business credit
carryovers expire in the years 1999 and 2000. Approximately $57 million of the
net operating loss carryovers expire in 2012 and the remaining $45 million
expire in the years 2004 through 2011. Usage of these carryovers is subject to
the limitations provided for under Sections 382 and 383 of the Internal Revenue
Code as well as the separate return limitation year rules of IRS regulations.
63
<PAGE> 78
The Company has recorded a valuation allowance to reflect the estimated
amount of deferred tax assets which may not be realized due to the expiration of
net operating loss and tax credit carryovers. As of December 31, 1998, and 1997,
approximately $4 million and $8 million, respectively, of the valuation
allowance relates to the net operating loss carryovers of an acquired company.
The remainder of the valuation allowance relates to the general business credit
carryovers of an acquired company. Any tax benefits subsequently recognized from
reversal of this valuation allowance will be allocated to goodwill.
Prior to 1999, EPTPC and its subsidiaries filed a consolidated federal
income tax return and EPEC and its other subsidiaries filed a separate
consolidated federal income tax return. As a result of the tax-free
reorganization described in Note 1, starting in 1999, EPEC and its subsidiaries,
including EPTPC and its subsidiaries, will file one consolidated federal income
tax return.
Deferred taxes corresponding to the allocation of the purchase price to the
assets and liabilities acquired of EPTPC, have been reflected in the
Consolidated Balance Sheets as of December 31, 1998, and 1997.
8. CAPITAL STOCK
Common Stock
In October 1997, approximately .8 million shares of Company common stock
were issued in connection with the acquisition of Gulf States Gas Pipeline
Company. Such shares were valued at approximately $21 million.
In February 1997, approximately 6 million shares of Company common stock
were issued in a public offering registered under the Securities Act of 1933, as
amended. Proceeds of $152 million, net of issuance costs, were received and used
to repay borrowings under the Revolving Credit Facility.
In December 1996, 37.6 million shares of Company common stock were issued
in connection with the acquisition of EPTPC. Such shares were valued at
approximately $913 million.
Treasury Stock
From time to time, the Board has authorized the repurchase of EPEC's
outstanding shares of common stock to be used in connection with EPEC employee
stock-based compensation plans and for other corporate purposes. During 1998,
the Company repurchased 995,600 common shares at a weighted average cost of
$35.77 per share. As of December 31, 1998, and 1997, EPEC held 4,149,099 and
2,946,832 shares of treasury stock, respectively. Included in the balance at
December 31, 1998, were 1,360,000 shares of treasury stock used to secure
benefits under certain of the Company's benefit plans which are subject to
certain restrictions.
Stock Dividend
In January 1998, the Board declared a two-for-one stock split in the form
of a 100 percent stock dividend (on a per share basis). In March 1998, the
stockholders approved an increase in the Company's authorized common stock. The
stock dividend of an aggregate of 60,944,417 shares of common stock was paid on
April 1, 1998 to stockholders of record on March 13, 1998. All presentations
herein are made on a post-split basis.
Other
EPEC has 25,000,000 shares of authorized preferred stock, par value $0.01
per share, none of which have been issued, but of which 2,750,000 shares have
been designated as Series A Junior Participating Preferred Stock and reserved
for issuance pursuant to the Company's preferred stock purchase rights plan.
64
<PAGE> 79
9. STOCK-BASED COMPENSATION
During 1998, 1997, and 1996 the Company granted stock options under various
stock option plans (the "Plans"). The Company applies Accounting Principles
Board Opinion No. 25 and related Interpretations in accounting for these Plans.
In 1995, the Financial Accounting Standards Board issued SFAS No. 123,
Accounting for Stock-Based Compensation which, if fully adopted, changes the
methods companies apply in determining expense related to their stock option
plans. Adoption of the expense recognition provisions of SFAS No. 123 was
optional and the Company elected not to apply provisions of SFAS No. 123.
However, pro forma disclosures as if the Company adopted the expense recognition
provisions of SFAS No. 123 are presented below.
Under the Company's existing stock option plans, the Company is authorized
to issue shares of Common Stock to employees and non-employee directors pursuant
to awards granted as incentive stock options (intended to qualify under Section
422 of the Internal Revenue Code, non-qualified stock options, restricted stock,
stock appreciation rights ("SARs"), and performance units.
Non-qualified Stock Options
The Company granted non-qualified stock options in 1998, 1997, and 1996
under its stock option plans. The stock options granted during these periods
have contractual terms of 10 years and generally vest after completion of one to
five years of continuous employment from the grant date. Options are also
granted to non-employee members of the Board at fair market value on the date of
grant and are exercisable immediately. Under the terms of certain plans, EPEC
may grant SARs to certain holders of stock options. SARs are subject to the same
terms and conditions as the related stock options. As of December 31, 1998,
50,538 SARs were outstanding which have been included in stock options as part
of tandem awards. The stock option holder who has been granted tandem SARs can
elect to exercise either an option or a SAR. SARs entitle an option holder to
receive a payment equal to the difference between the option price and the fair
market value of the common stock of EPEC at the date of exercise of the SAR. To
the extent a SAR is exercised, the related option is canceled, and to the extent
an option is exercised, the related SAR is canceled. Currently, the SARs are
being accounted for as compensation expense under Accounting Principles Board
Opinion No. 25 and are not considered for purposes of computing fair value of
outstanding options using the Black-Scholes option pricing model as described
below.
A summary of the status of the Company's stock options as of December 31,
1998, 1997, and 1996 is presented below:
<TABLE>
<CAPTION>
STOCK OPTIONS
------------------------------------------------------------------------
1998 1997 1996
---------------------- ---------------------- ----------------------
WEIGHTED WEIGHTED WEIGHTED
# SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE
UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE
OPTIONS PRICES OPTIONS PRICES OPTIONS PRICES
----------- -------- ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the
year.............................. 8,782,214 $17.90 8,847,190 $15.83 5,207,910 $14.41
Granted........................... 2,328,450 $33.40 1,775,200 $26.23 4,933,646 $16.55
Exercised......................... 1,072,351 $17.40 1,643,376 $15.28 1,240,596 $12.79
Forfeited......................... 187,070 $21.48 196,800 $21.77 53,770 $14.44
--------- --------- ---------
Outstanding at end of year.......... 9,851,243 $21.55 8,782,214 $17.90 8,847,190 $15.83
========= ========= =========
Exercisable at end of year.......... 5,042,572 $16.94 4,006,508 $15.43 3,960,190 $14.82
========= ========= =========
</TABLE>
65
<PAGE> 80
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions:
<TABLE>
<CAPTION>
ASSUMPTION: 1998 1997 1996
----------- ----- ----- -----
<S> <C> <C> <C>
Expected Term in Years...................................... 5 3 3
Expected Volatility......................................... 20.3% 17.3% 20.3%
Expected Dividends.......................................... 3.0% 3.0% 3.0%
Risk-Free Interest Rate..................................... 4.6% 6.3% 5.5%
</TABLE>
The Black-Scholes weighted average fair value of options granted during
1998, 1997 and 1996 was as follows:
<TABLE>
<CAPTION>
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Weighted-average fair value of options granted at a
discount............................................... $ 9.71 $ 5.96 $10.26
Weighted-average fair value of options granted at
market................................................. $ 7.00 $ 3.86 $ 2.58
</TABLE>
Options outstanding as of December 31, 1998 are summarized below:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- -----------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE
EXERCISE PRICES AT 12/31/98 CONTRACTUAL LIFE EXERCISE PRICE AT 12/31/98 EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 7.50 to $15.37 1,361,776 4.3 $12.66 1,361,776 $12.66
$15.38 to $19.28 4,541,225 6.5 $16.43 2,957,865 $16.56
$19.29 to $31.99 2,169,092 8.3 $26.77 603,531 $25.15
$32.00 to $38.56 1,779,150 9.4 $35.07 119,400 $33.42
--------- ---------
$ 7.50 to $38.56 9,851,243 7.1 $21.55 5,042,572 $16.94
========= =========
</TABLE>
Restricted Stock
Under the Company's various stock-based compensation plans, a limited
number of shares of restricted Company common stock may be granted at no cost to
certain key officers and employees. These shares carry voting and dividend
rights; however, sale or transfer of the shares is restricted in accordance with
the vesting procedures. These restricted stock awards vest over a specific
period of time and/or if the Company achieves certain performance targets.
Restricted stock awards representing .5 million, .7 million, and 3.2 million
shares were granted during 1998, 1997, and 1996, respectively, with a weighted
average grant date fair value of $32.29, $28.53, and $18.82 per share,
respectively. At December 31, 1998, 4.5 million shares of restricted stock were
outstanding. The value of these shares is determined based on the fair market
value on the measurement dates and is charged to compensation expense ratably
over the restriction period based on the number of shares earned over the
vesting period. For 1998, 1997, and 1996, these charges totaled $27 million, $19
million, and $5 million, respectively. The unamortized balance is recorded as a
reduction of stockholders' equity in the Consolidated Balance Sheets.
Performance Units
Certain employees and officers of the Company are awarded performance units
that are payable in cash or stock at the end of the vesting period. The final
value of the performance units may vary according to the plan under which they
are granted, but is usually based on the Company's common stock price at the end
of the vesting period. The value of the performance units is charged ratably to
compensation expense over the vesting period with periodic adjustments to
account for the fluctuation in the market price of the Company's stock. Amounts
charged to compensation expense in 1998, 1997, and 1996 were $13 million, $5
million, and $5 million, respectively.
66
<PAGE> 81
Pro Forma Net Income and Net Income Per Common Share
Had the compensation expense for the Company's stock-based compensation
plans been determined applying the provisions of SFAS No. 123, the Company's net
income and net income per common share for 1998, 1997, and 1996 would
approximate the pro forma amounts below:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1997 DECEMBER 31, 1996
----------------------- ----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
SFAS No. 123 charge, pretax..... $ -- $ 61 $ -- $ 30 $ -- $ 17
APB No. 25 charge, pretax....... $ 49 $ -- $ 24 $ -- $ 13 $ --
Net income...................... $ 225 $ 217 $ 186 $ 183 $ 38 $ 36
Basic earnings per common
share......................... $1.94 $1.87 $1.64 $1.61 $0.53 $0.50
Diluted earnings per common
share......................... $1.85 $1.79 $1.59 $1.56 $0.52 $0.49
</TABLE>
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards granted
prior to the 1995 fiscal year.
At December 31, 1998, 21.1 million shares of common stock were reserved for
issuance pursuant to existing and future stock awards, of which approximately
5.4 million shares remain reserved.
10. RETIREMENT BENEFITS
Pension Benefits
Prior to January 1, 1997, the Company maintained a defined benefit pension
plan covering substantially all employees of EPNG and EPFS. Pension benefits
were based on years of credited service and final 5-year average compensation,
subject to maximum limitations as defined in the pension plan. During 1996, the
Company recognized a $21 million charge to pension expense related to an early
retirement window and workforce reductions.
Effective January 1, 1997, the plan was amended to provide benefits
determined by a cash balance formula and to include employees added as a result
of the Merger and other acquisitions prior to 1997. Employees who were
participants on December 31, 1996, receive the greater of cash balance benefits
or prior plan benefits accrued through December 31, 2001.
During 1997, the Company offered special termination benefits to employees
added as a result of the Merger who were at least 55 years old and who were
eligible to retire under the Tenneco Inc. Retirement Plan on December 31, 1996.
Eligible employees accepting this offer and retiring by July 1, 1997, received a
cash balance credit based on an enhanced formula not to exceed one year's base
salary. The cost associated with the special termination benefits was accrued at
December 31, 1996, as part of the liabilities assumed in the Merger. In 1997,
the Company funded $11 million for these special termination benefits.
Other Postretirement Benefits
EPNG provides postretirement medical benefits for a closed group of
employees who retired on or before March 1, 1986, and limited postretirement
life insurance for employees who retired after January 1, 1985. As such, EPNG's
obligation to accrue for other postretirement employee benefits ("OPEB") is
primarily limited to the fixed population of retirees who retired on or before
March 1, 1986. The medical plan is pre-funded to the extent employer
contributions are recoverable through rates. To the extent actual OPEB costs
differ from the amounts recovered in rates, a regulatory asset or liability is
recorded.
As a result of the Merger, EPTPC retained responsibility for certain
postretirement medical and life insurance benefits for former employees of
operations previously disposed of by Old Tenneco, and for employees, including
TGP employees, added as a result of the Merger who were eligible to retire on
December 31, 1996, and did so on or before July 1, 1997. Medical benefits for
this closed group of retirees may be subject to deductibles, co-payment
provisions, and other limitations and dollar caps on the amount of
67
<PAGE> 82
employer costs. EPTPC has reserved the right to change these benefits. Employees
who retired on or after July 1, 1997 will continue to receive limited
postretirement life insurance benefits. TGP's postretirement benefit plan costs
are pre-funded to the extent such costs are recoverable through rates. Effective
February 1, 1992, TGP began recovering through its rates the OPEB costs included
in the June 2, 1993 rate case settlement agreement. To the extent actual OPEB
costs differ from the amounts funded, a regulatory asset or liability is
recorded.
Several plan amendments were made effective January 1, 1998, including
increases in deductibles, increases in out-of-pocket limits, and changes to the
prescription drug provisions. These changes resulted in a $25 million decrease
in the postretirement benefits obligation.
The following table sets forth the change in benefit obligation, change in
plan assets, funded status, and components of net periodic benefit cost for
pension benefits and other postretirement benefits. In 1998, the Company changed
the measurement date for measuring its pension and OPEB obligations from
December 31 to September 30. Traditionally, timing of the receipt of this
information has limited the Company's ability to maximize planning and budgeting
opportunities with respect to projected costs of its various plans. The Company
changed its benefit reporting date to facilitate the planning process and gather
necessary financial reporting information in a more timely manner. Management
believes the date change is preferable to the method previously employed. This
change in measurement date has been accounted for as a change in accounting
principle and had no material cumulative effect on retirement benefit expense
for the current or prior periods.
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
---------------- --------------
1998 1997 1998 1997
------ ------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Change in benefit obligation
Actuarial present value of benefit obligation at January
1,..................................................... $535 $505 $ 417 $ 427
Service cost.............................................. 11 13 -- --
Interest cost............................................. 36 37 27 30
Participant contributions................................. -- -- 4 5
Amendments................................................ -- -- (25) --
Special termination benefits.............................. -- 11 -- --
Actuarial (gain) or loss.................................. (8) 28 29 15
Benefits paid............................................. (38) (59) (45) (60)
---- ---- ----- -----
Actuarial present value of benefit obligation for 1998 at
September 30 and for 1997 at December 31............... $536 $535 $ 407 $ 417
==== ==== ===== =====
Change in plan assets
Fair value of plan assets at January 1,................... $547 $497 $ 55 $ 42
Actual return on plan assets.............................. 7 79 3 9
Employer contributions.................................... 4 30 46 59
Participant contributions................................. -- -- 4 5
Benefits paid............................................. (38) (59) (45) (60)
---- ---- ----- -----
Fair value of plan assets for 1998 at September 30 and for
1997 at December 31.................................... $520 $547 $ 63 $ 55
==== ==== ===== =====
Reconciliation of fund status
Funded status............................................. $(16) $ 12 $(344) $(362)
Fourth quarter contributions.............................. 5 -- 15 --
Unrecognized net actuarial (gain) or loss................. 29 (4) -- (26)
Unrecognized net transition obligation.................... 6 8 54 70
Unrecognized prior service cost........................... (34) (37) (12) --
---- ---- ----- -----
Net accrued benefit cost at December 31,.................. $(10) $(21) $(287) $(318)
==== ==== ===== =====
</TABLE>
68
<PAGE> 83
As of December 31, 1998, and 1997, the current liability portion of the
postretirement benefits was $39 million and $33 million, respectively. Benefit
obligations are based upon certain actuarial estimates as described below.
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------ ------------------
YEAR ENDED DECEMBER 31,
---------------------------------------
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Benefit cost for the plans includes the following
components
Service cost........................................ $ 11 $ 13 $ 7 $-- $-- $--
Interest cost....................................... 36 37 41 27 30 6
Expected return on plan assets...................... (47) (43) (41) (3) (3) (2)
Amortization of net actuarial gain.................. -- -- -- -- (4) (2)
Amortization of transition obligation............... 2 2 2 7 9 9
Amortization of prior service cost.................. (3) (3) -- (1) -- --
Curtailment and special termination benefits
expense.......................................... -- -- 21 -- -- --
---- ---- ---- --- --- ---
Net benefit cost.................................... $ (1) $ 6 $ 30 $30 $32 $11
==== ==== ==== === === ===
</TABLE>
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------------------- ----------------------------
SEPTEMBER 30, DECEMBER 31, SEPTEMBER 30, DECEMBER 31,
1998 1997 1998 1997
------------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
Weighted average assumptions
Discount rate........................... 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets.......... 9.50% 9.25% 7.50% 8.50%
Rate of compensation increase........... 4.50% 4.50% -- --
</TABLE>
Actuarial estimates for the Company's postretirement benefits plans assumed
a weighted average annual rate of increase in the per capita costs of covered
health care benefits of 10 percent through 2000, gradually decreasing to 6
percent by the year 2008. Assumed health care cost trends have a significant
effect on the amounts reported for other postretirement benefit plans. A
one-percentage point change in assumed health care cost trends would have the
following effects:
<TABLE>
<CAPTION>
1998 1997
----- -----
(IN MILLIONS)
<S> <C> <C>
One Percentage Point Increase
Aggregate of Service Cost and Interest Cost for 1998 at
September 30 and for 1997 at December 31............... $ 0.7 $ 0.6
Accumulated Postretirement Benefit Obligation for 1998 at
September 30 and for 1997 at December 31............... $ 9.9 $ 9.1
One Percentage Point Decrease
Aggregate of Service Cost and Interest Cost for 1998 at
September 30 and for 1997 at December 31............... $(0.6) $(0.6)
Accumulated Postretirement Benefit Obligation for 1998 at
September 30 and for 1997 at December 31............... $(9.1) $(8.2)
</TABLE>
Retirement Savings Plan
The Company maintains a defined contribution plan covering all employees of
the Company. During the first six months of 1996, the Company made matching
contributions equal to a participant's basic contributions of up to 6 percent
where the participant had fewer than 10 years of employment with the Company, or
up to 8 percent where the participant had 10 or more years of employment with
the Company. In February 1996, the Company changed its matching contribution to
75 percent of a participant's basic contributions of up to 6 percent, with the
matching contribution being made in Company stock. Amounts
69
<PAGE> 84
expensed under the plan were approximately $9 million, $9 million and $4 million
for the years ended December 31, 1998, 1997, and 1996, respectively.
11. EMPLOYEE SEPARATION AND ASSET IMPAIRMENT CHARGE
During the first quarter of 1996, the Company adopted a program to reduce
operating costs through work force reductions and improved work processes and
adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of. As a result of the workforce reduction
program and the adoption of SFAS No. 121, the Company recorded a special charge
of $99 million ($47 million for employee separation costs and $52 million for
asset impairments) in the first quarter of 1996.
The employee separation charge included approximately $26 million for
expected severance-related costs and $21 million for pension costs related to
special termination benefits and work force reductions. The special charge for
pension-related costs will have no cash impact outside of the normal funding of
the Company's pension plan.
In accordance with SFAS No. 121, the Company determined the fair value of
certain assets based on discounted future cash flows. The resultant non-cash
charge for asset impairments included approximately $44 million for the
impairment of certain natural gas gathering, processing, and production
facilities and $8 million for the write-off of a regulatory asset established
upon the adoption of SFAS No. 112, Employers' Accounting for Postemployment
Benefits, but not recoverable through the Company's rate settlement filed with
FERC in March 1996.
12. PREFERRED STOCK OF SUBSIDIARY
In November 1996, EPTPC issued 6 million shares of 8 1/4% cumulative
preferred stock with a par value of $50 per share for $296 million (net of
issuance costs). The preferred stock is redeemable, at the option of EPTPC,
after December 31, 2001, at a redemption price equal to $50 per share, plus
dividends accrued and unpaid up to the date of redemption.
During 1998, 1997, and 1996, dividends of approximately $25 million, $25
million, and $3 million, respectively, were paid on the cumulative preferred
stock. Approximately $2 million is reflected in 1996 as minority interest for
the 20 days EPTPC was included in the Consolidated Statements of Income.
13. SEGMENT INFORMATION
The Company adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, effective January 1, 1998.
Accordingly, the Company has segregated its business activities into five
segments: Tennessee Gas Pipeline segment, El Paso Natural Gas segment, El Paso
Field Services segment, El Paso Energy Marketing segment, and El Paso Energy
International segment. These segments are strategic business units that offer a
variety of different energy products and services. They are managed separately
as each business requires different technology and marketing strategies.
The Tennessee Gas Pipeline segment, which includes the interstate pipeline
systems of TGP, Midwestern, and East Tennessee, transports natural gas to the
northeast, midwest, and mid-Atlantic sections of the U.S. including the states
of Tennessee, Virginia and Georgia as well as the New York City, Chicago, and
Boston metropolitan areas. The El Paso Natural Gas segment, which includes the
interstate pipeline systems of EPNG and MPC, transports natural gas primarily to
the California market. The El Paso Field Services segment provides natural gas
gathering, products extraction, dehydration, purification, compression and
intrastate transmission services. The El Paso Energy Marketing segment markets
and trades natural gas, power, and petroleum products and participates in the
development and ownership of domestic power generation projects. The El Paso
Energy International segment develops and operates energy infrastructure
facilities worldwide.
70
<PAGE> 85
The accounting policies of the individual segments are the same as those of
the Company, as a whole, as described in Note 1. Certain business segments'
earnings are largely derived from the earnings on equity investments which are
reported in Other, net in the Consolidated Statements of Income. Accordingly,
the Company evaluates segment performance, based on EBIT. To the extent
practicable, results of operations for the years ended December 31, 1997, and
1996 have been reclassified to conform to the current business segment
presentation, although such results are not necessarily indicative of the
results which would have been achieved had the revised business segment
structure been in effect during that period.
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
-------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic......................... $ 728 $ 473 $ 194 $4,000 $ -- $5,395
Foreign.......................... -- -- -- 323 58 381
Intersegment revenue............... 38 2 59 17 -- 116
Depreciation and amortization...... 143 61 47 3 9 263
Operating income................... 332 215 60 5 (28) 584
Other, net......................... 26 2 15 4 53 100
Earnings before interest and
taxes............................ 358 217 75 9 25 684
Assets
Domestic......................... 4,995 1,742 1,426 762 281 9,206
Foreign.......................... -- -- -- 73 581 654
Capital expenditures............... 138 31 107 2 119 397
Equity investments................. 74 -- 87 -- 436 597
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1997
-------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic......................... $ 765 $ 518 $360 $3,757 $ -- $5,400
Foreign.......................... -- -- -- 218 13 231
Intersegment revenue............... 33 2 20 20 -- 75
Depreciation and amortization...... 137 56 33 4 1 231
Operating income................... 304 255 66 (31) (24) 570
Other, net......................... 14 5 8 3 26 56
Earnings before interest and
taxes............................ 318 260 74 (28) 2 626
Assets
Domestic......................... 5,179 1,838 852 859 180 8,908
Foreign.......................... -- -- -- 16 238 254
Capital expenditures............... 111 84 62 8 21 286
Equity investments................. 64 -- 24 44 241 373
</TABLE>
71
<PAGE> 86
<TABLE>
<CAPTION>
SEGMENTS
FOR THE YEAR ENDED OF DECEMBER 31, 1996
-------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic......................... $47 $510 $276 $2,177 $-- $3,010
Intersegment revenue............... 1 1 15 6 -- 23
Depreciation and amortization...... 12 58 27 4 -- 101
Operating income................... 14 209 35 23 (3) 278
Other, net......................... 2 14 -- 1 (1) 16
Earnings before interest and
taxes............................ 16 223 35 24 (4) 294
</TABLE>
The reconciliations of revenues for reportable segments to total
consolidated revenues are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
------------------------
1998 1997 1996
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Total revenues for segments................................. $5,892 $5,706 $3,033
Other revenues.............................................. 6 7 2
Elimination of intersegment revenue......................... (116) (75) (23)
------ ------ ------
Total consolidated revenues....................... $5,782 $5,638 $3,012
====== ====== ======
</TABLE>
The reconciliations of other, net for reportable segments to total
consolidated other, net are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Total other, net for segments............................... $100 $ 56 $ 16
Corporate other, net........................................ 38 1 (11)
---- ---- ----
Total consolidated other, net..................... $138 $ 57 5
==== ==== ====
</TABLE>
The reconciliations of EBIT to income before income taxes and minority
interest are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
-------------------
1998 1997 1996
---- ----- ----
(IN MILLIONS)
<S> <C> <C> <C>
Total EBIT for segments..................................... $684 $ 626 $294
Corporate expenses, net..................................... 40 48 119
Interest and debt expense................................... 267 238 110
---- ----- ----
Income before income taxes and minority
interest........................................ $377 $ 340 $ 65
==== ===== ====
</TABLE>
The reconciliations of assets for reportable segments to total consolidated
assets are presented below.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------
1998 1997
-------- -------
(IN MILLIONS)
<S> <C> <C>
Total assets for segments................................... $ 9,860 $9,162
Corporate and other assets.................................. 209 370
------- ------
Total consolidated assets......................... $10,069 $9,532
======= ======
</TABLE>
72
<PAGE> 87
The Company did not have gross revenue from any customer equal to, or in
excess of, ten percent of consolidated operating revenue for the years ended
December 31, 1998, 1997, and 1996.
14. INVENTORIES
Inventories consisted of the following at December 31:
<TABLE>
<CAPTION>
1998 1997
----- -----
(IN MILLIONS)
<S> <C> <C>
Materials and supplies...................................... $45 $42
Gas in storage.............................................. 4 26
--- ---
Total............................................. $49 $68
=== ===
</TABLE>
15. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
<TABLE>
<CAPTION>
1998 1997
------ ------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost
Tennessee Gas Pipeline.................................... $2,438 $2,289
El Paso Natural Gas....................................... 2,417 2,454
El Paso Field Services.................................... 1,118 1,022
El Paso Energy Marketing.................................. 47 78
El Paso Energy International.............................. 283 79
Corporate and Other....................................... 103 82
------ ------
6,406 6,004
Less accumulated depreciation and depletion................. 1,546 1,395
------ ------
4,860 4,609
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,481 2,507
------ ------
Total property, plant, and equipment, net................... $7,341 $7,116
====== ======
</TABLE>
16. EARNINGS PER SHARE
In March 1997, the Financial Accounting Standards Board issued SFAS No.
128, Earnings Per Share, which establishes new guidelines for calculating
earnings per share. The pronouncement is effective for reporting periods ending
after December 15, 1997. SFAS No. 128 requires companies to present both a basic
and diluted earnings per share amount on the face of the statement of income and
to restate prior period earnings per share amounts to comply with this standard.
Basic and diluted earnings per share amounts calculated in accordance with SFAS
No. 128 are presented below for the years ended December 31.
<TABLE>
<CAPTION>
1998 1997
------------------------------------ ------------------------
AVERAGE AVERAGE
SHARES EARNINGS SHARES
NET INCOME OUTSTANDING PER SHARE NET INCOME OUTSTANDING
---------- ----------- --------- ---------- -----------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Basic.................. $225 115.8 $1.94 $186 114.0
=====
Effect of dilutive
securities
Stock options........ -- 2.5 -- 2.1
Trust preferred
securities......... 8 6.2 -- --
Restricted stock..... -- 1.4 -- 1.3
---- ----- ---- -----
Diluted................ $233 125.9 $1.85 $186 117.4
==== ===== ===== ==== =====
<CAPTION>
1997 1996
--------- ------------------------------------
AVERAGE
EARNINGS SHARES EARNINGS
PER SHARE NET INCOME OUTSTANDING PER SHARE
--------- ---------- ----------- ---------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Basic.................. $1.63 $38 72.3 $0.53
===== =====
Effect of dilutive
securities
Stock options........ -- 1.0
Trust preferred
securities......... -- --
Restricted stock..... -- --
--- ----
Diluted................ $1.59 $38 73.3 $0.52
===== === ==== =====
</TABLE>
73
<PAGE> 88
17. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Interest.................................................. $266 $249 $ 85
Income tax payments (refunds)............................. (93) (34) 49
</TABLE>
See Note 2, for a discussion of the non-cash investing transactions related
to certain acquisitions.
18. INVESTMENT IN AFFILIATED COMPANIES (UNAUDITED)
The Company holds investments in various affiliates which are accounted for
on the equity method of accounting. The principal equity method investments are
the Company's investments in international pipelines, interstate pipelines,
power generation plants, gathering systems and natural gas storage facilities.
Summarized financial information of the Company's proportionate share of 50
percent or less owned companies and majority owned unconsolidated subsidiaries
accounted for by the equity method of accounting is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
COMPANIES OWNED 50% OR LESS 1998 1997 1996
- --------------------------- ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating results data:
Revenues and other income................................. $202 $130 $98
Costs and expenses........................................ 156 103 68
Net income................................................ 46 26 30
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
---------------
1998 1997
------ ------
<S> <C> <C>
Financial position data:
Current assets............................................ $ 182 $ 78
Non-current assets........................................ 1,941 1,033
Short-term debt........................................... 175 25
Other current liabilities................................. 75 50
Long-term debt............................................ 1,028 640
Other non-current liabilities............................. 171 67
Equity in net assets...................................... 674 329
</TABLE>
74
<PAGE> 89
19. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.
<TABLE>
<CAPTION>
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1998
Operating revenues............................... $1,252 $1,615 $1,296 $1,619
Operating income................................. 140 112 113 141
Net income....................................... 60 52 55 58
Basic earnings per common share.................. 0.52 0.45 0.47 0.50
Diluted earnings per share....................... 0.49 0.43 0.45 0.48
1997
Operating revenues............................... $1,577 $1,251 $ 979 $1,831
Operating income................................. 137 120 125 139
Net income....................................... 52 44 43 47
Basic earnings per common share.................. 0.45 0.38 0.38 0.43
Diluted earnings per share....................... 0.44 0.37 0.37 0.42
</TABLE>
75
<PAGE> 90
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
El Paso Energy Corporation:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14.(a) 1. present fairly, in all material respects, the
consolidated financial position of El Paso Energy Corporation as of December 31,
1998 and 1997, and the consolidated results of its operations and its cash flows
for each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule listed in the index appearing under Item 14.(a) 2.
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and the financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and the financial statement schedule based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinions expressed
above.
PricewaterhouseCoopers LLP
Houston, Texas
March 9, 1999
76
<PAGE> 91
SCHEDULE II
EL PASO ENERGY CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996
(IN MILLIONS)
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------- ---------- ------------------- ---------- ---------
CHARGED
BALANCE AT TO COSTS CHARGED BALANCE
BEGINNING AND TO OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
1998
Allowance for doubtful accounts.......... $ 56 $ 7 $ 4 $(29)(a) $ 38
Valuation allowance on deferred tax
assets................................ 8 -- 4 (7) 5
1997
Allowance for doubtful accounts.......... $ 64 $ 53 $ -- $(61)(a) $ 56
Valuation allowance on deferred tax
assets................................ -- -- 8(b) -- 8
1996
Allowance for doubtful accounts.......... $ 11 $ 6 $ 51(c) $ (4)(a) $ 64
</TABLE>
- ---------------
(a) Primarily accounts written off.
(b) Due to acquisition of Gulf States Gas Pipeline Company.
(c) Primarily due to acquisition of EPTPC.
77
<PAGE> 92
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information appearing under the captions "Proposal No. 1 -- Election of
Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in
EPEC's proxy statement for the 1999 Annual Meeting of Stockholders is
incorporated herein by reference. Information regarding executive officers of
EPEC is presented in Item 1, Business, of this Form 10-K under the caption
"Executive Officers of the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in EPEC's
proxy statement for the 1999 Annual Meeting of Stockholders is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information appearing under the caption "Security Ownership of a Certain
Beneficial Owner and Management" in EPEC's proxy statement for the 1999 Annual
Meeting of Stockholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. Financial statements.
The following consolidated financial statements of the Company are included
in Part II, Item 8 of this report:
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Statements of Income...................... 42
Consolidated Balance Sheets............................ 43
Consolidated Statements of Cash Flows.................. 44
Consolidated Statements of Stockholders' Equity........ 45
Consolidated Statements of Comprehensive Income........ 46
Notes to Consolidated Financial Statements............. 47
Report of independent accountants...................... 76
2. Financial statement schedules and supplementary information
required to be submitted.
Schedule II -- Valuation and qualifying accounts....... 77
Schedules other than that listed above are omitted
because they are not applicable
3. Exhibit list............................................. 79
</TABLE>
(B) REPORTS ON FORM 8-K:
None.
78
<PAGE> 93
EL PASO ENERGY CORPORATION
EXHIBIT LIST
DECEMBER 31, 1998
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
2 -- Agreement and Plan of Merger, dated July 16, 1998, by and
among EPEC, EPNG, and El Paso Energy Merger Company
(Exhibit 2.1 to EPEC's Form 8-K, filed August 3, 1998,
File No. 1-14365).
3.A -- Restated Certificate of Incorporation of EPEC, dated July
16, 1998; Certificate of Designation, Preferences and
Rights of Series A Junior Participating Preferred Stock
of EPEC, dated July 16, 1998, as amended (Exhibit 3.1 to
EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365).
3.B -- By-laws of EPEC, as amended dated October 21, 1998
(Exhibit 3.B to EPEC's Form 10-Q, filed November 12,
1998, File No. 1-14365 (the "EPEC 1998 Third Quarter
10-Q")).
4.A -- Amended and Restated Shareholder Rights Agreement,
between EPEC and BankBoston, N.A., dated January 20, 1999
(Exhibit 1 to EPEC's Registration Statement on Form 8-A/A
Amendment No. 1, filed January 29, 1999, File No.
1-14365).
4.B -- Amended and Restated Declaration of Trust of El Paso
Energy Capital Trust I dated March 16, 1998 (Exhibit 4.4
to EPNG's Form 8-K, filed March 17, 1998, File No.
1-2700); First Amendment to the Amended and Restated
Declaration of Trust of El Paso Energy Capital Trust I,
dated August 1, 1998 (Exhibit 4.3 of EPEC's Form 8-K,
filed August 3, 1998, File No. 1-14365).
4.C -- Subordinated Debt Securities Indenture dated March 1,
1998, between EPNG and The Chase Manhattan Bank as
Trustee (Exhibit 4.1 to EPNG's Form 8-K, filed March 17,
1998, File No. 1-2700); First Supplemental Indenture
dated March 17, 1998, between EPNG and The Chase
Manhattan Bank, as Trustee (Exhibit 4.2 to EPNG's Form
8-K, filed March 17, 1998, File No. 1-2700); Second
Supplemental Indenture, dated August 1, 1998 between EPEC
and The Chase Manhattan Bank, as Trustee (Exhibit 4.2 to
EPEC's Form 8-K, filed August 3, 1998, File No. 1-14365).
4.D -- 4 3/4% Convertible Subordinated Debenture due 2028
(Exhibit 4.6 to EPNG's Form 8-K, filed March 17, 1998,
File No. 1-2700).
4.E -- Certificate of Trust Preferred Security (Exhibit 4.5 to
EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700).
4.F -- Trust Preferred Securities Guarantee Agreement issued by
EPNG dated March 17, 1998 (Exhibit 4.7 to EPNG's Form
8-K, filed March 17, 1998, File No. 1-2700); First
Amendment to Trust Preferred Securities Guarantee
Agreement issued by EPEC dated August 1, 1998, (Exhibit
4.4 to EPEC's Form 8-K, filed August 3, 1998, File No.
1-14365).
</TABLE>
79
<PAGE> 94
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.A -- $750 million 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of October 29, 1997,
by and among EPNG, TGP, The Chase Manhattan Bank,
Citibank, N.A., Morgan Guaranty Trust Company of New York
and certain other banks (Exhibit 10.A to the EPEC 1998
Third Quarter 10-Q); First Amendment to the $750 million
364-Day Revolving Credit and Competitive Advance Facility
dated as of October 9, 1998, among EPNG, TGP, The Chase
Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust
Company of New York, and certain other banks (Exhibit
10.B to the EPEC 1998 Third Quarter 10-Q); Guarantee,
dated as of August 28, 1998, made by EPEC in favor of The
Chase Manhattan Bank, as Administrative Agent for several
banks and other financial institutions from time to time
parties to the $750 million 364-Day Revolving Credit and
Competitive Advance Facility dated as of October 29,
1997, by and among EPNG, TGP, The Chase Manhattan Bank,
Citibank, N.A., Morgan Guaranty Trust Company of New
York, and certain other banks (Exhibit 10.C to the EPEC
1998 Third Quarter 10-Q).
*10.A.1 -- Joinder Agreement dated December 7, 1998, made by EPEC to
the $750 million 364-Day Revolving Credit and CAF Advance
Facility Agreement, by and among EPNG, TGP, The Chase
Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust
Company of New York.
10.B -- $750 million 5-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of October 29, 1997,
by and among EPNG, TGP, The Chase Manhattan Bank,
Citibank, N.A., Morgan Guaranty Trust Company of New
York, and certain other banks (Exhibit 10.D to the EPEC
1998 Third Quarter 10-Q); First Amendment to the $750
million 5-Year Revolving Credit and Competitive Advance
Facility dated as of October 9, 1998, among EPNG, TGP,
The Chase Manhattan Bank, Citibank, N.A., Morgan Guaranty
Trust Company of New York, and certain other banks
(Exhibit 10.E to the EPEC 1998 Third Quarter 10-Q);
Guarantee, dated as of August 28, 1998, made by EPEC in
favor of The Chase Manhattan Bank, as Administrative
Agent for several banks and other financial institutions
from time to time parties to the $750 million 5-Year
Revolving Credit and Competitive Advance Facility dated
as of October 29, 1997, by and among EPNG, TGP, The Chase
Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust
Company of New York, and certain other banks (Exhibit
10.F to the EPEC 1998 Third Quarter 10-Q).
*10.B.1 -- Joinder Agreement dated December 7, 1998, made by EPEC to
the $750 million 5-Year Revolving Credit and CAF Advance
Facility Agreement, by and among EPNG, TGP, The Chase
Manhattan Bank, Citibank, N.A., Morgan Guaranty Trust
Company of New York.
*+10.C -- Omnibus Compensation Plan dated January 1, 1992;
Amendment No. 1 effective as of April 1, 1998; Amendment
No. 2 effective as of August 1, 1998; Amendment No. 3
effective as of December 3, 1998; and Amendment No. 4
effective as of January 20, 1999.
*+10.D -- 1995 Incentive Compensation Plan, Amended and Restated
effective as of December 3, 1998.
+10.E -- 1995 Compensation Plan for Non-Employee Directors,
Amended and Restated effective as of August 1, 1998
(Exhibit 10.H to the EPEC 1998 Third Quarter 10-Q).
*+10.F -- Stock Option Plan for Non-Employee Directors, Amended and
Restated effective as of January 20, 1999.
</TABLE>
80
<PAGE> 95
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.G -- 1995 Omnibus Compensation Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.J to the EPEC
1998 Third Quarter 10-Q).
*+10.G.1 -- Amendment No. 1 to the 1995 Omnibus Compensation Plan
effective as of December 3, 1998; Amendment No. 2 to the
1995 Omnibus Compensation Plan effective as of January
20, 1999.
*+10.H -- Supplemental Benefits Plan, Amended and Restated
effective as of December 3, 1998.
+10.I -- Senior Executive Survivor Benefit Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.M to
the EPEC 1998 Third Quarter 10-Q).
*+10.J -- Deferred Compensation Plan, Amended and Restated
effective as of December 3, 1998.
+10.K -- Key Executive Severance Protection Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.O to
the EPEC 1998 Third Quarter 10-Q).
+10.L -- Director Charitable Award Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.P to the EPEC
1998 Third Quarter 10-Q).
+10.M -- Strategic Stock Plan, Amended and Restated effective as
of August 1, 1998 (Exhibit 10.Q to the EPEC 1998 Third
Quarter 10-Q).
*+10.M.1 -- Amendment No. 1 to the Strategic Stock Plan, effective as
of December 3, 1998; Amendment No. 2 to the Strategic
Stock Plan, effective as of January 20, 1999.
+10.N -- Domestic Relocation Policy, effective November 1, 1996
(Exhibit 10.Q to EPNG's Form 10-K for 1997, File No.
1-2700).
+10.O -- Employment Agreement dated July 31, 1992 between EPNG and
William A. Wise (Exhibit 10.R to the EPEC 1998 Third
Quarter 10-Q); Amendment to Employment Agreement dated
January 29, 1996, between EPNG and William A. Wise
(Exhibit 10.U.1 to EPNG's Form 10-K for 1995, File No.
1-2700).
*+10.P -- Letter Agreement dated January 13, 1995 between EPNG and
William A. Wise.
+10.Q -- Promissory Note dated May 30, 1997, made by William A.
Wise to EPEC (Exhibit 10.R to EPNG's Form 10-Q, filed May
15, 1998, File No. 1-2700; Amendment to Promissory Note
dated November 20, 1997 (Exhibit 10.R to EPNG's Form
10-Q, filed May 15, 1998, File No. 1-2700).
+10.S -- Letter Agreement dated February 22, 1991, between EPNG
and Britton White Jr. (Exhibit 10.V to the EPEC 1998
Third Quarter 10-Q).
*18 -- Letter regarding Change in Accounting Principles.
*21 -- Subsidiaries of EPEC.
*23 -- Consent of Independent Accountants.
*27 -- Financial Data Schedule.
</TABLE>
81
<PAGE> 96
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Energy Corporation has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 9th day of March 1999.
EL PASO ENERGY CORPORATION
Registrant
By /s/ WILLIAM A. WISE
------------------------------------
William A. Wise
Chairman of the Board, President,
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
El Paso Energy Corporation and in the capacities and on the dates indicated:
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ WILLIAM A. WISE Chairman of the Board, March 9, 1999
- ----------------------------------------------------- President, Chief Executive
(William A. Wise) Officer and Director
/s/ H. BRENT AUSTIN Executive Vice President and March 9, 1999
- ----------------------------------------------------- Chief Financial Officer
(H. Brent Austin)
/s/ JEFFREY I. BEASON Vice President and Controller March 9, 1999
- ----------------------------------------------------- (Chief Accounting Officer)
(Jeffrey I. Beason)
/s/ BYRON ALLUMBAUGH Director March 9, 1999
- -----------------------------------------------------
(Byron Allumbaugh)
/s/ JUAN CARLOS BRANIFF Director March 9, 1999
- -----------------------------------------------------
(Juan Carlos Braniff)
/s/ PETER T. FLAWN Director March 9, 1999
- -----------------------------------------------------
(Peter T. Flawn)
/s/ JAMES F. GIBBONS Director March 9, 1999
- -----------------------------------------------------
(James F. Gibbons)
/s/ BEN F. LOVE Director March 9, 1999
- -----------------------------------------------------
(Ben F. Love)
/s/ KENNETH L. SMALLEY Director March 9, 1999
- -----------------------------------------------------
(Kenneth L. Smalley)
/s/ MALCOLM WALLOP Director March 9, 1999
- -----------------------------------------------------
(Malcolm Wallop)
</TABLE>
82
<PAGE> 97
REPORT OF MANAGEMENT
To the Board of Directors and Stockholders
El Paso Energy Corporation
The management of El Paso Energy Corporation is responsible for the
preparation, integrity, and fairness of the accompanying financial statements as
well as other information presented in this Annual Report. Such responsibility
includes judgments, estimates, the selection of appropriate generally accepted
accounting principles, the consistent application of such principles, and
devising and maintaining adequate systems of internal controls.
In the opinion of management, the financial statements are fairly stated
and have been prepared in conformity with generally accepted accounting
principles, and, to that end, the Company and its subsidiaries maintain a system
of internal control which: provides reasonable assurance that transactions are
recorded properly for the preparation of financial statements; safeguards assets
against unauthorized acquisition, use or disposition; maintains accountability
for assets; requires proper authorization and accountability for all
transactions; provides for a comparison of the recorded and existing assets at
reasonable intervals and requires appropriate action with respect to any
difference; and promotes compliance with applicable laws and regulations. The
financial statements have been audited by the independent accounting firm,
PricewaterhouseCoopers LLP, which was given unrestricted access to all financial
records and related data. Their audit was conducted in accordance with generally
accepted auditing standards and included a review of internal control to the
extent deemed necessary for the purpose of their audit.
Management is responsible for the effectiveness of its system of internal
control. This is accomplished through established codes of conduct, accounting
and other control systems, policies and procedures, employee selection and
training, appropriate delegation of authority, and segregation of
responsibilities. To further ensure compliance with established standards and
related control procedures, the Company conducts an ongoing, substantial
corporate audit program. Corporate auditors monitor the operation of the
Company's internal control system and report findings and recommendations to
management, including corrective action taken to address control deficiencies
and opportunities for improving the system. Even an effective internal control
system has inherent limitations, including the possibility of circumvention or
overriding of controls, and therefore can provide only reasonable assurance with
respect to financial statement preparation.
The Audit Committee of the Board of Directors, composed entirely of
Directors who are not employees of El Paso Energy Corporation, has met privately
and separately with PricewaterhouseCoopers LLP, corporate auditors, and
management of the Company to review accounting, auditing, internal control, and
financial reporting matters.
March 9, 1999
/s/ H. BRENT AUSTIN
H. Brent Austin
Executive Vice President and
Chief Financial Officer
/s/ JEFFREY I. BEASON
Jeffrey I. Beason
Vice President, Controller
and Chief Accounting Officer
<PAGE> 98
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
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 MARCH 31, 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 1-14365
---------------------
EL PASO ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0568816
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET 77002
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)
</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 $3.00 per share. Shares outstanding on May 10,
1999: 121,491,576
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 99
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 Energy Corporation and its subsidiaries
Court of Appeals...... United States Court of Appeals for the District of Columbia Circuit
EBIT.................. Earnings before interest expense and income taxes, excluding affiliated
interest income
Edison................ Southern California Edison Company
EPA................... United States Environmental Protection Agency
EPEC.................. El Paso Energy Corporation, unless the context otherwise requires
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 Negara, 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.
TransAmerican......... TransAmerican Natural Gas Corporation
</TABLE>
i
<PAGE> 100
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED MARCH 31,
-------------------
1999 1998
------- -------
<S> <C> <C>
Operating revenues.......................................... $ 1,494 $ 1,619
------- -------
Operating expenses
Cost of gas and other products............................ 1,068 1,209
Operation and maintenance................................. 183 180
Depreciation, depletion, and amortization................. 71 65
Taxes, other than income taxes............................ 27 24
------- -------
1,349 1,478
------- -------
Operating income............................................ 145 141
------- -------
Other (income) and expense
Interest and debt expense................................. 73 64
Other -- net.............................................. (45) (22)
------- -------
28 42
------- -------
Income before income taxes, minority interest, and
cumulative effect of accounting change.................... 117 99
Income tax expense.......................................... 40 35
Minority interest
Preferred stock dividend requirement of subsidiary........ 6 6
------- -------
Income before cumulative effect of accounting change........ 71 58
Cumulative effect of accounting change, net of income tax... (13) --
------- -------
Net income.................................................. $ 58 $ 58
======= =======
Comprehensive income........................................ $ 49 $ 57
======= =======
Basic earnings per common share
Income before cumulative effect of accounting change...... $ 0.62 $ 0.50
Cumulative effect of accounting change, net of income
tax.................................................... (0.12) --
------- -------
Net income................................................ $ 0.50 $ 0.50
======= =======
Diluted earnings per common share
Income before cumulative effect of accounting change...... $ 0.58 $ 0.48
Cumulative effect of accounting change, net of income
tax.................................................... (0.10) --
------- -------
Net income................................................ $ 0.48 $ 0.48
======= =======
Basic average common shares outstanding..................... 116.0 115.9
======= =======
Diluted average common shares outstanding................... 127.8 121.7
======= =======
Dividends declared per common share......................... $ 0.20 $ 0.19
======= =======
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
1
<PAGE> 101
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
----------- ------------
(UNAUDITED)
<S> <C> <C>
Current assets
Cash and temporary investments............................ $ 90 $ 90
Accounts and notes receivable, net........................ 780 733
Materials and supplies.................................... 48 49
Other..................................................... 305 337
------- -------
Total current assets.............................. 1,223 1,209
Property, plant, and equipment, net......................... 7,191 7,220
Investments in unconsolidated affiliates.................... 973 600
Other....................................................... 1,079 1,009
------- -------
Total assets...................................... $10,466 $10,038
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable.......................................... $ 599 $ 724
Short-term borrowings (including current maturities of
long-term debt)........................................ 736 812
Other..................................................... 600 595
------- -------
Total current liabilities......................... 1,935 2,131
------- -------
Long-term debt, less current maturities..................... 3,082 2,552
------- -------
Deferred income taxes....................................... 1,589 1,564
------- -------
Other....................................................... 1,008 993
------- -------
Commitments and contingencies (See Note 4)
Company-obligated mandatorily redeemable convertible
preferred securities of El Paso Energy Capital Trust I.... 325 325
------- -------
Minority interest
Preferred stock of subsidiary............................. 300 300
------- -------
Other minority interest................................... 65 65
------- -------
Stockholders' equity
Common stock, par value $3 per share; authorized
275,000,000 shares; issued 125,529,432 and 124,434,110
shares, respectively................................... 377 373
Additional paid-in capital................................ 1,465 1,436
Retained earnings......................................... 494 460
Accumulated comprehensive income.......................... (23) (14)
Treasury stock (at cost) 4,233,028 and 4,149,099 shares,
respectively.................................... (92) (90)
Deferred compensation..................................... (59) (57)
------- -------
Total stockholders' equity........................ 2,162 2,108
------- -------
Total liabilities and stockholders' equity........ $10,466 $10,038
======= =======
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
2
<PAGE> 102
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
--------------
1999 1998
----- -----
<S> <C> <C>
Cash flows from operating activities
Net income................................................ $ 58 $ 58
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion, and amortization.............. 71 65
Deferred income taxes.................................. 23 24
Undistributed earnings in equity investees............. (11) (4)
Cumulative effect of accounting change, net of income
tax................................................... 13 --
Other.................................................. -- (2)
Working capital changes, net of the effect of
acquisitions........................................... 30 (54)
Other..................................................... (53) 23
----- -----
Net cash provided by operating activities......... 131 110
----- -----
Cash flows from investing activities
Capital expenditures...................................... (39) (47)
Investment in joint ventures and equity investees......... (443) (278)
Acquisition of EnCap Investments L.C...................... (36) --
Restricted cash deposited in escrow related to equity
investee............................................... (53) --
Other..................................................... 4 7
----- -----
Net cash used in investing activities............. (567) (318)
----- -----
Cash flows from financing activities
Net commercial paper borrowings (repayments).............. 354 (72)
Revolving credit borrowings............................... 220 --
Revolving credit repayments............................... (150) (45)
Long-term debt retirements................................ (21) (21)
Net proceeds from preferred securities of El
Paso Energy Capital Trust I issuance................... -- 317
Net proceeds from long-term note payable.................. 53 --
Dividends paid on common stock............................ (23) (22)
Other..................................................... 3 8
----- -----
Net cash provided by financing activities......... 436 165
----- -----
Decrease in cash and temporary investments.................. -- (43)
Cash and temporary investments
Beginning of period............................... 90 116
----- -----
End of period..................................... $ 90 $ 73
===== =====
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
3
<PAGE> 103
EL PASO ENERGY CORPORATION
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 March 31, 1999, and for the quarters ended March 31,
1999, and 1998, are unaudited. The condensed balance sheet at December 31, 1998,
is derived from audited financial statements. These financial statements do not
include all disclosures required by generally accepted accounting principles. 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 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 current presentation. Such reclassifications have
no effect on reported net income or stockholders' equity.
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. MERGER WITH SONAT INC.
In March 1999, the Company entered into a merger agreement with Sonat Inc.
See Item 2, Management's Discussion and Analysis of Financial Condition and
Results of Operations, Recent Developments for a further discussion.
3. ACQUISITIONS
In February 1999, the Company acquired a 51 percent ownership interest in
East Asia Power Resources Corporation ("EAPRC"), a publicly traded company in
the Philippines, for approximately $70 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 three power generation
facilities in the Philippines and owns an interest in one power generation
facility in China, with a total generating capacity of 289 megawatts. Electric
power generated by the facilities is supplied to a diversified base of customers
including National Power Corporation, the state-owned utility, private
distribution companies and industrial users.
In March 1999, El Paso Power Holding Company purchased a 50 percent
ownership interest in CE Generation LLC. The investment of approximately $254
million is accounted for under the equity method of accounting. CE Generation
LLC owns four natural gas-fired cogeneration projects in New York, Pennsylvania,
Texas and Arizona and eight geothermal facilities near the Imperial Valley in
southern California, which are qualifying facilities under the Public Utility
Regulatory Policy Act. In addition, two additional geothermal facilities are
currently under construction in southern California. Collectively, the 14 power
projects will have a combined electric generating capacity of approximately 900
megawatts.
In March 1999, EPFS acquired EnCap Investments L.C. ("EnCap"), a Texas
limited liability company, for $52 million, net of cash acquired. The purchase
price included $17 million in Company 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
4
<PAGE> 104
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.
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.
4. 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 significantly increased. PLN is
currently unable to pass this increase in cost on to its customers without
creating further political instability. 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, with a commitment to pay the balance when
financial aid is received. The difference between the current and prior exchange
rate has resulted in an outstanding balance due from PLN of $12 million at March
31, 1999. Recently, the Company met and discussed its situation and concerns
with the World Bank, the International Monetary Fund, the Overseas Private
Investment Corporation, and the U.S. Treasury Department in an attempt to
achieve a resolution through the Indonesian Minister of Finance. The Company met
with PLN in April 1999 to discuss payments in arrears and the terms of a
contract rationalization process proposed by PLN. The Company informed PLN that
all payments in arrears must first be received as a prerequisite to any further
discussions on contract rationalization. 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 cannot predict with certainty the outcome of
such discussions. The total investment in the Sengkang project was approximately
$26 million at March 31, 1999. Additionally, the Company has provided specific
recourse guarantees of up to $6 million for loans from the project lenders. All
other project debt is non-recourse. 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 250 megawatt power generating plant in
Manaus, Brazil. Power from the plant is currently sold under a four-year
contract to a subsidiary of Centrais Electricas do Norte do Brasil, S.A.,
("Electronorte"), denominated in Brazilian real. In January 1999, the real was
devalued. Under a provision in the contract, the Company is entitled to recover
a substantial portion of any devaluation. In April 1999, the contract with
Electronorte 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.
The contract for the Manaus power project provides for delay damages to be
paid to Electronorte if the specified construction schedule is not met.
Completion of the project was delayed beyond the originally scheduled completion
dates provided in the contract, and such delays have resulted in claims by
Electronorte for delay damages. The Company believes that any delay damages for
which it may ultimately be responsible 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
5
<PAGE> 105
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.
TGP -- 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 March 31, 1999, the demand portion had been fully collected and
$43 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 on
March 31, 1999. Upon approval of this report, TGP will refund approximately $14
million to its firm customers, which represents the amount collected in excess
of the $693 million recovered 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 on March 31, 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.
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 but clarifying that,
among other things, although the ultimate resolution as to the proper allocation
of costs would be applied retroactively to July 1, 1995, the cost of service
settlement does not allow TGP to recover from other customers any amounts that
TGP may ultimately be required to refund. In 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.
TGP has filed cash out reports for the period September 1993 through August
1998. TGP's filings showed a cumulative loss through August of 1998 of $3
million. The reports, as well as the accounting for customer imbalances, were
previously challenged by TGP's customers. In April 1999, FERC approved a
settlement that resolved outstanding FERC proceedings relating to the filed
cashout reports, subject to rehearing. The settlement provides a new mechanism
for accounting for TGP's cash out program.
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
6
<PAGE> 106
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.
EPNG -- In June 1995, EPNG filed with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In March 1996, EPNG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996, through December 31, 1997. In April 1997, FERC
approved EPNG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rates it
ultimately pays EPNG. In July 1997, FERC issued an order denying the requests
for rehearing of the April 1997 order and the settlement was implemented
effective July 1, 1997. Hearings to determine Edison's rates were completed in
May 1998, and an initial decision was issued by the presiding ALJ in July 1998.
EPNG and Edison have filed exceptions to the decision with FERC. If the ALJ's
decision is affirmed by FERC, EPNG believes that the resulting rates to Edison
would be such that no significant, if any, refunds in excess of the amounts
reserved would be required. Pending the final outcome, Edison continues to pay
the originally filed rates, subject to refund, and EPNG continues to provide a
reserve for such potential refunds.
Edison filed with the Court of Appeals a petition for review of FERC's
April 1997 and July 1997 orders, in which it challenged the propriety of FERC's
approving the settlement over Edison's objections to the settlement as a
customer of Southern California Gas Company. In December 1998, the Court of
Appeals issued its decision vacating and remanding FERC's order. In April 1999,
FERC issued an order requiring the parties to submit briefs setting forth their
positions as to whether FERC can approve the settlement over Edison's continuing
objections. EPNG cannot predict the outcome with certainty, but it believes that
FERC will ultimately approve the settlement.
The rate settlement establishes, among other things, base rates through
December 31, 2005. Such rates escalate annually beginning in 1998. In addition,
the settlement provides for settling customers to (i) pay $295 million
(including interest) as a risk sharing obligation, which approximates 35 percent
of anticipated revenue shortfalls over an 8 year period, resulting from certain
contract reductions and expirations identified in the settlement, (ii) receive
35 percent of additional revenues received by EPNG, above a threshold, for the
same eight-year period, and (iii) have the base rates increase or decrease if
certain changes in laws or regulations result in increased or decreased costs in
excess of $10 million a year. Through March 31, 1999, approximately $231 million
of the risk sharing obligation had been paid, and the remaining balance of $64
million will be collected by the end of 2003. At March 31, 1999, the balance of
the unearned risk sharing revenue was $215 million. This amount will be
recognized ratably through the year 2003.
In addition to other arrangements to offset the effects of the reduction in
firm capacity commitments referred to above, EPNG entered into three contracts
with Dynegy Inc. ("Dynegy") for the sale of substantially all of its turned back
firm capacity available to California as of January 1, 1998, (approximately 1.3
billion cubic feet) for a two-year period beginning January 1, 1998, at rates
negotiated pursuant to EPNG's tariff provisions and FERC policies. EPNG realized
$11 million in revenue in the first quarter of 1999 and anticipates realizing at
least $32 million in revenues during the remainder of 1999. Such revenue is
subject to the revenue sharing provisions of the rate settlement. The contracts
have a transport-or-pay provision requiring Dynegy to pay a minimum charge equal
to the reservation component of the contractual charge on at least 72 percent of
the contracted volumes each month in 1999. In the third quarter of 1999, EPNG
intends to remarket this capacity pursuant to EPNG's tariff provisions and FERC
regulations, subject to Dynegy's right of first refusal.
In December 1997, EPNG filed to implement several negotiated rate
contracts, including those with Dynegy. In a protest to this filing, three
shippers (producers/marketers) requested that FERC require EPNG to eliminate
certain provisions from the Dynegy contracts, to publicly disclose and repost
the contracts for
7
<PAGE> 107
competitive bidding, and to suspend their effectiveness. In an order issued in
January 1998, FERC rejected several of the arguments made in the protest and
allowed the contracts to become effective as of January 1, 1998, subject to
refund, and subject to the outcome of a technical conference, which was held in
March 1998. In June 1998, FERC issued an order rejecting the protests to the
Dynegy contracts, but required EPNG to file modifications with FERC to the
contracts clarifying the credits under the reservation reduction mechanism and
the recall rights of certain capacity. In addition, EPNG agreed to separately
post capacity covered by the Dynegy contracts which becomes available in the
future. Several parties have protested EPNG's compliance filing and/or requested
rehearing of FERC's June 1998 order. In June 1998, EPNG
filed a letter agreement in compliance with the June 1998 FERC order. In
September 1998, FERC issued
an order accepting the letter agreement subject to EPNG making additional
modifications. The additional
modifications to the letter agreement required further clarification of credits
available to Dynegy under the reservation reduction mechanism and the recall
rights of certain capacity. In October 1998, EPNG filed a revised letter
agreement with FERC and requested rehearing of the September 1998 order. The
issue is pending before FERC.
Under the revenue sharing provisions of its rate case settlement, EPNG was
obligated to return approximately $12 million of non-traditional fixed cost
revenues earned in 1998 to certain customers. This amount was credited to those
customers' transportation invoices between October 1998 and March 1999. EPNG
continues to reserve for the revenue sharing provisions. At March 31, 1999, EPNG
had a reserve of $4 million for additional amounts, which are expected to be
credited to customer accounts during the period September 1999 through March
2000.
In a November 1997 order, FERC reversed its previous decision and found
that EPNG's Chaco Station should be functionalized as a gathering, not
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.
TGP and EPNG, as interstate pipelines, are subject to FERC audits of their
books and records. EPNG currently has an open audit covering the years 1990
through 1995. FERC is expected to issue its final audit report in 1999. As part
of an industry-wide initiative, both EPNG's and 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 November 1993, TransAmerican filed a complaint in a Texas state court,
TransAmerican Natural Gas Corporation v. El Paso Natural Gas Company, et al.,
alleging fraud, tortious interference with contractual relationships, negligent
misrepresentation, economic duress, civil conspiracy, and violation of state
antitrust laws arising from a settlement agreement entered into by EPNG,
TransAmerican Natural Gas Corporation ("TransAmerican"), and others in 1990 to
settle litigation then pending and other potential claims. The complaint, as
amended, seeks actual damages of $1.5 billion and exemplary damages of $6
billion. EPNG is defending the matter in the State District Court of Dallas
County, Texas. In April 1996, a former employee of TransAmerican filed a related
case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al.
(including EPNG), seeking indemnification and other damages in unspecified
amounts relating to litigation consulting work allegedly performed for various
entities, including EPNG, in cases involving TransAmerican. EPNG filed a motion
for summary judgment in the TransAmerican case arguing that plaintiff's claims
are barred by a prior release executed by TransAmerican, by statues of
limitations, and by the final court judgment ending the original litigation in
1990. Following a hearing in January 1998, the court
8
<PAGE> 108
granted summary judgment in EPNG's favor on TransAmerican's claims based on
economic duress and negligent misrepresentation, but denied the motion as to the
remaining claims. In March 1999, the Court ruled in EPNG's favor, denying
TransAmerican's summary judgment motion which sought to dismiss EPNG's
counterclaims. In April 1999, EPNG filed a motion for partial summary judgment
as to
TransAmerican's claims of fraud, tortious interference and civil conspiracy.
That motion is currently set for hearing in June 1999. The TransAmerican trial
is set to commence in September 1999. In February 1998, EPNG filed a motion for
summary judgment in the Stone litigation arguing that all claims are baseless,
barred by statutes of limitations, subject to executed releases, or have been
assigned to TransAmerican. In June 1998, the court granted EPNG's motion in its
entirety and dismissed all the remaining claims in the Stone litigation. In
August 1998, the court denied Stone's motion for a new trial seeking
reconsideration of that ruling. Stone has appealed the court's ruling to the
Texas Court of Appeals in Houston, Texas. Based on information available at this
time, management believes that the claims asserted against it in both cases have
no factual or legal basis and 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 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 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 relevant states
regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies to specify the remediation
requirements at the Pennsylvania and New York stations. Remediation activities
in Pennsylvania are complete with the exception of some long-term groundwater
monitoring requirements. Remediation and characterization work at the compressor
stations under its consent order with the EPA and the jurisdiction of the New
York Department of Environmental Conservation is ongoing. 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
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<PAGE> 109
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, both wholly and partially owned, 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 does not intend to intervene in these actions. The Company believes the
complaint to be without merit.
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 March 31, 1999, the Company had reserves of
approximately $252 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. Capital expenditures are expected to range from approximately
$84 million to $109 million in the aggregate for the years 2000 through 2007.
These expenditures primarily relate to compliance with air regulations and, to a
lesser extent, control of water discharges.
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 March 31, 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 32 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
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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 reserve is 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.
5. SEGMENT INFORMATION
<TABLE>
<CAPTION>
SEGMENTS
FOR THE QUARTER ENDED MARCH 31, 1999
--------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenues from external customers....... $ 201 $ 118 $ 74 $1,084 $ 17 $ 1,494
Intersegment revenues.................. 7 -- 17 2 -- 26
Operating income (loss)................ 103 56 10 5 (16) 158
EBIT................................... 113 56 16 8 3 196
Segment assets......................... 4,887 1,728 1,459 968 1,029 10,071
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
FOR THE QUARTER ENDED MARCH 31, 1998
-------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenues from external customers........ $ 203 $ 114 $ 59 $1,227 $ 12 $1,615
Intersegment revenues................... 9 1 9 4 -- 23
Operating income (loss)................. 94 52 20 -- (7) 159
EBIT.................................... 98 52 24 -- 2 176
Segment assets.......................... 5,137 1,757 916 536 653 8,999
</TABLE>
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The reconciliations of EBIT to income before income taxes, minority
interest, and cumulative effect of accounting change are presented below for the
quarters ended March 31:
<TABLE>
<CAPTION>
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Total EBIT for reportable segments.......................... $196 $176
Corporate expenses, net..................................... (6) (13)
Interest and debt expense................................... (73) (64)
---- ----
Income before income taxes, minority interest, and
cumulative effect of accounting change.................... $117 $ 99
==== ====
</TABLE>
6. FINANCING TRANSACTIONS
In February 1999, DeepTech International, Inc. retired its 11% senior
promissory notes due 2000 in the amount of $16 million.
The average interest rate of short-term borrowings was 5.1% and 5.8% at
March 31, 1999 and December 31, 1998, respectively. The Company had short-term
borrowings, including current maturities of long-term debt, at March 31, 1999,
and December 31, 1998, as follows:
<TABLE>
<CAPTION>
1999 1998
----- ----
(IN MILLIONS)
<S> <C> <C>
EPEC revolving credit facility.............................. $ 350 $350
Commercial paper............................................ 694 340
Other credit facilities..................................... 130 60
Current maturities of long-term debt........................ 62 62
Less amount reclassified as long-term debt.................. (500) --
----- ----
$ 736 $812
===== ====
</TABLE>
In May 1999, EPEC issued $500 million aggregate principal amount of 6.75%
Senior Notes due 2009. Proceeds of approximately $496 million, net of issuance
costs, were used to repay approximately $350 million of outstanding debt under
EPEC's revolving credit facility and the remainder was used to repay commercial
paper. As a result of this transaction, $500 million of short-term borrowings
has been reclassified and reflected as long-term debt at March 31, 1999.
7. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment at March 31, 1999, and December 31, 1998,
consisted of the following:
<TABLE>
<CAPTION>
1999 1998
------ ------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost..................... $6,336 $6,285
Less accumulated depreciation and depletion................. 1,619 1,546
------ ------
4,717 4,739
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,474 2,481
------ ------
Total property, plant, and equipment, net................... $7,191 $7,220
====== ======
</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.
12
<PAGE> 112
8. EARNINGS PER SHARE
The computation of basic and diluted earnings per common share amounts are
presented below for the quarters ended March 31.
<TABLE>
<CAPTION>
1999 1998
--------------------- ---------------------
BASIC DILUTED BASIC DILUTED
-------- --------- ------- ---------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Income before cumulative effect of accounting change... $ 71 $ 71 $ 58 $ 58
Interest on trust preferred securities............... -- 3 -- --
------ ------ ----- -----
Adjusted income before cumulative effect of
accounting change................................. 71 74 58 58
Cumulative effect of accounting change, net of income
tax............................................... (13) (13) -- --
------ ------ ----- -----
Net income............................................. $ 58 $ 61 $ 58 $ 58
====== ====== ===== =====
Average common shares outstanding...................... 116 116 116 116
Effect of diluted securities
Restricted stock..................................... -- 2 -- 2
Stock options........................................ -- 2 -- 3
Trust preferred securities........................... -- 8 -- 1
------ ------ ----- -----
Adjusted average common shares outstanding............. 116 128 116 122
====== ====== ===== =====
Earnings per common share
Adjusted income before cumulative effect of
accounting change................................. $ 0.62 $ 0.58 $0.50 $0.48
Cumulative effect of accounting change, net of income
tax............................................... (0.12) (0.10) -- --
------ ------ ----- -----
Net income........................................... $ 0.50 $ 0.48 $0.50 $0.48
====== ====== ===== =====
</TABLE>
9. 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 is effective for all quarters in fiscal years beginning after June 15,
1999. The Company is currently evaluating the effects of this pronouncement.
13
<PAGE> 113
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.
RECENT DEVELOPMENTS
MERGER WITH SONAT INC.
In March 1999, the Company announced it had entered into a definitive
agreement to acquire Sonat Inc. ("Sonat"). The Company entered into the second
amended and restated agreement and plan of merger effective as of March 13,
1999, (the "Merger Agreement") with Sonat pursuant to which Sonat will merge
into the Company, and the Company will issue to Sonat stockholders one share of
Company common stock for each share of Sonat common stock owned by them, and the
Company's restated certificate of incorporation will be amended to authorize the
issuance of up to 750 million shares of common stock and 50 million shares of
preferred stock. The Company and Sonat are separately holding a special meeting
of their stockholders on June 10, 1999, to consider and vote on a proposal to
approve and adopt the Merger Agreement. If the Company's stockholders approve
the Merger Agreement, the Company intends to account for the merger as a pooling
of interests. If the Company's stockholders do not approve the Merger Agreement
and Sonat's stockholders do, Sonat will instead merge with a subsidiary of the
Company, and the Company will issue a fraction of a share of Company common
stock and a fraction of a depositary share representing a fractional interest in
a new series of senior voting preferred stock of the Company for each share of
Sonat common stock. The Company and Sonat will complete the merger only if a
number of conditions are satisfied or waived, including:
- Sonat stockholders adopt the Merger Agreement;
- no law or court order prohibits the transaction;
- all waiting periods under federal antitrust laws applicable to the merger
expire or terminate;
- all other regulatory approvals are received without conditions that would
have a material adverse effect on the financial condition, results of
operations, or cash flows of the Company's and Sonat's combined
businesses; and
- attorneys for the Company and Sonat issue opinions that the merger is
expected to be tax-free.
However, we cannot assure you that the Company and Sonat will complete the
merger even if all those conditions are satisfied.
Sonat is a diversified energy holding company. It is engaged through its
subsidiaries and joint ventures in domestic oil and natural gas exploration and
production, transmission and storage of natural gas, and natural gas and power
marketing. Sonat owns interests in approximately 14,000 miles of natural gas
pipelines extending across the southeastern U.S. from Texas to South Carolina
and Florida. Also, Sonat has interests in oil and gas producing properties in
Louisiana, Texas, Oklahoma, Arkansas, Alabama, New Mexico and the Gulf of
Mexico. Sonat owns approximately 1.6 trillion cubic feet equivalent of proved
natural gas and oil reserves based on estimates as of December 31, 1998.
RESULTS OF OPERATIONS
Consolidated EBIT for the quarter ended March 31, 1999, increased 17
percent to $190 million from $163 million in the first quarter of 1998.
Variances are discussed in the segment results below.
14
<PAGE> 114
SEGMENT RESULTS
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
--------------
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Tennessee Gas Pipeline...................................... $ 113 $ 98
El Paso Natural Gas......................................... 56 52
----- -----
Regulated segments........................................ 169 150
El Paso Field Services...................................... 16 24
El Paso Energy Marketing.................................... 8 --
El Paso Energy International................................ 3 2
----- -----
Non-regulated segments.................................... 27 26
Corporate expenses, net..................................... (6) (13)
----- -----
Total EBIT................................................ $ 190 $ 163
===== =====
</TABLE>
Tennessee Gas Pipeline
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
--------------
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Operating revenues.......................................... $ 208 $ 212
Operating expenses.......................................... (105) (118)
Other -- net................................................ 10 4
----- -----
EBIT...................................................... $ 113 $ 98
===== =====
</TABLE>
Operating revenues for the quarter ended March 31, 1999, were $4 million
lower than for the same period of 1998 primarily due to lower GSR revenue in
1999, a favorable customer settlement in the first quarter of 1998, and lower
miscellaneous operating revenue. The decrease was partially offset by the
favorable resolution of a regulatory issue.
Operating expenses for the quarter ended March 31, 1999, were $13 million
lower than for the same period of 1998 primarily due to lower system fuel costs
associated with operating efficiencies related to lower throughput levels, the
favorable resolution of certain regulatory issues and lower operating expenses.
Other -- net for the quarter ended March 31, 1999, was $6 million higher
than for the same period of 1998 primarily due to the favorable resolution of
regulatory and contractual issues and higher earnings from equity investments.
15
<PAGE> 115
El Paso Natural Gas
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
-------------
1999 1998
---- ----
(IN MILLIONS)
<S> <C> <C>
Operating revenues.......................................... $118 $115
Operating expenses.......................................... (62) (63)
---- ----
EBIT...................................................... $ 56 $ 52
==== ====
</TABLE>
Operating revenues for the quarter ended March 31, 1999, were $3 million
higher than for the same period of 1998 primarily due to an increase in
non-traditional revenues including revenues from the sale of capacity to Dynegy.
El Paso Field Services
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
-------------
1999 1998
---- ----
(IN MILLIONS)
<S> <C> <C>
Gathering and treating margin............................... $ 40 $ 39
Processing margin........................................... 9 14
Other margin................................................ -- 2
---- ----
Total gross margin................................ 49 55
Operating expenses.......................................... (39) (35)
Other -- net................................................ 6 4
---- ----
EBIT...................................................... $ 16 $ 24
==== ====
</TABLE>
Total gross margin for the quarter ended March 31, 1999, was $6 million
lower than for the same period of 1998 primarily due to a decrease in the
processing margin. The decrease resulted from lower liquids prices during the
first quarter of 1999 compared to the same period of 1998. The slight increase
in the gathering and treating margin primarily resulted from higher volumes
attributable to the global compression project which was completed in September
1998. This increase was offset by lower volumes attributable to the sale of the
natural gas gathering and treating assets in the Anadarko Basin in September
1998.
Operating expenses for the quarter ended in March 31, 1999, were $4 million
higher than for the same period of 1998 primarily due to an increase in
amortization expense attributable to the acquisition of DeepTech International
Inc.
Other -- net for the quarter ended March 31, 1999, was $2 million higher
than for the same period of 1998 due to additional earnings from equity
investments primarily attributable to the acquisition of DeepTech International
Inc.
16
<PAGE> 116
El Paso Energy Marketing
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
-------------
1999 1998
---- ----
(IN MILLIONS)
<S> <C> <C>
Natural gas margin.......................................... $ 17 $ 6
Power margin................................................ 2 7
---- ----
Total gross margin................................ 19 13
Operating expenses.......................................... (14) (13)
Other -- net................................................ 3 --
---- ----
EBIT...................................................... $ 8 $ --
==== ====
</TABLE>
Total gross margin for the quarter ended March 31, 1999, was $6 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
largely due to the first quarter 1998 income recognition from electric power
transactions, partially offset by the contribution from power generation
facilities acquired in December 1998.
Operating expenses for the quarter ended March 31, 1999, were $1 million
higher than for the same period of 1998 primarily due to expenses associated
with acquired power generation facilities.
Other -- net for the quarter ended March 31, 1999, was $3 million higher
than for the same period of 1998 primarily due to additional earnings from the
acquisition of a 50 percent ownership interest in CE Generation LLC in March
1999.
El Paso Energy International
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED MARCH 31,
----------------
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Operating revenues.......................................... $ 17 $ 12
Operating expenses.......................................... (33) (19)
Other -- net................................................ 19 9
---- ----
EBIT...................................................... $ 3 $ 2
==== ====
</TABLE>
Operating revenues for the quarter ended March 31, 1999, were $5 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.
Operating expenses for the quarter ended March 31, 1999, were $14 million
higher than for the same period of 1998 due to the consolidation of the Manaus
Power project and an increase in general and administrative expenses primarily
attributable to higher project development costs reflecting increased
project-related activities.
Other -- net for the quarter ended March 31, 1999, was $10 million higher
than for the same period of 1998 primarily due to higher earnings from equity
investments.
Corporate expenses, net
Net corporate expenses for the quarter ended March 31, 1999, were $7
million lower than for the same period of 1998 primarily due to lower costs
related to the Company's employee incentive plans and lower benefits costs.
17
<PAGE> 117
INTEREST AND DEBT EXPENSE
Interest and debt expense for the quarter ended March 31, 1999, was $9
million higher than for the same period of 1998 primarily due to increased
borrowings used to fund acquisitions, capital expenditures, and other investing
expenditures.
INCOME TAX EXPENSE
The effective tax rate for the quarter ended March 31, 1999, was lower than
the rate for the same period of 1998 primarily as a result of increased
consolidated foreign income subject to foreign tax rates different than U.S. tax
rates and increased equity income from unconsolidated foreign affiliates
recorded net of foreign income taxes for which no provision for U.S. income tax
is required.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $21 million higher for the
quarter ended March 31, 1999, compared to the same period of 1998. The increase
was primarily attributable to a take-or-pay refund to EPNG customers in February
1998 and other working capital changes. The increase was partially offset by net
income tax refunds received in 1998 and non-working capital changes including
lower GSR collections in 1999.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was $567 million for the quarter
ended March 31, 1999. Expenditures related to joint ventures and equity
investments were primarily for the acquisition of the 50 percent ownership
interest in CE Generation LLC, as well as the acquisition of a 51 percent
ownership interest in the East Asia Power project. Other investment activity
included the acquisition of EnCap. Internally generated funds, 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,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
CASH FROM FINANCING ACTIVITIES
Net cash provided by financing activities was $436 million for the quarter
ended March 31, 1999.
Short-term borrowings, supplemented by internally generated funds, were used to
fund capital and equity investments, retire long-term debt, pay dividends, and
for other corporate purposes.
The following table reflects quarterly dividends declared and paid on
EPEC's common stock:
<TABLE>
<CAPTION>
AMOUNT PER
DECLARATION DATE COMMON SHARE PAYMENT DATE TOTAL AMOUNT
---------------- ------------ ------------ -------------
(IN MILLIONS)
<S> <C> <C> <C>
October 22, 1998....................... $0.19125 January 4, 1999 $22
January 21, 1999....................... $0.20000 April 1, 1999 $23
</TABLE>
In April 1999, the board of directors of EPEC declared a quarterly dividend
of $0.20 per share on EPEC's common stock, payable on July 1, 1999, to
stockholders of record on June 4, 1999. Also during the first quarter of 1999,
quarterly dividends of $6 million were paid on the 8 1/4% cumulative preferred
stock, series A of EPTPC.
Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
18
<PAGE> 118
At March 31, 1999, the Company had approximately $450 million available
under its revolving credit facilities. The availability of borrowings under the
Company's credit agreements is subject to certain specified conditions, which
management believes it currently meets.
In May 1999, EPEC issued $500 million aggregate principal amount of 6.75%
Senior Notes due 2009. Proceeds of approximately $496 million, net of issuance
costs, were used to repay approximately $350 million of outstanding debt under
EPEC's revolving credit facility and the remainder was used to repay commercial
paper. As a result of this transaction, $500 million of short-term debt has been
reclassified and reflected as long-term debt at March 31, 1999.
COMMITMENTS AND CONTINGENCIES
See Note 4, which is incorporated herein by reference.
OTHER
PPN POWER PROJECT
In March 1999, the Company signed a sale and purchase agreement, subject to
the project lenders' consent, to acquire a 26 percent interest in a $295 million
power plant in Tamil Nadu, India. 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. The transaction is expected to close before
the end of the second quarter of 1999.
YEAR 2000
The Company 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.
In recognition of the importance of Year 2000 issues and their potential
impact to the Company, 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 the Company 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. To date, the
responses from such third parties, although generally encouraging, are
inconclusive. As a result, 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.
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
19
<PAGE> 119
necessary, its unit, system, integration and acceptance testing. The Company
estimates that approximately one-fourth of the work of these phases remains, and
expects each to be substantially completed by mid-1999.
The implementation phase involves placing the converted or replaced key
automated systems into operation. In some cases, this phase will also involve
the implementation of contingency plans needed to support business functions and
processes that may be interrupted by Year 2000 failures that are outside of the
Company's control. The Company has completed more than three-fourths of the
implementation phase, which is expected to be substantially completed by
mid-1999.
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 the
impact of a significant failure. The Company plans to have its contingency plan
completed by mid-1999. The Year 2000 contingency plan will continue to be
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 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 believes that most of the international facilities in which it has
significant
20
<PAGE> 120
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 $12 million and $19 million. Of
these estimated costs, the Company expects between $5 million and $9 million to
be capitalized and the remainder to be expensed. As of March 31, 1999, the
Company has incurred expenses of approximately $8 million and has capitalized
costs of approximately $2 million. The Company has previously only traced
incremental expenses related to its 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 most of the costs reported above in the
remediation, implementation and contingency planning phases of the project. As
described herein, the Company and Sonat have entered into an agreement which, if
approved, will result in the merger of the Company and Sonat. If the merger is
consummated, Sonat's Year 2000 risks, liabilities and expenses will be assumed
by the Company. Based on its due diligence investigation in connection with the
merger, the Company is not aware of any material Year 2000 risks, liabilities,
or expenses that are not disclosed in Sonat's filings with the U.S. Securities
and Exchange Commission. 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 9, which is incorporated herein by reference.
21
<PAGE> 121
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 are 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.
22
<PAGE> 122
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Financial Information, Note 4, 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
None.
ITEM 5. OTHER INFORMATION
None.
ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as part of this report. Exhibits
designated with a "+" constitute a management contract or compensatory plan or
arrangement required to be filed as an exhibit to this report.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.E.1 -- Amendment No. 1, effective March 9, 1999, to the 1995
Compensation Plan for Non-Employee Directors, Amended and
Restated effective as of August 1, 1998.
27 -- Financial Data Schedule.
</TABLE>
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 EPEC 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 EPEC and its consolidated subsidiaries.
b. Reports on Form 8-K
EPEC filed a report under Item 5 and Item 7 on Form 8-K, dated March 15,
1999, with respect to the Sonat Merger Agreement. In addition, EPEC filed a
report under Item 5 and Item 7 on Form 8-K and Form 8-K/A dated April 23, 1999
and April 30, 1999, respectively, disclosing preliminary unaudited pro forma
financial information of EPEC and Sonat giving effect to the proposed merger.
EPEC filed a report under Item 5 and Item 7 on Form 8-K, dated May 10, 1999
with respect to the issuance of $500 million aggregate principal amount of 6.75%
Senior Notes due 2009.
23
<PAGE> 123
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 ENERGY CORPORATION
Date: May 12, 1999 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: May 12, 1999 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Vice President and Controller
(Chief Accounting Officer)
24
<PAGE> 124
Item 7. Financial Statements and Exhibits.
Exhibit No. Description
- ----------- -----------
23 Consent of PricewaterhouseCoopers LLP
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, Sonat
Inc. has duly caused this report to be signed on its behalf by the undersigned
hereunto duly authorized.
SONAT INC.
By /s/ William A. Smith
-------------------------------
William A. Smith
Executive Vice President
and General Counsel
July 6, 1999
<PAGE> 125
EXHIBIT INDEX
Exhibit No. Description
- ---------- -----------
23 Consent of PricewaterhouseCoopers LLP
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the registration
statement of Sonat Inc. (the "Company") on Form S-3 (File No. 333-62383) and
the registration statements of the Company on Form S-8 (File Nos. 33-64367
and 33-50142) of our report dated March 9, 1999 relating to El Paso Energy
Corporation's consolidated financial statements as of December 31, 1998 and
1997, and for each of the three years in the period ended December 31, 1998,
which appears in the Company's Current Report on Form 8-K dated July 6, 1999.
PricewaterhouseCoopers LLP
Houston, Texas
July 6, 1999
