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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 1996
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 1-2700
EL PASO NATURAL GAS COMPANY
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 74-0608280
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 757-2131
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, par value $3 per
share............................... New York Stock Exchange
Preferred Stock Purchase Rights....... New York Stock Exchange
9.45% Notes due 1999.................. New York Stock Exchange
8 5/8% Debentures due 2012............ New York Stock Exchange
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. [ ]
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 February 28,
1997, computed by reference to the closing sale price of the registrant's common
stock on the New York Stock Exchange on such date: $3,152,151,839.
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 February 28,
1997: 58,775,906
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: El Paso Natural Gas Company's definitive Proxy Statement for the
1997 Annual Meeting of Stockholders, to be filed not later than 120 days after
the end of the fiscal year covered by this report, is incorporated by reference
into Part III.
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EL PASO NATURAL GAS COMPANY
TABLE OF CONTENTS
CAPTION PAGE
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Glossary.............................................................. ii
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 11
Item 3. Legal Proceedings........................................... 11
Item 4. Submission of Matters to a Vote of Security Holders......... 12
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 13
Item 6. Selected Financial Data..................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 15
Item 8. Financial Statements and Supplementary Data................. 28
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 59
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 59
Item 11. Executive Compensation...................................... 59
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 59
Item 13. Certain Relationships and Related Transactions.............. 59
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 59
Signatures.................................................. 64
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GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
DEFINITIONS
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ALJ............................... Administrative Law Judge
Bcf............................... Billion cubic feet
Bcf/d............................. Billion cubic feet per day
Board............................. Board of directors of El Paso Natural Gas Company
CFE............................... Comision Federal de Electricidad, the Mexican government-owned
electric utility
Company........................... El Paso Natural Gas Company, now doing business as El Paso Energy
Corporation, and its subsidiaries, unless the context otherwise
requires
Cornerstone....................... Cornerstone Natural Gas, Inc., a wholly owned subsidiary of El Paso
Field Services Company
Court of Appeals.................. United States Court of Appeals for the District of Columbia Circuit
Dakota............................ Dakota Gasification Company
CPUC.............................. California Public Utilities Commission
Dth............................... Decatherm
East Tennessee.................... East Tennessee Natural Gas Company, a wholly owned subsidiary of
Tennessee Gas Pipeline Company
Edison............................ Southern California Edison Company
EPA............................... United States Environmental Protection Agency
EPEI.............................. El Paso Energy International Company, a wholly owned subsidiary of
El Paso Natural Gas Company
EPEM.............................. El Paso Energy Marketing Company (formerly Eastex Energy Inc.), a
wholly owned subsidiary of El Paso Natural Gas Company, unless the
context requires otherwise
EPFS.............................. El Paso Field Services Company, a wholly owned subsidiary of El
Paso Natural Gas Company
EPG............................... El Paso Natural Gas Company, unless the context otherwise requires
EPNC.............................. El Paso New Chaco Company, a wholly owned subsidiary of El Paso
Natural Gas Company
EPTPC............................. El Paso Tennessee Pipeline Co. (formerly Tenneco Inc.), an indirect
subsidiary of El Paso Natural Gas Company
FERC.............................. the Federal Energy Regulatory Commission
GSR............................... Gas supply realignment
Holding Company................... A new Delaware corporation, proposed to be formed to become the
holding company parent of the Company
IRS............................... Internal Revenue Service
Mgal/d............................ Thousand gallons per day
Midwestern........................ Midwestern Gas Transmission Company, a wholly owned indirect
subsidiary of Tennessee Gas Pipeline Company
MMcf/d............................ Million cubic feet per day
Mdth/d............................ Thousand decatherms per day
MPC............................... Mojave Pipeline Company, a wholly owned subsidiary of El Paso
Natural Gas Company
MW(s)............................. Megawatt(s)
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DEFINITIONS
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New Tenneco....................... Tenneco Inc., subsequent to the Merger and Distributions,
consisting of the automotive parts, packaging and administrative
services businesses
NGLs.............................. Natural gas liquids
Odd-Lot Holders................... Shareholders of El Paso Natural Gas Company owning beneficially
fewer than 100 shares of El Paso Natural Gas Company's common stock
Old Tenneco....................... Tenneco Inc. (renamed El Paso Tennessee Pipeline Co.), prior to its
acquisition by the Company
OPEB.............................. Other Postretirement Employee Benefits
OPIC.............................. Overseas Private Investment Corporation
OTC............................... Over-The-Counter
PASA.............................. Pipeline Authority of South Australia
PCB(s)............................ Polychlorinated biphenyl(s)
Pemex............................. Pemex Gas y Petroquimica Basica, a Mexican state-owned company
PG&E.............................. Pacific Gas & Electric Company
Plan.............................. Dividend Reinvestment and Common Stock Purchase Plan
Premier........................... Premier Gas Company, a wholly owned subsidiary of El Paso Energy
Marketing Company
Program........................... Continuous Odd-Lot Stock Sales Program
PRP(s)............................ Potentially Responsible Party(ies)
PSC............................... Public Service Company of Colorado
Reorganization.................... Proposed merger of El Paso Natural Gas Company with a direct
subsidiary of the Holding Company to reorganize the Company into a
holding company structure
RI/FS............................. Remedial Investigation/Feasibility Study
SAR(s)............................ Stock Appreciation Right(s)
SEC............................... Securities and Exchange Commission
SFAS.............................. Statement of Financial Accounting Standards
SoCal............................. Southern California Gas Company
Tcf............................... Trillion cubic feet
TEPCO............................. The El Paso Company, formerly the parent company of El Paso Natural
Gas Company
TDEC.............................. Tennessee Department of Environment and Conservation
TGP............................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
TGTC.............................. TransColorado Gas Transmission Company
TransAmerican..................... TransAmerican Natural Gas Corporation
TransTexas........................ TransTexas Gas Corporation
Transwestern...................... Transwestern Pipeline Company
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PART I
ITEM 1. BUSINESS
GENERAL
EPG is a Delaware corporation incorporated in 1928. The Company's principal
operations include the interstate and intrastate transportation, gathering and
processing of natural gas; the marketing of natural gas, natural gas liquids,
electricity, crude oil and refined products; 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 and 7,900 miles of
gathering systems connecting the nation's principal natural gas supply regions
to the four largest gas consuming regions in the U.S., namely the Gulf Coast,
California, the Northeast and the Midwest. In recognition of changes in the
natural gas industry and the manner in which EPG manages its businesses, and in
order to facilitate a more detailed understanding of the various activities in
which it engages, EPG began doing business under the name El Paso Energy
Corporation (effective April 22, 1996) and has segregated its business
activities into three segments: (i) natural gas transmission; (ii) field and
merchant services; and (iii) corporate and other, which includes the Company's
international development activities. For information concerning the operating
revenues, operating income and identifiable assets attributable to each of these
segments, see Note 12 of Item 8, Financial Statements and Supplementary Data.
In December 1996, the Company completed the $4 billion acquisition of EPTPC
(the "Merger"), in a transaction accounted for as a purchase. The Merger was
effected in accordance with the Amended and Restated Agreement and Plan of
Merger dated as of June 19, 1996 (the "Merger Agreement"). In the Merger, Old
Tenneco changed its name to EPTPC. Prior to the Merger, Old Tenneco and its
subsidiaries effected 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 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 (the
"Distributions"). Following the Distributions, EPTPC's business consisted
principally of the interstate transportation of natural gas, as well as
unregulated business 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 continued the Company's effort to expand its presence in
non-regulated portions of the energy industry. As a result of the Merger, EPG
indirectly owns 100 percent of the common equity and approximately 75 percent of
the combined equity value of EPTPC. The remaining 25 percent of the combined
equity of EPTPC is comprised of $296 million of preferred stock issued in a
public offering by Old Tenneco on November 18, 1996, which remains outstanding.
In June 1996, the Company acquired Cornerstone. Cornerstone consisted of
approximately 700 miles of gathering and transportation systems and seven
natural gas processing and treating facilities principally located in Texas and
Louisiana. The Company acquired Eastex Energy Inc. in September 1995 and Premier
in December 1995. Effective July 1996, the name Eastex Energy Inc. was changed
to, and its subsidiaries were merged into, EPEM. EPEM is a full service natural
gas merchant which conducts wholesale gas marketing and related services on a
national basis. For a further discussion of these acquisitions, see Note 2 of
Item 8, Financial Statements and Supplementary Data.
NATURAL GAS TRANSMISSION
The natural gas transmission segment is comprised of five interstate
pipeline systems: the TGP System, the EPG System, the Midwestern System, the
East Tennessee System, and the MPC System, collectively referred to as the
Interstate System. The Interstate System totals approximately 26,600 miles of
transmission pipeline.
The TGP System. The TGP System consists of approximately 14,800 miles of
pipeline with a design capacity of 5,460 MMcf/d. During 1996, TGP transported
natural gas representing 99 percent of its capacity. The TGP System serves the
northeast section of the U.S., including the New York City and Boston
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metropolitan areas. The multiple-line system begins in the gas-producing regions
of Texas and Louisiana, including the Gulf of Mexico.
The EPG System. The EPG System consists of approximately 9,900 miles of
pipeline with a design capacity of 4,744 MMcf/d. During 1996, EPG transported
natural gas representing approximately 74 percent of its capacity. California is
the single largest market served by the EPG System, which also serves markets in
Nevada, Arizona, New Mexico, Texas and northern Mexico. The EPG System is
connected to one of the most prolific supply basins in the nation, the San Juan
Basin of northern New Mexico and southern Colorado, and also accesses natural
gas supplies in the Permian and Anadarko Basins.
The Midwestern System. The Midwestern System consists of approximately 400
miles of pipeline with a design capacity of 800 MMcf/d. During 1996, Midwestern
transported natural gas representing approximately 82 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 630 MMcf/d.
During 1996, East Tennessee transported natural gas representing approximately
56 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.
The MPC System. The MPC System consists of approximately 450 miles of
pipeline with a design capacity of approximately 400 MMcf/d. During 1996, MPC
transported natural gas representing
approximately 75 percent of its capacity. The MPC System is connected with the
EPG System at Topock, Arizona and extends to customers in the vicinity of
Bakersfield, California.
Other. The Company has a one-third interest in TGTC, which was formed for
the purpose of constructing and operating a 292-mile pipeline with a design
capacity of approximately 300 MMcf/d, from northwestern Colorado to the San Juan
Basin. The Company also owns a 17.8 percent interest in Portland Natural Gas
Transmission System, L.P., which is developing a 224-mile pipeline with a
projected capacity of 178 MMcf/d running from the Canadian border near
Pittsburg, New Hampshire, to Dracut, Massachusetts.
REGULATORY ENVIRONMENT
The Interstate System is 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 began 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 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 accorded to
gas owned by the pipelines. FERC's stated purpose was to ensure that the
pipelines' monopoly over the transportation of natural gas did not distort 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 which 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. In Order No. 636,
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, and
remanded to FERC several issues for further explanation, including further
explanation of FERC's decision to allow pipelines to recover 100 percent of GSR
costs and FERC's requirement that pipelines allocate 10 percent of GSR costs to
interruptible
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transportation customers. In February 1997, FERC reaffirmed its decision to
allow pipelines to recover 100 percent of GSR costs. In addition, FERC modified
the requirement that pipelines allocate 10 percent of GSR costs to interruptible
customers to permit pipelines to propose an allocation of any percentage of such
costs to their interruptible customers. For a further discussion of GSR issues
related to TGP, see Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations, Item 3, Legal Proceedings, and Note 6 of
Item 8, Financial Statements and Supplementary Data.
TGP. In December 1994, TGP filed for a general rate increase (the "1995
Rate Case"). In January 1995, FERC accepted the filing, suspended its
effectiveness for the maximum period of five months pursuant to normal
regulatory process, and set the matter for hearing. On July 1, 1995, TGP began
collecting rates, subject to refund, reflecting an $87 million increase in TGP's
annual revenue requirement. A Stipulation and Agreement (the "Stipulation") was
filed with an ALJ in this proceeding in April 1996. The Stipulation resolves the
rates that are the subject of the 1995 Rate Case, including a structural rate
design change that results in a larger proportion of TGP's transportation
revenues being dependent upon throughput. Under the Stipulation, TGP is required
to refund, upon final approval of the Stipulation, the difference between the
revenues collected under the July 1, 1995 motion rates and the revenues that
would have been collected pursuant to the rates underlying the Stipulation. In
October 1996, FERC approved the Stipulation with certain modifications and
clarifications which are not material. In January 1997, FERC issued an order
denying requests for rehearing of the October 1996 order. One party to the rate
proceeding, a competitor of TGP, filed with the Court of Appeals, in February
1997, a Petition for Review of the FERC orders approving the Stipulation.
For a discussion of recent FERC proceedings relating to the recovery by TGP
of certain environmental costs as a component of the rates charged by its
interstate pipeline operations, see Note 6 of Item 8, Financial Statements and
Supplementary Data.
EPG. In June 1995, EPG made a filing with FERC for approval of new system
rates for mainline transportation to be effective January 1, 1996. In July 1995,
FERC accepted and suspended EPG's filing to be effective January 1, 1996,
subject to refund and certain other conditions. FERC also set EPG's rates for
hearing.
In March 1996, EPG filed a comprehensive offer of settlement which, if
approved by FERC, would resolve issues related to the above-mentioned rate case
and issues surrounding certain contract reductions and expirations that occur
from January 1, 1996, through December 31, 1997. The settlement provides for,
among other things: (i) a long-term rate stability plan which establishes base
rates for a 10-year period from January 1, 1996, through December 31, 2005,
subject to annual escalation after 1997; (ii) payments over 8 years, or less, to
EPG by its customers totaling $255 million prior to interest, representing
approximately 35 percent of the revenues associated with the contract reductions
and expirations; (iii) the sharing between EPG (65 percent) and its customers
(35 percent) of revenues in excess of a threshold, as defined in the settlement;
and (iv) a mechanism to reflect in the base rate increases or decreases
resulting from laws or regulations which impact costs at a level in excess of
$10 million a year. The settlement provides that any party desiring not to be
bound by the settlement may have its rates determined pursuant to procedures
established by FERC. FERC staff, the regulatory agencies of California, Arizona,
and Nevada, the state of New Mexico, and customers representing 95 percent of
the firm throughput on EPG's mainline transmission system support EPG's
settlement.
In March 1996, Edison, a firm shipper on EPG's system, filed its own offer
of settlement. One party supported Edison's proposal, while several other
parties independently contested elements of EPG's settlement. In January 1997,
the Chief ALJ certified EPG's settlement to FERC and severed the contesting
parties. Edison requested reconsideration of the certification. Edison and other
contesting parties also provided notice of their intention to preserve their
rights to contest this matter, including through litigation. A decision by FERC
on both the certification and the merits of EPG's settlement is pending.
For a further discussion of regulatory matters related to TGP and EPG, see
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations and Note 6 of Item 8, Financial Statements and Supplementary Data.
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MARKETS AND COMPETITION
The Interstate System faces varying degrees of competition from alternative
energy sources, such as electricity, hydroelectric power, coal, and oil. The
potential consequences of the proposed restructuring of the electric power
industry are currently unclear. It may benefit the natural gas industry by
creating more demand for 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 increase in gas demand as a result of such
restructuring.
The TGP System. Customers of TGP include natural gas producers, marketers
and end-users, as well as other gas transmission and distribution companies.
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 four years,
principally in the year 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 this
area. Although TGP intends to pursue 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. Accordingly, the Company presently is unable to
ascertain whether or not the expiration and renegotiation, extension and/or
replacement of these transportation contracts will have a materially adverse
effect on the Company's financial position or results of operations.
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 gas and the cost
of transportation. Competition between pipelines is particularly intense in
TGP's supply area, Louisiana and Texas. TGP also faces varying degrees of
competition from alternative energy sources, such as electricity, coal, and oil.
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
impacted by the foregoing competitive factors.
The EPG System. EPG maintains a significant competitive position in the
California market by virtue of the fact that 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. EPG'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. In addition, gas shipped to California across the EPG System represented
about 33 percent of the natural gas consumed in the state in 1996.
Interstate pipeline capacity utilization to California is currently
approximately 63 percent and is not expected to reach 100 percent until sometime
in the next decade, assuming no new interstate pipeline construction. Currently,
EPG has firm transportation contracts covering 88 percent of its 3.3 Bcf/d of
capacity to California. By 1998, that figure will likely drop significantly,
perhaps to as low as 53 percent. EPG's largest contracts for interstate capacity
to California are with SoCal and PG&E, which have both exercised contractual
options to relinquish certain capacity rights. For a further discussion of the
SoCal and PG&E capacity relinquishments, see Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations.
EPG faces significant competition from three other
companies -- Transwestern, Kern River Gas Transmission Company and Pacific Gas
Transmission Company -- each of which transports natural gas to the California
market. The combined capacity of these three companies and EPG transporting
natural gas to the California market is approximately 6.9 Bcf/d. In 1996, the
demand for interstate pipeline capacity to California averaged 4.3 Bcf/d.
Competition generally occurs on the basis of the delivered cost of natural gas
into the SoCal and PG&E distribution systems.
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FIELD AND MERCHANT SERVICES
The field and merchant services segment provides natural gas gathering,
products extraction, treating, compression and intrastate transmission services.
In addition, the segment purchases, markets and trades natural gas, NGLs,
electricity, crude and refined products, and provides risk management services
associated with these commodities. This segment owns or has interests in
approximately 7,900 miles of gathering systems located in the country's most
prolific and active gas production areas, including the San Juan, Anadarko and
Permian Basins and East Texas, South Texas, Louisiana and the Gulf of Mexico. In
addition, this segment owns or has interests in approximately 1,500 miles of
intrastate transmission pipeline, which supply natural gas to the Interstate
System and support the Company's trading and marketing operations. The field and
merchant services segment also owns or has interests in 18 natural gas
processing and treating facilities. The Company's field services business is
conducted principally through EPFS, Cornerstone (acquired in June 1996), and the
field services activities of EPTPC (acquired in December 1996). The Company's
merchant services business is conducted principally through EPEM, El Paso Gas
Marketing Company, and the energy marketing activities of EPTPC. The merchant
services business has 14 sales offices throughout the U.S. and Canada with
headquarters in Houston, Texas.
FIELD SERVICES
EPFS, incorporated in June 1993, was formed for the purpose of owning,
operating, acquiring and constructing natural gas gathering, processing and
other related field facilities. Effective January 1, 1996, EPG transferred to
EPFS its non-certificated assets along with certain assets that were no longer
subject to FERC jurisdiction. These assets included major gathering systems in
the San Juan, Anadarko, and Permian Basins. From this initial asset base, EPFS
began to implement plans to increase gathering and processing volumes through a
strategy of project developments, acquisitions, and joint ventures.
Major project developments for EPFS include the construction of the largest
cryogenic liquids extraction plant (the "Chaco Plant") in the continental U.S.,
the construction of the Masters Creek liquids extraction plant and the
construction of the Hart Canyon compression project. The Chaco Plant, located in
San Juan County, New Mexico, was constructed at a cost of approximately $77
million and replaced a lean oil recovery plant previously operated by EPFS. The
Chaco Plant was designed to process 600 MMcf/d and extract 50,000 barrels of
NGLs per day. In May 1996, the Chaco Plant began processing natural gas, and by
September 1996 was experiencing recovery rates of over 90 percent for ethane and
99 percent for liquids heavier than ethane.
EPFS completed the construction of the Masters Creek cryogenic liquids
extraction plant in November 1996. This plant, located in Rapides Parish,
Louisiana, has the capacity to process 50 MMcf/d. EPFS completed the Hart Canyon
compression project in November 1995, which consisted of looping several
pipelines and adding three field compressor sites. The project added 7,675
horsepower of compression and allowed a certain portion of the system in the San
Juan Basin to experience lower operating pressures, which has resulted in a 21
percent increase in production or approximately 15 MMcf/d.
The field services assets of EPTPC, acquired in December 1996, include
approximately 1,500 miles of gathering and intrastate transportation systems and
four liquids extraction plants. These assets are principally located in the Gulf
Coast region of Texas.
Effective June 1996, EPFS acquired Cornerstone for approximately $94
million, exclusive of acquisition costs. This acquisition added approximately
700 miles of gathering and transportation systems and seven liquids extraction
and natural gas treating facilities. These assets are principally located in
Louisiana and East Texas.
In February 1996, EPFS acquired the Linc and Pandale gathering systems from
Tejas Power Corporation. These systems are located in West Texas and currently
gather approximately 45 MMcf/d.
In 1996, EPFS formed a joint venture with KN Energy in order to complete
the construction of the Coyote Gulch natural gas treating plant. The plant,
constructed at a cost of approximately $15 million, is
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located in La Plata County, Colorado, and has the capacity to treat 120 MMcf/d.
Initial treating began in December 1996.
The following table provides information at December 31, 1996 concerning
the natural gas gathering and transportation facilities, as well as natural gas
gathered for the years ended December 31:
AVERAGE VOLUME
MILES GATHERING (MDTH/D)
OF CAPACITY --------------------------------
SYSTEM PIPELINE(1) (MMCF/D)(2) 1996 1995 1994
------ ----------- ----------- -------- -------- --------
San Juan Basin............................ 5,500 1,180 1,139 1,042 1,091
Permian Basin............................. 1,074 515 223 164 170
Anadarko Basin............................ 667 425 135 116 92
Louisiana/East Texas(3)................... 704 696 280 -- --
Gulf Coast Region(3)...................... 1,480 1,936 700 -- --
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(1) Mileage amounts shown are approximate for the total system and have not been
reduced to reflect EPFS's net ownership interest.
(2) All capacity information reflects EPFS's net ownership and is subject to
increases or decreases depending on operating pressures and point of
delivery into or out of the system.
(3) Average daily volumes for Cornerstone, acquired in June 1996, and for the
field services activities of EPTPC, acquired in December 1996, are reflected
from the date of acquisition.
The following table provides information concerning the processing
facilities at December 31, 1996:
AVERAGE AVERAGE
INLET NGLS
INLET VOLUME PRODUCTION
CAPACITY (MDTH/D) (MGAL/D)
PLANT (MMCF/D)(1) 1996 1996
----- ----------- -------- ----------
San Juan Basin(2).......................................... 600 557 1,315
Louisiana/East Texas(3).................................... 242 160 304
Gulf Coast Region(3)....................................... 91 63 107
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(1) All capacity information reflects EPFS's net ownership.
(2) Average daily NGLs production since commencement of Chaco Plant operations
in May 1996.
(3) Average daily volumes and NGLs production for Cornerstone, acquired in June
1996, and for the field services activities of EPTPC, acquired in December
1996, are reflected from the date of acquisition.
EPFS focuses on providing its customers with wellhead-to-mainline field
services, including gathering, products extraction, dehydration, purification
and compression. EPFS, together with EPEM, is able to offer its customers fully
bundled gas services with a broad range of pricing options as well as financial
risk management products. EPFS also provides well-ties and can offer real-time
information services, including electronic wellhead gas flow measurement.
EPFS provides 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 extracted. EPFS, through Cornerstone, may also
purchase gas at the wellhead and, if there is no local market, arrange
transportation on intrastate or interstate pipelines and resell the gas to local
distribution companies, utilities, commercial or industrial end-users, or other
natural gas marketing companies.
Competition
EPFS operates in a highly competitive environment that includes independent
gathering and processing companies, interstate and intrastate companies, gas
marketers, and oil and gas producers. EPFS competes for
6
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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.
MERCHANT SERVICES
The Company, through its merchant services business, markets and trades
natural gas, NGLs, electricity, crude and refined products and has emerged as
one of North America's largest energy marketing and trading companies, ranking
among the top 10 companies in volume of gas marketed in 1996. In December 1996,
EPEM marketed physical and financial volumes of over 7,200 Mdth/d.
A broad range of energy products and services is provided, including supply
aggregation, transportation management and integrated price risk management.
EPEM maintains a diverse natural gas supplier and customer base serving
producers, utilities (including local distribution companies and power plants),
municipalities, and a variety of industrial and commercial end users. In 1996,
the Company served approximately 400 producer/suppliers, and approximately 700
sales customers in 26 states with transportation of gas supplies on 40
pipelines.
Set forth below are marketed physical and financial gas volumes for the
years ended December 31:
1996(1) 1995 1994
------- -------- -----
(MDTH/D)
----------------------------
Marketed Gas Volumes...................................... 6,320 773 355
(1) Average daily volumes for the energy marketing activities of EPTPC, acquired
in December 1996, are reflected from the date of acquisition.
Demand for natural gas products and services has primarily resulted from
the deregulation effects of FERC Order No. 636, the commercialization of natural
gas, and the intense competition within the industry. Volatility in the physical
and financial gas markets has compounded the effects of these changes creating
greater service opportunities.
In the course of its business, the Company trades and develops a market in
natural gas in both the physical and financial markets, and purchases or sells
swaps and options in the OTC markets with major energy merchants. The Company
seeks to maintain a balanced portfolio of supply and demand contracts and
utilizes the New York Mercantile Exchange and OTC financial markets to hedge
against price and basis risk which may affect those obligations. To support
these activities, the Company employs centralized corporate risk management and
hedging strategies. In addition to these hedging activities, the Company also
engages in selective trading of these financial instruments. For additional
information regarding the use of financial instruments, see Note 5 of Item 8,
Financial Statements and Supplementary Data.
In 1996, a power marketing group was formed to capitalize on the
opportunities created from the deregulation of the electric industry. This group
will participate in wholesale power trading and offer products and services to
industrial and commercial end users of electricity. During 1996, the power
marketing group sold 3,555,000 MW hours of electricity, ranking it in the top 25
power marketers in the country. Additionally, during 1996, the Company began
marketing NGLs, crude and refined products.
Competition
The merchant services business' 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. The Company competes on the basis of
price, access to production, imbalance management, and experience in the market
place.
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CORPORATE AND OTHER
The Company's corporate and other segment includes its international
development activities, as well as certain other corporate activities. The
international development activities are conducted principally through EPEI and
the international activities of EPTPC (acquired in December 1996).
INTERNATIONAL AND OTHER ENERGY-RELATED BUSINESS
EPEI was incorporated in June 1995 for the purpose of investing in energy
projects with an emphasis on projects involving the development of
infrastructure to gather, transport and use natural gas in northern Mexico and
Latin America. With the combination of EPTPC's international activities, the
focus of international project pursuit has expanded to encompass Australia,
Asia, Europe and other Latin American countries. Set forth below are brief
descriptions of the projects that are either operational or are in various
stages of development.
Samalayuca Project. The Company has a 30 percent interest in an
international consortium that is constructing a 700 MW combined cycle gas fired
power generation facility located in Samalayuca, Chihuahua, Mexico. Completion
of the plant is scheduled for 1999 whereupon CFE will operate the plant under a
20-year lease. Upon completion of the lease term, ownership will be transferred
to CFE. The Company's investment in this plant is expected to be approximately
$40 million.
Aguaytia Project. The Company is a member of a consortium that is
developing an integrated gas and power project near Pucallpa, in central Peru,
called the Aguaytia Energy Project. The Company's economic interest in the
project is approximately 24 percent and its equity investment is estimated to be
approximately $26 million, which will be funded over the two-year construction
period. The project consists of constructing a single cycle 155 MW power plant
and transmission lines and developing the gas supply to power the plant. The
plant is expected to commence operations during 1998. The consortium will sell
electricity, propane and natural gas to meet the growing demand for energy in
Peru. The project was initially proposed to be funded with 60 percent equity;
however, the consortium is negotiating a loan from the Inter-American
Development Bank which will reduce the equity requirements to approximately 40
percent. The Company has obtained full political risk insurance for its equity
investment from OPIC.
Australia Project. In 1995, a subsidiary of EPTPC was selected to
construct, own and operate a 470-mile natural gas pipeline in Queensland,
Australia. Construction of the pipeline was completed in December 1996 at a
total cost of $170 million. Additionally, in June 1995, EPTPC acquired the
natural gas pipeline assets of PASA, which includes a 488-mile pipeline, for
$225 million. In December 1996, the Company received approximately $400 million
through debt financing and the subsequent sale of 70 percent of its ownership
interest in these projects.
Indonesia Project. The Company has a 50 percent ownership interest in a
producing gas field (having reserves of approximately 500 Bcf) and a 47.5
percent ownership in a 135 MW power generating plant under construction in South
Sulawesi, Indonesia. The $225 million project has been financed with
approximately $179 million in debt. The electricity from the power generating
plant will be sold to the national electric utility pursuant to a long-term
contract. The Company has obtained political risk insurance for its equity
investment.
Pakistan Project. In February 1997, the Company acquired a 42 percent
interest in a 151 MW power generating plant to be constructed in Kabirwala,
Pakistan. The Company is obligated to invest approximately $18 million in the
project. Project financing in the amount of approximately $128 million closed in
early 1997 and construction has begun. Long-term fuel supply agreements and
electricity sales agreements with Pakistani national corporations have been
entered into by the project company and are guaranteed by the Pakistani
Government. The Company is seeking to obtain political risk insurance for its
equity investment.
Hungary Project. In September 1996, a subsidiary of EPTPC was selected to
acquire a 50 percent controlling interest in an operating 70 MW power plant
located in Danaujvaros, Hungary. The electricity generated at this plant is
consumed by Dunaferr, the largest steel mill in Hungary. Excess power is sold
pursuant to long-term contracts to the Hungarian national electric utility.
Subject to satisfaction of certain
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conditions, the acquisition is scheduled to be finalized in the first quarter of
1997. The assets will be acquired for approximately $25 million, and no
financing will be involved. The Company is seeking political risk insurance from
OPIC for its equity investment. The acquisition agreement requires the Company
to study and, if deemed economically feasible, to expand the electric generating
plant. The feasibility study is underway.
Other Projects. The Company has 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 which have a combined capacity of 220 MWs.
OTHER
As a result of the Merger, the Company holds certain limited assets and is
responsible for certain liabilities, which the Company estimates to be
approximately $600 million, 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 business segments of the Company.
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 Note 3
of Item 8, Financial Statements and Supplementary Data.
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 ongoing and former operating sites. As of
December 31, 1996, the Company had a reserve of approximately $215 million for
the following environmental contingencies which the Company anticipates
incurring through 2027: (i) expected
remediation costs and associated onsite, offsite and groundwater technical
studies of approximately $162 million; and (ii) other costs of approximately $53
million. For a further discussion of specific environmental matters, see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, Item 3, Legal Proceedings, and Note 6 of Item 8, Financial
Statements and Supplementary Data.
In addition, the Company estimates that its subsidiaries will make capital
expenditures for environmental matters of approximately $5 million in 1997 and
that capital expenditures for environmental matters will range from
approximately $45 million to $85 million in the aggregate for the years 1998
through 2007. These expenditures primarily relate to compliance with air
regulations and control of water discharges.
EMPLOYEES
The Company had approximately 4,300 full-time employees on December 31,
1996. The Company has no collective bargaining arrangements. Subsequent to the
Merger, EPTPC implemented a program to streamline operations and reduce
operating costs. Since December 31, 1996, EPTPC has reduced its workforce by 340
employees.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPG as of February 28, 1997, were as follows:
OFFICER
NAME OFFICE SINCE AGE
---- ------ ------- ---
William A. Wise.............. Chairman of the Board and Chief Executive 1983 51
Officer of EPG
Richard Owen Baish........... President of EPG 1987 50
H. Brent Austin.............. Executive Vice President and Chief Financial 1992 42
Officer of EPG
Joel Richards III............ Executive Vice President of EPG 1990 50
Britton White, Jr............ Executive Vice President and General Counsel 1991 53
of EPG
John D. Hushon............... President, EPEI 1996 51
Greg G. Jenkins.............. President, EPEM 1996 39
Robert G. Phillips........... President, El Paso Energy Resources Company 1995 42
Mark A. Searles.............. President, EPFS 1995 40
John W. Somerhalder II....... President, TGP 1990 41
Mr. Wise has been Chairman of the Board of EPG since January 1994 and Chief
Executive Officer since January 1990. He was President of EPG from April 1989 to
April 1996. From March 1987 until April 1989, Mr. Wise was an Executive Vice
President of EPG. From January 1984 to February 1987, he was a Senior Vice
President of EPG. Mr. Wise is a member of the Board of Directors of Battle
Mountain Gold Company.
Mr. Baish has been President of EPG since April 1996. From September 1994
until April 1996, he was Executive Vice President of EPG 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.
Mr. Austin has been Executive Vice President of EPG since May 1995. He has
been Chief Financial Officer of EPG since April 1992. He was Senior Vice
President of EPG from April 1992 to April 1995. He was Vice President, Planning
and Treasurer of 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 EPG since December 1996.
From January 1991 until December 1996, he was Senior Vice President of EPG. 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 EPG since December 1996 and
General Counsel of EPG since March 1991. He was Senior Vice President and
General Counsel of EPG from March 1991 until December 1996. From March 1991 to
April 1992, he was also Corporate Secretary of EPG. For more than five years
prior to that time, Mr. White was a partner in the law firm of Holland & Hart.
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 Company.
Mr. Phillips has been President of El Paso Energy Resources Company since
December 1996. He was President of EPFS from April 1996 to December 1996 and was
a Senior Vice President of EPG from
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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. Searles has been President of EPFS since December 1996. He 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 time, he held various
managerial positions with Enron Corp.
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 EPG from August 1992 to April 1996. From January
1990 to July 1992, he was Vice President of EPG.
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. In
addition the Company's physical properties are adequate and suitable for the
conduct of its business in the future.
ITEM 3. 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, economic
duress, civil conspiracy, and violation of state antitrust laws arising from a
settlement agreement entered into by EPG, TransAmerican, and others in 1990 to
settle litigation then pending and other potential claims. The complaint, as
amended, seeks unspecified actual and exemplary damages. EPG 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 EPG), seeking
indemnification and other damages in unspecified amounts relating to litigation
consulting work allegedly performed for various entities, including EPG, in
cases involving TransAmerican. 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 materially adverse effect on the Company's financial position or
results of operations.
In July 1996, EPG and TGP were served with a complaint in the matter of
Jack J. Grynberg v. Alaska Pipeline Co., et al., filed in the U.S. District
Court for the District of Columbia. The plaintiff filed this action under the
False Claims Act against most interstate pipelines and others alleging that the
defendants mismeasured natural gas produced from federal and Indian lands, which
deprived the United States of royalties otherwise due it. Among other things,
the plaintiff seeks to recover, unspecified treble damages on behalf of the
United States. The plaintiff is also seeking to recover his finder's fee and
attorneys' fees. All defendants, most of whom are pursuing a combined defense,
have filed responsive motions. The plaintiff responded to those motions in
January 1997. Oral arguments are set for March 12, 1997. Both EPG and TGP
believe that there are valid jurisdictional and procedural defenses to the
plaintiff's complaint; however, even if the plaintiff is ultimately entitled to
pursue his claims, EPG and TGP believe that they have substantive defenses,
including that their measurement practices are consistent with industry practice
and all applicable standards, regulations, contracts, and tariffs and that EPG
and TGP should not be liable in any event. Based on information available at
this time, EPG and TGP do not believe that the ultimate resolution of this
matter will have a materially adverse effect on the Company's financial position
or results of operations.
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On August 1, 1995, the Texas Supreme Court affirmed a ruling of the Texas
Court of Appeals favorable to TGP involving a gas purchase contract and
indicated that it would remand the case to the trial court. On April 18, 1996,
however, the Texas Supreme Court withdrew its initial opinion and issued an
opinion reversing the Court of Appeals opinion. In June 1996, TGP filed a motion
for rehearing with the Texas Supreme Court which was denied in August 1996. In
December 1996, TGP entered into settlement agreements with each of the parties
to this gas purchase contract. As a result of these settlements, the gas
purchase contract is now terminated. TGP paid a total of $74 million to
terminate this contract. In addition, all related litigation was terminated.
During the course of this action, TGP either paid, or provided for the payment
of, amounts it believes were appropriate to cover the resolution of its contract
reformation litigation, including providing a bond in the amount of $206
million. On September 30, 1996, TGP paid approximately $193 million to the
producers and the producers agreed to release all but approximately $2 million
of the bonded amount. On November 1, 1996, a final order was issued which
assessed only $456,000 of the $2 million to TGP and TGP was released from the
remaining bond amount. TGP has filed with FERC to recover these payments from
its customers.
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 Pennsylvania and
New York environmental agencies to specify the remediation requirements at the
Pennsylvania and New York stations. Remediation activities in Pennsylvania are
essentially complete; in addition, pursuant to the Consent Order dated August 1,
1995, between TGP and the Pennsylvania Department of Environmental Protection,
TGP funded an environmentally beneficial project for $450,000 in April 1996 and
paid a $500,000 civil penalty in September 1996. 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 materially adverse effect on the Company's
financial position or results of operations.
In Commonwealth of Kentucky, Natural Resources and Environmental Protection
Cabinet v. Tennessee Gas Pipeline Company (Franklin County Circuit Court, Docket
No. 88-C1-1531, November 16, 1988), the Kentucky environmental agency alleged
that TGP discharged pollutants into the waters of the state without a permit and
disposed of PCBs without a permit. The agency sought an injunction against
future discharges, sought an order to remediate or remove PCBs, and sought a
civil penalty. TGP has entered into agreed orders with the agency to resolve
many of the issues raised in the original allegations, has received water
discharge permits for its Kentucky stations from the agency, and continues to
work to resolve the remaining issues. Management believes that the resolution of
this issue will not have a materially adverse effect on the Company's financial
position or results of operations.
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 materially adverse effect on the Company's financial position
or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EPG held a special meeting of stockholders on December 9, 1996. The
proposal presented for a stockholders' vote was the approval of the issuance by
EPG of up to 23,894,862 shares of common stock in connection with the
transactions contemplated by the Merger Agreement, as such may be amended,
supplemented or modified from time to time.
FOR AGAINST ABSTAIN
---------- -------- --------
Issuance of common stock................................... 23,605,943 181,417 155,077
There were no broker non-votes for the issuance of common stock.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
EPG's common stock is traded on the New York Stock Exchange. As of February
28, 1997, the approximate number of holders of record of common stock was
96,900. This does not include individual participants on whose behalf a clearing
agency, or its nominee, holds EPG's common stock.
The following table reflects the high and low sales prices for EPG'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.
HIGH LOW DIVIDENDS
------- ------- ---------
(PER SHARE)
1996
First Quarter.......................................... $38.125 $28.625 $0.3475
Second Quarter......................................... $39.000 $34.250 $0.3475
Third Quarter.......................................... $45.875 $37.750 $0.3475
Fourth Quarter......................................... $53.250 $44.000 $0.3475
1995
First Quarter.......................................... $32.500 $28.000 $0.3300
Second Quarter......................................... $29.875 $26.875 $0.3300
Third Quarter.......................................... $29.500 $24.750 $0.3300
Fourth Quarter......................................... $31.625 $26.500 $0.3300
In January 1997, the Board declared a quarterly dividend of $0.365 per
share on EPG's common stock, payable on April 1, 1997, to stockholders of record
on March 14, 1997. The declaration of future dividends will be dependent upon
business conditions, earnings, the cash requirements of EPG, and other relevant
factors.
In February 1997, the Company sold approximately 3 million shares of its
common stock. Proceeds of $152 million were received, net of issuance costs.
EPG has made available the Program, in which 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 EPG
may suspend the Program at any time. Inquiries regarding the Program should be
directed to The First National Bank of Boston.
EPG has made available the Plan, which provides all stockholders of record
a convenient and economical means of increasing their holdings in EPG'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. A brochure and related materials describing the Plan were sent to
stockholders of record in November 1994. The Plan currently does not have a
termination date, but EPG may suspend the Plan at any time. Inquiries regarding
the Plan should be directed to The First National Bank of Boston.
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ITEM 6. SELECTED FINANCIAL DATA
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1996(A) 1995(A) 1994 1993(B) 1992
-------- -------- ------- -------- -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
Operating Results Data:
Operating revenues................................. $3,010 $1,038 $ 870 $ 909 $ 803
Employee separation and asset impairment charge.... 99 -- -- -- --
Net income......................................... 38 85 90 92 76
Earnings per common share.......................... 1.06 2.47 2.45 2.46 2.12
Cash dividends declared per common share........... 1.39 1.32 1.21 1.10 0.75
Average common shares outstanding.................. 36 34 37 37 36
DECEMBER 31,
---------------------------------------------
1996(A) 1995(A) 1994 1993(B) 1992
------- ------- ------ ------- ------
(IN MILLIONS)
Financial Position Data:
Total assets....................................... $8,712 $2,535 $2,332 $2,270 $2,051
Long-term debt..................................... 2,215 772 779 796 637
Preferred stock of subsidiary...................... 296 -- -- -- --
Other minority interest............................ 39 -- -- -- --
Stockholders' equity............................... 1,638 712 710 708 669
- ---------------
(a) Reflects the acquisition in September 1995 of Eastex Energy Inc., in
December 1995 of Premier, in June 1996 of Cornerstone, and in December 1996
of EPTPC.
(b) Reflects the consolidation in May 1993 of MPC.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
GENERAL
In response to changes in the natural gas industry and the manner in which
the Company manages its businesses, the Company restructured its business
activities into three segments: (i) natural gas transmission, (ii) field and
merchant services, and (iii) corporate and other. To the extent practicable,
results of operations for 1995 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 the period. Due to the
inability to present 1994 results of operations by segment, the discussion for
the year ended December 31, 1995, compared to the year ended December 31, 1994,
is presented on a consolidated basis. Operating revenues by segment include
intersegment sales which are eliminated in consolidation.
YEAR ENDED DECEMBER 31, 1996, COMPARED TO YEAR ENDED DECEMBER 31, 1995
NATURAL GAS TRANSMISSION
YEAR ENDED
DECEMBER 31,
-------------
1996 1995
---- ----
(IN MILLIONS)
Reservation Revenue......................................... $503 $505
Transportation Revenue...................................... 36 13
Other Revenue............................................... 30 22
---- ----
Operating Revenue......................................... 569 540
Operating Expenses.......................................... 346 337
---- ----
Operating Income.......................................... $223 $203
==== ====
Operating revenue for the year ended December 31, 1996, was $29 million
higher than for the same period of 1995 primarily due to the acquisition of
EPTPC. This increase was partially offset by an accrual for regulatory issues
and a decrease in take or pay cost recoveries.
Operating expenses for the year ended December 31, 1996, were $9 million
higher than for the same period of 1995 primarily due to the acquisition of
EPTPC. This increase was partially offset by lower operation and maintenance
expenses resulting primarily from the Company's program to reduce operating
costs which was adopted in the first quarter of 1996. For a further discussion,
see Note 3 of Item 8, Financial Statements and Supplementary Data.
FIELD AND MERCHANT SERVICES
YEAR ENDED
DECEMBER 31,
-------------
1996 1995
---- ----
(IN MILLIONS)
Processing Margin........................................... $ 53 $ 13
Gathering and Treating Margin............................... 80 81
Marketing Margin............................................ 47 --
---- ----
Gross Margin.............................................. 180 94
Operating Expenses.......................................... 123 93
---- ----
Operating Income.......................................... $ 57 $ 1
==== ====
Gross margin and operating income increased $86 million and $56 million,
respectively. This was primarily a result of increased margins and earnings from
the gas processing and gas marketing businesses.
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The 1996 increase in marketing margin reflects the results of EPEM for the
entire year. The increase in processing margin was primarily caused by the
startup of operations at the Chaco Plant and the acquisition of Cornerstone. The
Chaco Plant began processing in May 1996 and was fully operational in September
1996. The Chaco Plant processed an average of 570 Mdth/d in the fourth quarter
and experienced recoveries of over 90 percent for ethane and 99 percent for
propane and heavier NGLs. The Cornerstone gas processing facilities were
acquired in June 1996 and have processed an average of 160 Mdth/d since then.
The gathering and processing operations benefited from an increase in both
natural gas and NGLs prices, particularly in the fourth quarter. Many of the
EPFS contracts are based on a percentage of products extracted or have fees
based on the price of natural gas. Product prices in the fourth quarter of 1996
were near historic highs and had a significant impact on earnings. The Company
does not anticipate that these price levels will be experienced in 1997.
The increase in operating expenses for 1996 was due primarily to the
acquisition of Cornerstone in June 1996 and EPEM in September 1995.
CORPORATE AND OTHER
YEAR ENDED
DECEMBER 31,
--------------
1996 1995
----- ----
(IN MILLIONS)
Operating Revenues.......................................... $ 1 $ 8
Operating Expenses.......................................... 111 --
----- ----
Operating Income (Loss)................................... $(110) $ 8
===== ====
Operating income for 1996 was $118 million lower than the prior year
primarily due to a $99 million employee separation and asset impairment charge
incurred in the first quarter of 1996. For a further discussion, see Note 3 of
Item 8, Financial Statements and Supplementary Data.
YEAR ENDED DECEMBER 31, 1995, COMPARED TO YEAR ENDED DECEMBER 31, 1994
CONSOLIDATED
Operating revenues for the year ended December 31, 1995, were $168 million
higher than for the same period of 1994. The increase was primarily due to the
acquisition of Eastex Energy Inc. and net reserves reversals. Higher gathering
and processing rates and return on take-or-pay receivables also contributed to
the increase. Partially offsetting the increase in operating revenues were lower
gas sales volumes, gas sales and transportation rates, transportation, gathering
and processing volumes, and reservation revenue.
Operating expenses for the year ended December 31, 1995, were $178 million
higher than for the same period of 1994. The increase was primarily due to the
acquisition of Eastex Energy Inc., increases in operation and maintenance
expense, and depreciation expense. The increase in operation and maintenance
expenses was due primarily to higher stock related benefits, higher consultant
fees, and higher severance accruals. Offsetting the increase in operating
expenses were lower gas purchase volumes, lower average cost of gas, a 1994
litigation special charge, and net reserve reversals.
OTHER INCOME AND EXPENSE
YEAR ENDED DECEMBER 31, 1996, COMPARED TO YEAR ENDED DECEMBER 31, 1995
Interest and debt expense for the year ended December 31, 1996, was $24
million higher than for the same period of 1995 due to the debt assumed in
connection with the acquisition of EPTPC and an increase in EPG's short-term and
long-term borrowings.
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Allowance for funds used during construction was $1 million lower for the
year ended December 31, 1996 than for the same period of 1995 due primarily to a
decrease in the average balance of construction work in progress.
YEAR ENDED DECEMBER 31, 1995, COMPARED TO YEAR ENDED DECEMBER 31, 1994
Interest and debt expense for the year ended December 31, 1995 was $7
million higher than for the same period of 1994 due to increased short-term
borrowings.
Allowance for funds used during construction was $1 million higher for the
year ended December 31, 1995 than for the same period of 1994 due primarily to
an increase in the average balance of construction work in progress.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $291 million for 1996,
compared with $203 million for the same period of 1995. The increase from the
previous year was primarily due to the collection of revenues subject to refund
(expected to be refunded in 1997), the net impact of acquisitions, the Amoco
Production Company litigation payment made in the first quarter of 1995, and
timing differences in other working capital accounts. This increase was
partially offset by gas contract settlement payments made by TGP in the fourth
quarter of 1996, lower take-or-pay cost recoveries, higher tax payments, and
higher severance payments.
Net cash provided by operating activities was $203 million for 1995,
compared with $253 million for the same period of 1994. The decrease from the
previous year was primarily due to lower net insurance reimbursements, the Amoco
Production Company litigation payment, the timing of insurance premium payments,
lower cash received on gas imbalance settlements, lower net tax refunds, higher
interest payments, and timing differences in other working capital
disbursements. The decrease was partially offset by 1994
take-or-pay refunds to customers, lower net tax payments, lower take-or-pay
payments, and timing differences in other working capital receipts.
CASH FROM INVESTING ACTIVITIES
Effective June 1996, the Company acquired Cornerstone. 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 have been capitalized. Effective December 1996, the
Company acquired EPTPC. The acquisition was accomplished by the issuance of
approximately 18.8 million shares of EPG common stock valued at approximately
$913 million, and the assumption of debt, preferred stock and other obligations
of approximately $3.2 billion. Acquisition costs of approximately $25 million
have been capitalized. For a further discussion of these acquisitions, see Note
2 of Item 8, Financial Statements and Supplementary Data.
In December 1996, the Company sold the exploration and production
investments of TGP and a 70 percent equity interest in its Australian pipeline.
For the year ended December 31, 1996, the net cash flow impact from the
monetization of these investments was approximately $179 million.
Total capital expenditures for 1996 were $119 million, a decrease of $47
million compared to 1995 expenditure levels of $166 million. The decrease
reflects the completion of the San Juan expansion project in 1995 and a lower
level of maintenance capital spending in 1996.
The Company's planned capital and investment expenditures for 1997 of $411
million are primarily for the maintenance of pipeline systems and other
facilities, expansion of international operations and unregulated operations,
and system enhancements.
Future funding for capital expenditures, acquisitions, and other investing
expenditures are expected to be provided by internally generated funds,
debt/equity issuances, and/or available credit facilities.
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CASH FROM FINANCING ACTIVITIES
In June 1996, EPG retired Cornerstone long-term debt in the amount of $16
million. In January 1997, EPG's 6.90% Notes for $100 million matured and were
retired.
On November 5, 1996, EPG's shelf registration statement on Form S-3 filed
with the SEC covering an aggregate of $800 million of unsecured debt securities,
preferred stock, and common stock was declared effective (the "Shelf
Registration Statement"). On November 13, 1996, EPG closed the sale of $200
million aggregate principal amount of its 6 3/4% Notes due 2003 and the sale of
$200 million aggregate principal amount of its 7 1/2% Debentures due 2026.
Proceeds from the debt issuance were used to repay short-term borrowings and for
general corporate purposes.
In connection with the Merger, the Company assumed approximately $2.2
billion in floating rate debt representing the outstanding amount under a $3
billion 364-day revolving credit facility taken out by Old Tenneco with a group
of banks as the vehicle to finance its debt realignment prior to the Merger. At
December 31, 1996, approximately $1.6 billion in borrowings and $400 million in
unused loan commitments remained outstanding under this facility. Additionally,
approximately $255 million of fixed rate public debt remained after the Old
Tenneco debt realignment and was assumed in the Merger.
Immediately following the Merger, the Company commenced a debt reduction
effort aimed at decreasing the debt assumed in the Merger and the related
interest cost and maintaining investment grade ratings on all senior debt. By
year end 1996, the Company completed several significant steps in its planned
monetization of certain assets, including the sale of the exploration and
production investments of TGP and the sale of an equity interest in and the
refinancing of its Australian natural gas pipeline. These steps resulted in debt
reductions in excess of $600 million.
For the years ended December 31, 1996, 1995, and 1994, EPG paid
approximately $53 million, $45 million, and $43 million in common and preferred
stock dividends. In January 1997, the Board declared a quarterly dividend of
$0.365 per share on EPG's common stock, payable on April 1, 1997, to
stockholders of record on March 14, 1997.
Since November 1994, the Company has been authorized by the Board to
repurchase up to 5.5 million shares of its common stock. Shares repurchased are
held in EPG's treasury and are expected to be used in conjunction with EPG stock
compensation plans and for other corporate purposes. Pursuant to the
authorization, the Company has repurchased 4.7 million shares as of December 31,
1995. There were no common stock repurchases in 1996.
Future funding for long-term debt retirements, dividends, and other
financing expenditures are expected to be provided by internally generated
funds, debt/equity issuances, and/or available credit facilities.
LIQUIDITY
The Company relies on cash generated from internal operations supplemented
by its available credit facilities as its primary sources of liquidity. In
November, 1996, EPG closed on a new $750 million five-year revolving credit
agreement and a new $250 million 364-day renewable revolving credit agreement,
both of which became effective upon the acquisition of EPTPC. The $750 million
and the $250 million facilities replaced EPG's existing $400 million five-year
revolving credit agreement and $100 million 364-day revolving credit agreement
which were established in May 1996.
The availability of borrowings under the Company's credit agreements is
subject to certain specified conditions, which management believes it 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).
In February 1997, EPG continued its debt reduction plan by issuing 3
million shares of common stock under the Shelf Registration Statement for
approximately $152 million, net of issuance costs. The proceeds of the stock
issuance were used to repay debt under the assumed Old Tenneco revolving credit
agreement. On February 28, 1997, TGP's shelf registration statement on Form S-3
filed with the SEC covering an aggregate
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of $1 billion of unsecured debt securities was declared effective. In March
1997, the Company plans to reduce the remaining outstanding debt under the Old
Tenneco revolving credit agreement by an additional $900 million with proceeds
from TGP's fixed rate debt offering.
EPG expects its debt to total capitalization ratio following the completion
of its debt reduction plan to be approximately 56 percent. Prior to the
acquisition of EPTPC, EPG's debt to total capitalization ratio was approximately
60 percent. All of the Company's senior debt has been given investment grade
ratings by Standard & Poors and Moody's.
COMMITMENTS AND CONTINGENCIES
Capital Commitments
At December 31, 1996, the Company had capital or investment commitments of
$85 million which are expected to be funded through cash provided by operations
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, the
Company has entered into unconditional purchase obligations for products and
services of $121 million ($94 million on a present value basis) at December 31,
1996. The Company's annual obligations under these agreements are $22 million
for the years 1997 and 1998, $21 million for the years 1999 and 2000, $11
million for the year 2001 and $24 million thereafter. In addition, in connection
with the Great Plains coal gasification project, TGP continues to have an
obligation to purchase 30 percent of the output of the plant's original design
capacity through July 2009. TGP has executed a settlement of this contract as a
part of its GSR negotiations as discussed below.
Guarantees
EPG has guaranteed various obligations of its subsidiaries, which
obligations are not expected to exceed $150 million. For further information,
see Note 6 of Item 8, Financial Statements and Supplementary Data.
Rates and Regulatory Matters
The Company is accruing a provision for various matters discussed below, as
well as other pending regulatory matters, and the balance of the provision at
December 31, 1996, was approximately $309 million, including interest.
TGP -- A phased proceeding was scheduled at FERC with respect to the
recovery of TGP's GSR costs. Testimony has been completed in connection with
Phase I of that proceeding relating to the eligibility of GSR cost recovery.
Phase II of the proceeding on the prudency of the costs to be recovered and on
certain contract specific eligibility issues has not yet been scheduled.
Although the Order No. 636 transition cost recovery mechanism provides for
complete recovery by pipelines of eligible and prudently incurred transition
costs, certain customers have challenged the prudence and eligibility of TGP's
GSR costs and TGP has engaged in settlement discussions with its customers
concerning the amount of such costs in response to FERC's public statements
encouraging such settlements.
On February 28, 1997, TGP filed with FERC a proposed settlement of all
issues related to the recovery by TGP of its GSR and other transition costs and
related proceedings (the "GSR Stipulation and Agreement"). Upon final approval
by FERC, this settlement will become effective retroactive to
January 1, 1997. The settlement is based upon the preliminary GSR understanding,
which called for sharing of transition costs, that EPG reached with TGP's
customers in October 1996 in anticipation of the Merger. The GSR Stipulation and
Agreement allows for TGP to recover up to $770 million in GSR and other
transition costs, including interest, of which approximately $531 million has
previously been recovered, subject to refund,
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pending resolution of the transition costs issues. Assuming FERC approves the
GSR Stipulation and Agreement, TGP will be entitled to recover additional
transition costs, up to the remaining $239 million, through a two-year demand
transportation surcharge and an interruptible transportation surcharge. The
terms of the GSR Stipulation and Agreement provide for a rate case moratorium
through November 2000 (subject to certain limited exceptions) and provide a rate
cap, indexed to inflation, through October 31, 2005, for certain of TGP's
customers. The purchase accounting adjustments reflected in the Company's
consolidated financial statements assume approval of the settlement with respect
to TGP's GSR and other transition costs in accordance with the terms of the GSR
Stipulation and Agreement.
Although parties to TGP's transition cost proceedings do not have to
declare their support or opposition to the GSR Stipulation and Agreement until
mid-March, management believes that all of TGP's customers will support or not
oppose the GSR Stipulation and Agreement.
In order to resolve litigation concerning purchases made by TGP of
synthetic gas produced from the Great Plains coal gasification plant, TGP, along
with three other pipelines, executed four separate settlement agreements with
Dakota and the Department of Energy and initiated four separate proceedings at
FERC seeking approval to implement the settlement agreements. Among other
things, the settlement required TGP to pay Dakota over a limited period a
premium over the spot price for Dakota's production and resolves the litigation
with Dakota. As of December 31, 1996, TGP had paid $87 million of this
obligation and has accrued its estimated remaining obligation through December
2003 of $55 million. FERC previously ruled that the costs related to the Great
Plains project are eligible for recovery through GSR and other special recovery
mechanisms and that the costs are eligible for recovery for the duration of the
term of the original gas purchase agreements. In October 1994, FERC consolidated
the four proceedings and set them for hearing before an ALJ. The hearing, which
concluded in July 1995, was limited to the issue of whether the settlement
agreements are prudent. The ALJ concluded, in his initial decision issued in
December 1995, that the settlement was not prudent. In December 1996, FERC
unanimously reversed that decision and upheld the settlements among the
pipelines, Department of Energy and Dakota. No parties filed for rehearing of
the FERC decision. TGP notified Dakota in December 1996 that it accepted the
settlement.
In December 1994, TGP filed for a general rate increase (the "1995 Rate
Case"). In January 1995, FERC accepted the filing, suspended its effectiveness
for the maximum period of five months pursuant to normal regulatory process, and
set the matter for hearing. On July 1, 1995, TGP began collecting rates, subject
to refund, reflecting an $87 million increase in TGP's annual revenue
requirement. A Stipulation was filed with an ALJ in this proceeding in April
1996. This Stipulation resolves the rates that are the subject of the 1995 Rate
Case, including a structural rate design change that results in a larger
proportion of TGP's transportation revenues being dependent upon throughput.
Under the Stipulation, TGP is required to refund, upon final approval of the
Stipulation, the difference between the revenues collected under the July 1,
1995 motion rates and the revenues that would have been collected pursuant to
rates underlying the Stipulation. In October 1996, FERC approved the Stipulation
with certain modifications and clarifications which are not material. In January
1997, FERC issued an order denying requests for rehearing of the October 1996
order. Refunds will be made in March 1997. The Company believes that these
refunds will not have a material impact on the Company's financial position or
results of operations. One party to the rate proceeding, a competitor of TGP,
filed with the Court of Appeals a Petition for Review of the FERC orders
approving the Stipulation.
EPG -- Effective January 1, 1996, SoCal exercised an option in its contract
to relinquish 300 MMcf/d of capacity. SoCal's demand quantity will remain at the
1,150 MMcf/d level for a primary term ending August 31, 2006. In addition, PG&E
has a contract for 1,140 MMcf/d of firm capacity rights on EPG's system with a
primary term ending December 31, 1997. In June 1995, PG&E notified EPG that it
intends to terminate the contract as of December 31, 1997. EPG's reservation
revenues from PG&E during 1996 were approximately $126 million. Known reductions
in existing firm capacity commitments total approximately 1,614 MMcf/d.
EPG is seeking to offset the effects of these reductions in existing firm
capacity commitments by actively seeking new markets, pursuing attractive
opportunities to increase traditional market share, and controlling costs. The
new markets EPG has targeted include various natural gas users in California
which are now served
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indirectly through SoCal and PG&E, as well as new markets off the east end of
its system. EPG's efforts to obtain new markets in California at full tariff
rates is adversely impacted by the current excess interstate pipeline capacity
to California, which is estimated to continue into the next decade.
In June 1995, EPG made a filing with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In July 1995, FERC
accepted and suspended EPG's filing to be effective January 1, 1996, subject to
refund and certain other conditions. FERC also set EPG's rates for hearing.
In March 1996, EPG filed a comprehensive offer of settlement which, if
approved by FERC, would resolve issues related to the above mentioned rate case
and issues surrounding certain contract reductions and expirations that occur
from January 1, 1996 through December 31, 1997. The settlement provides for,
among other things: (i) a long term rate stability plan which establishes base
rates, for a 10-year period from January 1, 1996, through December 31, 2005,
subject to annual escalation after 1997; (ii) payments, over 8 years, or less,
to EPG by its customers totaling $255 million prior to interest, representing
approximately 35 percent of the revenues associated with the contract reductions
and expirations; (iii) the sharing between EPG (65 percent) and its customers
(35 percent) of revenues in excess of a threshold, as defined in the settlement
and (iv) a mechanism to reflect in the base rate increases or decreases
resulting from laws or regulations which impact costs at a level in excess of
$10 million a year. The settlement provides that any party desiring not to be
bound by the settlement may have its rates determined pursuant to procedures
established by FERC. FERC staff, the regulatory agencies of California, Arizona,
and Nevada, the state of New Mexico, and customers representing 95 percent of
the firm throughput on EPG's mainline transmission system support EPG's
settlement.
In March 1996, Edison, a firm shipper on EPG's system, filed its own offer
of settlement. One party supported Edison's proposal, while several other
parties independently contested elements of EPG's settlement. In January 1997,
the Chief ALJ certified EPG's settlement to FERC and severed the contesting
parties. Edison requested reconsideration of the certification. Edison and the
other contesting parties also provided notice of their intention to preserve
their rights to contest EPG's settlement, including through litigation. A
decision by FERC on both the certification and the merits of EPG's settlement is
pending.
Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. Certain of EPG's
customers sought review in the Court of Appeals of FERC's determination in the
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 1996, FERC issued an
order to the effect that categories of costs which had been determined to be
eligible for recovery might in fact be ineligible for recovery and established a
technical conference which was held in May 1996. Management believes that the
costs at issue were eligible for recovery from EPG's customers pursuant to the
equitable sharing mechanism. If FERC should rule that the costs at issue were
not eligible for recovery, refunds by EPG of up to $42 million plus interest may
be required. A FERC decision is expected in 1997.
Management believes the ultimate resolution of the aforementioned rate and
regulatory matters, which are in various stages of finalization, will not have a
materially adverse effect on the Company's financial position and results of
operations. For a further discussion of regulatory matters, see Note 6 of Item
8, Financial Statements and Supplementary Data.
Future Projects
In April 1996, EPG filed with FERC for authorization to expand the Havasu
Crossover Line. The proposed expansion involves the construction of additional
compression on the Havasu Crossover Line at an estimated cost of approximately
$20 million. Expansion of the Havasu Line will permit an additional 180 MMcf/d
to move on the crossover line from the San Juan Basin in northern New Mexico to
points of delivery off EPG's southern system. EPG has executed transportation
service agreements to fully subscribe this expanded capacity on the crossover
line. In November 1996, FERC authorized EPG to construct and operate the
proposed facilities. In December 1996, EPG requested a rehearing or
clarification of FERC's November 1996 order relating to the accounting
classification of minor items of property, which request is currently pending.
The expansion is expected to be in service in the second quarter of 1997.
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In March 1993, EPG filed an application with FERC to expand its system in
order to provide natural gas service to the proposed Samalayuca II Power Plant
in northern Mexico. EPG's proposed facilities, together with a proposed border
crossing facility south of Clint, Texas would connect EPG's facilities with
facilities in Mexico. In December 1993, PG&E, SoCal and the CPUC jointly filed a
motion with FERC seeking clarification or rehearing of the November 1993 order
approving the proposed border crossing facility, which motion is currently
pending.
In February 1997, EPG filed with FERC an amendment to its March 1993
Samalayuca expansion application to reflect, among other things, EPG's
participation in the consortium discussed below. The amendment submitted
agreements evidencing binding, long-term firm commitments for 100 percent of the
revised capacity (208 MMcf/d) of the expansion project at a capital cost of
approximately $15 million. It also provided for the elimination of the mainline
facilities and for incremental rather than rolled-in rate treatment for the
costs of the project. EPG is required under the bid specifications for the
project to have the project in service by late 1997, and believes that it will
receive FERC and other authorizations necessary to meet the specified in-service
date.
In November 1996, EPG became a member of a consortium which successfully
bid on a proposed pipeline system connecting EPG's existing system in west Texas
to Pemex's pipeline system in northern Mexico. The proposed pipeline system,
which consists of approximately 22 miles on the U.S. side of the border, a
downsized version of the Samalayuca II Power Plant project, and an additional 23
miles in Mexico, will have a capacity of 208 MMcf/d. Volumes transported through
the proposed pipeline will provide natural gas to the Samalayuca Power Plants
and markets in northern Mexico. The entire project is estimated to cost
approximately $33 million.
In 1995 EPG purchased a one-third interest in TGTC for approximately $4
million from PSC. EPG paid approximately $2 million in cash with the balance of
approximately $2 million being due upon commencement of operation of the second
phase of the pipeline project. In December 1996, TGTC placed in service its
Phase I facilities, which consists of approximately 25 miles of pipeline with a
capacity of 120 MMcf/d, extending from the outlet of the Coyote Gulch Treating
Plant in southern Colorado to the Blanco Hub area. KN Energy and EPG each own a
one-half interest in Phase I. The cost of Phase I was approximately $12 million
and was funded by obtaining project financing. Phase II consists of the
remainder of the project extending up to northwest Colorado and is estimated to
cost $200 million. In October 1996, FERC granted an extension of time through
September 30, 1998 to complete construction and place in service Phase II.
Construction on Phase II has not yet begun.
In September 1996, a subsidiary of EPTPC was selected to acquire a 50
percent controlling interest in an operating 70 MW power plant located in
Danaujvaros, Hungary. The electricity generated at this plant is consumed by
Dunaferr, the largest steel mill in Hungary. Excess power is sold pursuant to
long-term contracts to the Hungarian national electric utility. Subject to
satisfaction of certain conditions, the acquisition is scheduled to be finalized
in the first quarter of 1997. The assets will be acquired for approximately $25
million, and no financing will be involved. The Company is seeking political
risk insurance from OPIC for its equity investment. The acquisition agreement
requires the Company to study and, if deemed economically feasible, to expand
the electric generating plant. The feasibility study is underway.
In February 1997, the Company acquired a 42 percent interest in a 151 MW
power generating plant to be constructed in Kabirwala, Pakistan. The Company is
obligated to invest approximately $18 million in the project. Project financing
in the amount of approximately $128 million closed in early 1997 and
construction has begun. Long-term fuel supply agreements and electricity sales
agreements with Pakistani national corporations have been entered into by the
project company and are guaranteed by the Pakistani Government. The Company is
seeking political risk insurance for its equity investment.
Legal Proceedings
See Item 3, Legal Proceedings which is incorporated herein by reference.
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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 ongoing and
former operating sites. As of December 31, 1996, the Company had a reserve of
approximately $215 million for the following environmental contingencies which
the Company anticipates incurring through 2027: (i) expected remediation costs
and associated onsite, offsite and groundwater technical studies of
approximately $162 million; and (ii) other costs of approximately $53 million.
For a further discussion of specific environmental matters, see Item 3, Legal
Proceedings and Note 6 of Item 8, Financial Statements and Supplementary Data.
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 31 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, 1996, the
Company has estimated its share of the remediation costs at these sites to be
between $24 million and $62 million and has provided reserves that it believes
are adequate for such costs. Because the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, the Company's estimate of its share of remediation costs
could change. Moreover, liability under the federal Superfund statute is joint
and several, meaning that the Company could be required to pay in excess of its
pro rata share of remediation costs. The Company's understanding of the
financial strength of other PRPs has been considered, where appropriate, in its
determination of its estimated liability as described herein. The Company
presently believes that the costs associated with the current status of such
entities as PRPs at the Superfund sites referenced above will not have a
materially adverse effect on the financial position of the Company.
The Company estimates that its subsidiaries will make capital expenditures
for environmental matters of approximately $5 million in 1997 and that capital
expenditures for environmental matters will range from approximately $45 million
to $85 million in the aggregate for the years 1998 through 2007. These
expenditures primarily relate to compliance with air regulations and control of
water discharges.
OTHER
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
Note 3 of Item 8, Financial Statements and Supplementary Data.
Financial Instruments
See Note 5 of Item 8, Financial Statements and Supplementary Data.
SFAS No. 71, Accounting for the Effects of Certain Types of Regulation
The Company's businesses that are subject to the regulations and accounting
requirements of FERC continue to meet the accounting requirements of SFAS No.
71. The Consolidated Balance Sheets of the Company contain assets and
liabilities related to operations which have been recorded pursuant to SFAS No.
71. If these accounting principles should no longer be applied, an amount would
be charged to earnings as an extraordinary item. At December 31, 1996, this
amount was estimated to be approximately $100 million,
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net of income taxes. Changes in the regulatory and economic environment may, at
some point in the future, create circumstances in which the application of
regulatory accounting principles is no longer appropriate. Any potential charge
would be non-cash and would have no direct effect on the ability to seek
recovery of the underlying deferred costs in future rate proceedings or on the
ability to collect the rates set thereby. For a further discussion of SFAS No.
71 issues, see Note 1 of Item 8, Financial Statements and Supplementary Data.
Effective January 1, 1996, EPG transferred certain gathering and processing
facilities to EPFS. FERC had determined that, upon the transfer to EPFS, the
facilities would be exempt from FERC jurisdiction. Accordingly, the provisions
of SFAS No. 71 do not apply to EPFS's transactions and balances effective
January 1, 1996. The discontinuance of the application of SFAS No. 71 to EPFS
did not have a material impact on the Company's financial position or results of
operations.
FERC Compliance Audits
TGP and EPG, as with all interstate pipelines, are subject to a FERC audit
review of their books and records. Both currently have open audits covering the
years 1991 through 1994 for TGP and 1991 through 1995 for EPG. FERC audit staff
is expected to issue both audit reports in early 1997.
Change in Corporate Structure
The Board has approved, subject to certain conditions, the adoption of a
holding company structure whereby the Company would become direct and indirect
subsidiaries of a Holding Company. Holders of shares of common stock of EPG
would become, by virtue of the Reorganization, holders on a share-for-share
basis, of shares of common stock of Holding Company with the result that Holding
Company would replace EPG as the publicly-held corporation, and all stockholders
of EPG immediately prior to the Reorganization would own the same number of
shares of Holding Company common stock immediately after the Reorganization as
the EPG common stock held immediately before the Reorganization. The change to a
holding company structure would be tax free for federal income tax purposes to
stockholders of EPG. The change to a holding company structure may be effected
without a vote of stockholders under applicable Delaware law.
The Reorganization is subject to the satisfaction of certain conditions,
including among other things: (i) approval of Holding Company common stock and
preferred stock purchase rights for trading on the New York Stock Exchange; (ii)
a favorable no-action ruling from the SEC concerning the absence of requirement
for registration under the Securities Act of 1933 of the Holding Company common
stock to be issued in the Reorganization and certain other securities law
issues; and (iii) a favorable private letter ruling from the IRS. The Company
believes, but there can be no assurance, that the conditions to forming the
holding company structure will be satisfied. It is possible that certain of the
terms of the structure described above may be modified or dispensed with and new
terms or structure may be adopted, in response to conditions imposed by the IRS
and/or SEC in their rulings or otherwise adopted by the Board in on-going
consideration of the holding company structure.
RECENT PRONOUNCEMENTS
The Company adopted SFAS No. 125, SFAS No. 127, and Statement of Position
No. 96-1 effective January 1, 1997. The Company believes that these
pronouncements will not have a material impact on the Company's financial
position or results of operations. In addition, SFAS No. 128 and SFAS No. 129
were issued in early March 1997 and the Company is currently evaluating the
effect of these pronouncements. For a further discussion of these
pronouncements, see Note 1 of Item 8, Financial Statements and Supplementary
Data.
The Company also adopted SFAS No. 123 effective January 1, 1997 and has
elected to continue to account for stock-based compensation plans under
Accounting Principles Board Opinion No. 25. For a further discussion, see Note 9
of Item 8, Financial Statements and Supplementary Data.
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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, 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.
Taking into account the foregoing, the following are identified as
important factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by, or on behalf of, the
Company:
HIGHLY COMPETITIVE INDUSTRY
The ability to maintain or increase current transmission, gathering,
processing, and sales volumes, or to remarket unsubscribed capacity, can be
subject to the impact of future weather conditions, including those that favor
hydroelectric generation or other alternative energy sources; price competition;
drilling activity and supply availability; and service competition, especially
due to excess pipeline capacity into California. Future profitability also may
be affected by the Company's ability to compete with the services offered by
other energy enterprises which may be larger, offer more services, and possess
greater resources. The ability of TGP to negotiate new contracts and to
renegotiate existing contracts (70 percent of which are expiring over the next
five years, principally in the year 2000) could be adversely affected by the
proposed construction of additional pipeline capacity in the Northeast U.S.,
reduced demand due to higher gas prices, the availability of alternative energy
sources, and other factors that are not within its control. For a further
discussion see Item 1, Business -- Natural Gas Transmission -- Markets and
Competition.
IMPACT OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES
The value of natural gas transmission services is based on an all-in cost,
including the cost of the natural gas. Therefore, the Company's ability to
compete with other transporters is impacted by natural gas prices in the supply
basins connected to its pipeline systems compared to prices in other gas
producing regions, especially Canada. Additionally, revenues generated by the
Company from its 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. Fluctuations in energy prices are caused by a number of
factors, including regional, domestic and international 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.
USE OF DERIVATIVE FINANCIAL INSTRUMENTS
In the ordinary course and conduct of its business, some of the Company's
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 OTC options and
price and basis swaps with other gas merchants and financial institutions. The
Company could incur financial losses in future periods as a result of volatility
in the market values of the underlying commodities.
ACQUISITIONS AND INVESTMENTS
Opportunities for growth through acquisitions and investments in joint
ventures, and future operating results and the success of acquisitions and joint
ventures within and outside the U.S. may be subject to
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the effects of, and changes in, U.S. and foreign trade and monetary
policies, laws and regulations, political and economic developments,
inflation rates, and the effects of taxes and operating conditions.
Activities in areas outside the U.S. also 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, war,
insurrection and other political risks, and the effects of currency
fluctuations and exchange controls. Such legal and regulatory delays and
other unforeseeable obstacles may be beyond the Company's control or
ability to manage.
PENDING REGULATORY PROCEEDINGS
EPG and TGP have entered into comprehensive settlements with their
respective customers that, if approved by FERC, would resolve many of the
contract expiration, transportation rate, gas supply realignment and other
transition issues in which they are involved. Whether FERC will approve
such settlements in the form filed or whether these regulatory proceedings
will be otherwise resolved in a manner satisfactory to the Company cannot
be predicted with certainty, and the business of the Company could be
adversely affected thereby. For a description of certain regulatory
proceedings involving the Company, see Item 1, Business -- Natural Gas
Transmission -- Regulatory Environment.
POTENTIAL ENVIRONMENTAL LIABILITIES
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. For additional information concerning the
Company's environmental matters, see Note 6 of Item 8, Financial Statements
and Supplementary Data.
OPERATING HAZARDS AND UNINSURED RISKS
While the Company maintains 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 the Company.
POTENTIAL LIABILITIES RELATED TO THE MERGER
The amount of the actual and contingent liabilities of Old Tenneco,
which remained the liabilities of the Company after the Merger, could vary
materially from the amount estimated by the Company, which was based upon
assumptions which may 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 the Company, under certain legal
theories which may or may not be applicable to the situation, to assume
responsibility for such obligations, which could have a material adverse
effect on the Company.
UNCERTAINTY SURROUNDING INTEGRATION OF OPERATIONS
The Company is engaged in a comprehensive review of the business and
operations of EPTPC and its subsidiaries and has begun to integrate such
operations to increase operating and administrative efficiency through
consolidation and reengineering of facilities, workforce reductions and
coordination of purchasing, sales and marketing activities. Management
anticipates that the complementary interstate and intrastate pipeline
operations and energy marketing activities of the combined company should
provide increased operating flexibility and access to additional customers
and markets, although the amount and timing of the realization of such
benefits will depend upon the Company's ability to integrate successfully
the businesses and operations of the companies, and the time period over
which such integration is effected.
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POTENTIAL FEDERAL INCOME TAX LIABILITIES
In connection with the Merger and Distributions, the IRS issued a private
letter ruling to Old Tenneco, in which the IRS ruled that for U.S. federal
income tax purposes (i) 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, (ii) the Merger would constitute a tax-free
reorganization, and (iii) that 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.
REFINANCING AND INTEREST RATE EXPOSURE RISKS
The business and operating results of the Company 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 the Company, or security ratings.
POTENTIAL FOR CHANGES IN ACCOUNTING STANDARDS
Authoritative generally accepted accounting principle or policy changes
from such standard setting bodies as the Financial Accounting Standards Board,
FERC, and the SEC may affect the Company's results of operations or financial
position.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
--------------------------
1996 1995 1994
------ ------ ------
Operating revenues
Reservation........................... $ 500 $ 504 $ 506
Transportation........................ 34 23 41
Natural gas and liquids............... 2,309 403 226
Gathering and processing.............. 85 73 67
Other................................. 82 35 30
------ ------ ------
3,010 1,038 870
------ ------ ------
Operating expenses
Natural gas and liquids............... 2,259 402 234
Operation and maintenance............. 338 312 295
Depreciation, depletion, and
amortization....................... 101 72 65
Employee separation and asset
impairment charge.................. 99 -- --
Litigation special charge............. -- -- 15
Taxes, other than income taxes........ 43 40 39
------ ------ ------
2,840 826 648
------ ------ ------
Operating income........................ 170 212 222
------ ------ ------
Other (income) and expense
Interest and debt expense............. 110 86 79
Allowance for funds used during
construction....................... (1) (2) (1)
Other, net............................ (4) (5) (4)
------ ------ ------
105 79 74
------ ------ ------
Income before income taxes and minority
interest.............................. 65 133 148
Income taxes............................ 25 48 58
------ ------ ------
Income before minority interest......... 40 85 90
Minority interest....................... 2 -- --
------ ------ ------
Net income.............................. $ 38 $ 85 $ 90
====== ====== ======
Earnings per common share............... $ 1.06 $ 2.47 $ 2.45
====== ====== ======
Average common shares outstanding....... 36 34 37
====== ====== ======
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
ASSETS
DECEMBER 31, DECEMBER 31,
1996 1995
------------ ------------
Current assets
Cash and temporary investments........ $ 200 $ 39
Accounts and notes receivable, net.... 1,445 215
Inventories........................... 87 37
Deferred income tax benefit........... 141 23
Other................................. 92 55
------ ------
Total current assets.......... 1,965 369
------ ------
Property, plant, and equipment, net..... 5,938 1,977
Other................................... 809 189
------ ------
6,747 2,166
------ ------
Total assets.................. $8,712 $2,535
====== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade.............................. $ 588 $ 201
Other.............................. 501 75
Short-term borrowings (including
current maturities of long-term
debt).............................. 841 285
Accrual for regulatory issues......... 309 --
Other................................. 473 82
------ ------
Total current liabilities..... 2,712 643
------ ------
Long-term debt, less current
maturities............................ 2,215 772
Deferred income taxes, less current
portion............................... 1,092 314
Postretirement benefits, less current
portion............................... 309 --
Other................................... 411 94
------ ------
4,027 1,180
------ ------
Minority interest
Preferred stock of subsidiary......... 296 --
------ ------
Other minority interest............... 39 --
------ ------
Commitments and contingencies (See Note
6.)
Stockholders' equity
Common stock, par value $3 per share;
authorized 100,000,000 shares;
issued 56,726,734 and 37,351,225
shares............................. 170 112
Additional paid-in capital............ 1,355 455
Retained earnings..................... 227 240
Less: Treasury stock of 1,451,922 and
3,127,077 shares................... 45 95
Deferred compensation........... 69 --
------ ------
Total stockholders' equity.... 1,638 712
------ ------
Total liabilities and
stockholders' equity....... $8,712 $2,535
====== ======
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
-------------------------
1996 1995 1994
------- ----- -----
Cash flows from operating activities
Net income............................ $ 38 $ 85 $ 90
Adjustments to reconcile net income to
net cash provided by operating
activities
Depreciation, depletion, and
amortization..................... 101 72 65
Deferred income taxes.............. (5) 30 49
Net take-or-pay recoveries......... 10 36 32
Net employee separation and asset
impairment charge................ 76 -- --
Net costs recovered (recoverable)
through insurance................ -- (1) 23
Other working capital changes
Accounts and notes receivable.... (168) (11) 1
Inventories...................... (5) 1 (3)
Other current assets............. (26) (10) 5
Accrual for regulatory issues.... 142 -- (35)
Accounts payable................. 65 (10) 33
Accrued taxes, other than income
taxes......................... -- 2 4
Other current liabilities........ 49 2 (4)
Other................................. 14 7 (7)
------- ----- -----
Net cash provided by operating
activities.................. 291 203 253
------- ----- -----
Cash flows from investing activities
Capital expenditures.................. (119) (166) (173)
Long-term note receivable issued by
subsidiary......................... (26) -- --
Investment in equity securities....... (24) -- --
Proceeds from sale of assets.......... 10 3 7
Net cash flow impact of
acquisitions....................... (35) (23) --
Net cash flow impact from monetization
of investments..................... 179 -- --
Other................................. 10 (30) (23)
------- ----- -----
Net cash used in investing
activities.................. (5) (216) (189)
------- ----- -----
Cash flows from financing activities
Net commercial paper borrowings
(repayments)....................... (203) 96 105
Revolving credit borrowings........... 400 75 --
Revolving credit repayments........... (1,022) -- --
Long-term debt retirements............ (24) (16) (16)
Long-term debt issuance............... 396 -- --
Repayment of volumetric take-or-pay
receivable......................... -- (37) (44)
Acquisition of treasury stock......... -- (56) (44)
Dividends paid........................ (53) (45) (43)
Contribution from minority interest... 40 -- --
Proceeds from project financing....... 310 -- --
Other................................. 31 7 6
------- ----- -----
Net cash provided by (used in)
financing activities........ (125) 24 (36)
------- ----- -----
Increase in cash and temporary
investments........................... 161 11 28
Cash and temporary investments
Beginning of period................... 39 28 --
------- ----- -----
End of period......................... $ 200 $ 39 $ 28
======= ===== =====
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
COMMON STOCK ADDITIONAL TREASURY STOCK TOTAL
--------------- PAID-IN RETAINED --------------- DEFERRED STOCKHOLDERS'
SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT COMPENSATION EQUITY
------ ------ ---------- -------- ------ ------ ------------ -------------
January 1, 1994......... 37 $112 $ 456 $157 (1) $(18) $ -- $ 707
Net income............ 90 90
Issuance of common
stock, net of
related costs....... --
Common stock dividend
($1.21 per share)... (44) (44)
Acquisition of
treasury stock...... (1) (44) (44)
Issuance of treasury
stock............... 2 2
Other................. (1) (1)
-- ---- ------ ---- -- ---- ---- ------
December 31, 1994....... 37 112 455 203 (2) (60) 710
Net income............ 85 85
Common stock dividend
($1.32 per share)... (45) (45)
Acquisition of
treasury stock...... (2) (57) (57)
Issuance of treasury
stock for
acquisition of
Eastex Energy
Inc................. (3) 1 21 18
Issuance of treasury
stock............... 1 1
-- ---- ------ ---- -- ---- ---- ------
December 31, 1995....... 37 112 455 240 (3) (95) 712
Net income............ 38 38
Common stock dividend
($1.39 per share)... (50) (50)
Issuance of common
stock for
acquisition of
EPTPC............... 19 56 857 913
Issuance of common
stock............... 1 2 19 21
Issuance of treasury
stock............... 23 (1) 2 50 72
Issuance and
amortization of
restricted stock,
net................. (69) (69)
Other................. 1 1
-- ---- ------ ---- -- ---- ---- ------
December 31, 1996....... 57 $170 $1,355 $227 (1) $(45) $(69) $1,638
== ==== ====== ==== == ==== ==== ======
The accompanying Notes are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
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 subsidiaries of the Company after the elimination of all
significant intercompany accounts and transactions. Investments in 20 percent to
50 percent owned companies where the Company has the ability to exert
significant influence over operating and financial policies are accounted for by
the equity method. The financial statements for previous periods include certain
reclassifications that were made to conform to the current presentation. Such
reclassifications have no impact on reported net income or stockholders' equity.
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 could differ from those
estimates.
Accounting for Regulated Operations
The Company's businesses that are subject to the regulations and accounting
requirements of FERC continue to meet the accounting requirements of SFAS No.
71, Accounting for the Effects of Certain Types of Regulation, which accounting
methods may differ from those used by non-regulated entities. Transactions that
have been recorded differently as a result of regulatory accounting requirements
include Order No. 636 transition costs to be recovered under a volumetric
surcharge; certain benefits costs and taxes expected to be included in future
rates; and costs to refinance debt. When the accounting method followed is
prescribed by or allowed by the regulatory authority for rate-making purposes,
such accounting conforms to the generally accepted accounting principle of
matching costs against the revenues to which they apply.
Changes in the regulatory and economic environment may, at some point in
the future, create circumstances in which the application of regulatory
accounting principles will no longer be appropriate. If these accounting
principles should no longer be applied, an amount would be charged to earnings
as an extraordinary item. At December 31, 1996, this amount was estimated to be
approximately $100 million, net of income taxes. Any potential charge would be
non-cash and would have no direct effect on the regulated companies' ability to
seek recovery of the underlying deferred costs in their future rate proceedings
or on their ability to collect the rates set thereby.
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
The Company has established a provision for losses on accounts and notes
receivable, as well as gas imbalances due from shippers and operators, which may
become uncollectible. Collectibility is reviewed regularly, and the allowance
for bad debts is adjusted as necessary primarily under the specific
identification method. The balances of this provision at December 31, 1996 and
1995, were $60 million and $10 million, respectively.
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Gas Imbalances
The Company values gas imbalances due to or due from shippers and operators
at the appropriate index price. The gas imbalances are settled in cash or made
up in-kind.
Inventories
Inventories, consisting of materials and supplies and 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 $189 million and $74 million at December 31,
1996, and 1995, respectively. An allowance for both debt and equity funds used
during construction is included in the cost of the Company's property, plant,
and equipment.
Depreciation of the Company's regulated transmission facilities are
provided primarily using the composite method over the estimated useful lives of
the depreciable facilities. The rates for depreciation range from approximately
2 percent to 5 percent.
Depreciation of the Company's nonregulated 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.
Additional acquisition cost assigned to utility plant represents the excess
of allocated purchase costs over historical costs that resulted from the 1983
acquisition of EPG's former parent, The El Paso Company, by Burlington Northern
Inc., the former parent of Burlington Resources Inc. and the December 1996
acquisition of EPTPC. These costs are being amortized on a straight-line basis
over the estimated useful life of the properties.
Costs of regulated properties that are not operating units, as defined by
FERC, which are retired, sold, or abandoned are charged or credited, net of
salvage, to accumulated depreciation and amortization. Gains or losses on sales
of operating units are credited or charged to income.
The Company evaluates impairment of its property, plant, and equipment in
accordance with SFAS No. 121.
Intangible Assets
Goodwill and other intangibles are being amortized using the straight-line
method over periods ranging from 5 years to 40 years. The net balances of
intangible assets at December 31, 1996 and 1995, were $116 million and $48
million, respectively.
The Company evaluates impairment of goodwill in accordance with SFAS No.
121.
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 remedial
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. 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 revision in
future periods based on actual costs or new circumstances. These liabilities are
included in the balance sheets at their undiscounted amounts. Recoveries
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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 a regulatory asset.
Financial Instruments With Off-Balance-Sheet Risk
The Company is a party to financial instruments with off-balance-sheet risk
in the normal course of business to reduce its exposure to fluctuations in
interest rates and the price of certain energy and power commodities. These
financial instruments include interest rate swaps, price swap agreements,
futures, and options.
The Company engages in price risk management activities for both trading
and non-trading purposes. Activities for trading purposes, generally consisting
of services provided to the energy sector, are accounted for using the
mark-to-market method. Under such method, changes in the market value of
outstanding financial instruments are recognized as gains or losses in the
period of change. The market prices used to value these transactions reflect
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.
Activities for non-trading purposes consist of transactions entered into by
the Company to hedge the impact of market fluctuations on assets, liabilities,
production or other contractual commitments. Changes in the market value of
these transactions are deferred until the gains or losses on the hedged item are
recognized. See Note 5 for a further discussion of the Company's price risk
management activities.
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 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.
As a result of the Merger, EPTPC entered into a new tax sharing agreement
with Newport News Shipbuilding Inc., New Tenneco and EPG. This new tax sharing
agreement provides, among other things, for the allocation among the parties of
assets and tax liabilities arising prior to, as a result of, and subsequent to
the Distributions. Generally, EPTPC will be liable for taxes imposed on EPTPC.
In the case of federal income taxes imposed with respect to periods prior to the
consummation of the Distributions on the combined activities of EPTPC 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 new tax sharing agreement, EPTPC will pay New Tenneco
for the tax benefits realized from the deduction of taxable losses generated by
a debt realignment in accordance with the Merger and such amount has been
accrued in the accompanying consolidated balance sheet.
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, 1996, and 1995, were 680,000 shares that were
reserved to secure benefits under certain of the Company's benefit plans.
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Earnings Per Share
Earnings per share of common stock is based on the weighted average number
of shares of common stock outstanding during the year. The weighted average
shares of common stock outstanding for 1996, 1995, and 1994 were 36 million, 34
million, and 37 million, respectively.
Stock-Based Compensation
The Company applies 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 a price lower than market on the
grant date.
Recent Pronouncements
In June 1996, the Financial Accounting Standards Board issued SFAS No. 125,
Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities, which establishes new accounting and reporting standards for
transfers and servicing of financial assets and extinguishment of liabilities.
The statement is effective for transactions occurring after December 31, 1996,
but in December 1996, the Financial Accounting Standards Board issued SFAS No.
127, Deferral of the Effective Date of Certain Provisions of FASB Statement No.
125, which defers the implementation of certain provisions of SFAS No. 125 until
January 1998. The new pronouncements are not expected to have a material impact
on the financial position or results of operations of the Company.
In October 1996, the American Institute of Certified Public Accountants
issued Statement of Position No. 96-1, Environmental Remediation Liabilities,
which establishes new accounting and reporting standards for the recognition and
disclosure of environmental remediation liabilities. The provisions of the
statement are effective for fiscal years beginning after December 15, 1996. This
pronouncement is not expected to have a material impact on the financial
position or results of operations of the Company.
In early March 1997, SFAS No. 128, Earnings Per Share, and SFAS No. 129,
Disclosures of Information about Capital Structure, were issued. The Company is
currently evaluating the impact of these pronouncements.
2. ACQUISITIONS
On December 12, 1996, the Company completed the acquisition of EPTPC in a
transaction accounted for as a purchase. Accordingly, an allocation of the
purchase price has been assigned to the assets and liabilities acquired based
upon the estimated fair value of those assets and liabilities as of the
acquisition date. A substantial portion of the excess of the total purchase
price over historical carrying amounts of the net assets acquired has been
allocated to property, plant and equipment of EPTPC's interstate pipeline
systems. Such allocation is based on the Company's internal evaluation of such
assets. An independent appraisal of the fair value of the property acquired is
in process and is expected to be completed by mid-1997. Should the independent
appraisal not support such allocation, the excess of total purchase price over
fair value of net assets acquired will be reflected as goodwill. Management does
not expect that the final results of the independent appraisal and the ultimate
disposition of the purchase price allocation will materially impact future
operating results.
In the Merger, which was effected in accordance with the Merger Agreement,
Old Tenneco changed its name to EPTPC. Prior to the Merger, Old Tenneco and its
subsidiaries effected 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 those operations related to the
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transmission and marketing of natural gas. Results of operations of EPTPC are
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 the IRS ruled that for U.S. federal income tax purposes (i) 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; (ii)
the Merger would constitute a tax-free reorganization; and (iii) 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
under a corporate level, federal income tax would be payable by the consolidated
group of which Old Tenneco was the common parent.
The consideration paid by EPG 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 (1) approximately $.2 billion
of public debt of Old Tenneco outstanding at the effective time of the
Merger, (2) $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, the banks and other financial
institutions party thereto and The Chase Manhattan Bank, as agent), and
(3) $300 million of Old Tenneco preferred stock);
- the issuance of 18.8 million shares of common stock of EPG valued at
approximately $913 million, based on a closing price per share of common
stock on the New York Stock Exchange of $48.625 on December 9, 1996, to
Old Tenneco's then existing common and preferred stockholders; and
- the retention of approximately $600 million of estimated assumed
liabilities related to certain discontinued businesses of Old Tenneco.
The number of shares of EPG'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 .093 of a share of EPG's common stock for each share of Tenneco common
stock, (ii) a holder of Old Tenneco's $7.40 Cumulative Preferred Stock received
2.365 shares of EPG'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 2.365 shares of EPG's common stock for each such share of $4.50
Cumulative Preferred Stock.
At the time of the Merger, EPG indirectly owned 100 percent of the common
equity and approximately 75 percent of the combined equity value of EPTPC. The
remaining 25 percent of the combined equity of EPTPC is comprised of $296
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:
Fair value of assets acquired............................... $ 6,080
Cash acquired............................................... (75)
Liabilities assumed......................................... (5,155)
Issuance of common stock.................................... (913)
-------
Net cash consideration received................... $ (63)
=======
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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 years ended December 31, 1996 and 1995, assuming the acquisition had
occurred January 1, 1995:
1996 1995
------ ------
(IN MILLIONS,
EXCEPT
PER SHARE AMOUNTS)
Operating revenue........................................... $5,281 $2,912
Net income.................................................. $ 183 $ 167
Earnings per common share................................... $ 3.22 $ 2.98
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,
in a $105 million transaction. 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 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 have
been capitalized. The cost of the acquisition has been 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
are included in the Company's Consolidated Statements of Income for the period
June 1996 through December 1996.
Effective September 1995, the Company acquired Eastex Energy Inc., and in
December 1995, the Company acquired all of the issued and outstanding capital
stock of Premier. Effective July 1996, the name Eastex Energy Inc. was changed
to, and its subsidiaries were merged into, EPEM.
3. 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.
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4. LONG-TERM DEBT AND OTHER FINANCING
Long-term debt outstanding at December 31, 1996 and 1995, consisted of the
following:
1996 1995
------ ------
(IN MILLIONS)
Long-term debt
EPG
Debentures due 2012 through 2026, average effective
interest rates of 8.15% in 1996 and 8.63% in 1995..... $ 475 $ 275
Notes due 1997 through 2003, average effective interest
rates of 7.39% in 1996 and 7.74% in 1995.............. 562 362
EPTPC
Credit Facility due 1999 average effective interest
rate 6.78%
in 1996.............................................. 1,600 --
Debentures due 1998 through 2025, average effective
interest rate 8.9% in 1996............................ 55 --
Notes due 1998 through 2005, average effective interest
rate 9.6% in 1996..................................... 90 --
TGP
Debentures due 2011, average effective interest rate
15.1% in 1996......................................... 73 --
EPECC
Senior notes due 1996 through 2001, average effective
interest rate 9.9% in 1996............................ 30 --
Subordinated notes due 1998 through 2001, average
effective interest rate 9.9% in 1996.................. 7 --
MPC
Project financing loan, due March 2007, average
effective interest rates of 8.9% in 1996 and 8.8% in
1995.................................................. 135 142
Other Subsidiaries
Notes due 1996 through 2014, average effective interest
rate 7.92% in 1996.................................... 12 --
------ ------
3,039 779
Less current maturities................................... 824 7
------ ------
Total long-term debt.............................. $2,215 $ 772
====== ======
The following are aggregate maturities of long-term debt for the next 5
years and in total thereafter:
(IN MILLIONS)
-------------
1997........................................................ $ 824
1998........................................................ 56
1999........................................................ 564
2000........................................................ 20
2001........................................................ 54
Thereafter.................................................. 1,521
------
Total long-term debt, including current
maturities....................................... $3,039
======
Other Financing Arrangements
In November 1996, EPG closed on a new $750 million five-year revolving
credit agreement and a new $250 million 364-day renewable revolving credit
agreement, both of which became effective upon the acquisition of EPTPC. The
$750 million and $250 million revolving credit agreements replaced EPG's
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$400 million five-year revolving credit agreement and $100 million 364-day
revolving credit agreement which were established in May 1996. Borrowings on
EPG's revolving credit facilities as of December 31, 1996 and 1995, were
approximately $17 million and $75 million, respectively. As of December 31,
1996, the Company had no commercial paper outstanding compared to $203 million
at December 31, 1995. The Company's weighted average interest rate on short-term
borrowings for 1996 was 5.7 percent compared to 6.0 percent in 1995.
In November 1996, Old Tenneco established with a group of banks a 364-day
$3 billion revolving credit and competitive advance facility (previously defined
as the "Credit Facility") with an initial termination date in November 1997.
Outstanding borrowings under the Credit Facility which are unpaid at the
termination date become due by the second anniversary following that date. At
December 31, 1996, approximately $1.6 billion in borrowings and $400 million in
unused loan commitments remained outstanding under the Credit Facility. In March
1997, TGP will issue $900 million of long-term debt, with maturities ranging
from 10 to 40 years. The proceeds of this borrowing will be used to pay down the
Credit Facility in the first quarter 1997. This refinanced amount is the basis
for classifying $900 million of that facility as long-term debt.
In June 1996, EPG retired Cornerstone long-term debt in the amount of $16
million. In January 1997, EPG's 6.90% Notes for $100 million matured and were
retired.
On November 5, 1996, EPG's Shelf Registration Statement was declared
effective. On November 13, 1996, EPG closed the sale of $200 million aggregate
principal amount of its 6 3/4% Notes due 2003 and the sale of $200 million
aggregate principal amount of its 7 1/2% Debentures due 2026. The 6 3/4% Notes
and the 7 1/2% Debentures were covered by the Shelf Registration Statement.
Proceeds from the debt issuance were used to repay short-term debt and for
general corporate purposes.
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 $150 million in the aggregate,
excluding acquisition debt, project financing, and certain refinancings. As of
December 31, 1996, EPG's consolidated debt and guarantees to capitalization
ratio was 60 percent and debt obligations of EPG subsidiaries in excess of
permitted debt did not exceed $150 million on a consolidated basis.
5. FINANCIAL INSTRUMENTS
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, 1996, and 1995, the carrying amounts of certain
financial instruments employed 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 the long-term debt has been estimated based on
quoted market prices for the same or similar issues. The fair value of the
project financing is representative of the carrying amount due to the short-term
nature of the interest rates. The fair value of all 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.
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The following table reflects the carrying amount and estimated fair value
of the Company's financial instruments at December 31:
1996 1995
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Balance sheet financial instruments:
Long-term debt, excluding project
financing................................. $2,904 $2,936 $637 $710
Project financing............................ 135 135 142 142
Other financial instruments:
Trading
Futures contracts......................... 25 25 -- (6)
Option contracts.......................... -- -- -- 7
Swap contracts............................ 14 14 -- 1
Non-Trading
Interest rate swap agreements............. -- 10 -- 15
Futures contracts......................... -- 2 -- 1
Option contracts.......................... -- -- -- (12)
Swap contracts............................ -- -- -- 23
Trading Activities
The Company, through its merchant services business, offers price risk
management services to the energy sector. These services primarily relate to
commodities associated with the energy sector (natural gas, crude natural gas
liquids and electricity). The Company provides these services through a variety
of financial instruments 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 uses the mark-to-market method of accounting for transactions
which subject the Company to price risk in order to accurately portray its price
risk management and trading activities. Under this method, forwards, swaps,
options and other financial instruments with third parties are reflected at
estimated market value, with resulting unrealized gains and losses recorded in
other current assets in the Consolidated Balance Sheets. Terms regarding cash
settlements of these contracts vary with respect to the actual timing of cash
receipts and payments. The amounts shown in the Consolidated Balance Sheets
related to price risk management activities also include assets or liabilities
which arise as a result of the actual timing of settlements related to these
contracts. Current period changes in the assets and liabilities from price risk
management activities (resulting primarily from newly originated transactions,
restructurings and the impact of price movements) are recognized as net gains or
losses in operating income in the Consolidated Statements of Income. Net gains
recognized during 1996 were approximately $28 million.
The fair value of the financial instruments as of December 31, 1996, and
the average fair value of those instruments held during the year are set forth
below (amounts in millions):
AVERAGE FAIR
VALUE FOR THE
ASSETS LIABILITIES YEAR ENDED 12/31/96(A)
------ ----------- ----------------------
Futures contracts............................ 74 49 4
Option contracts............................. 10 10 (11)
Swap contracts............................... 86 72 7
- ---------------
(a) Computed using the net asset balance at each month end.
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Notional Amounts and Terms
The notional amounts and terms of these financial instruments at December
31, 1996 are set forth below (volumes in trillions of British thermal units
equivalent):
FIXED PRICE FIXED PRICE MAXIMUM
PAYER RECEIVER TERMS IN YEARS
----------- ----------- --------------
Energy Commodities:
Natural gas........................... 914 873 5
NGLs, crude and refined products...... 58 77 1
Electricity........................... 1 1 1
Notional amounts reflect the volume of transactions but do not represent
the amounts exchanged by the parties to the financial instruments. 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 in the markets at any
time based on the Company's risk management needs and liquidity of the commodity
market.
The volumetric weighted average maturity of the Company's entire portfolio
of price risk management activities as of December 31, 1996, was approximately
one year.
Market and Credit Risks
To provide solutions to energy problems nationwide, the Company serves a
diverse customer group that includes independent power producers, industrials,
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 group operating
separately 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 losses.
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 and the use of
standardized agreements which allow for the netting of positive and negative
exposures associated with a single counterparty. Counterparties to the forwards,
futures and other contracts discussed above are generally investment grade
financial institutions. Counterparties with below investment grade ratings are
required to provide collateral to offset non-performance risk. Notional amounts
are used to express the volume of various derivative financial instruments, the
amounts potentially subject to credit risk, in the event of nonperformance by
the third parties, are substantially smaller.
Non-Trading Activities
EPEM also enters into forwards, swaps and other contracts to hedge the
impact of market fluctuations on assets, liabilities, production or other
contractual commitments. Changes in the market value of these transactions are
deferred until the gain or loss is recognized on the hedged item.
MPC has entered into interest rate swap agreements which effectively
converted $114.3 million of floating-rate debt to fixed-rate debt (see Note 4,
Long-Term Debt and Other Financing). MPC makes payments to counterparties at
fixed rates and in return receives payments at floating rates. The two swap
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agreements were entered into in March 1992 and have remaining terms of
approximately 3 years and 5 years, respectively.
In February 1995, EPNC entered into a 7.75-year lease agreement (see Note
6, Commitments and Contingencies). To moderate the exposure to interest rate
changes, EPNC entered into an interest rate swap arrangement effective July 31,
1995, whereby approximately 50 percent of the current lease financing was
converted from a London Interbank Offered Rate (LIBOR) based floating rate to a
5.9 percent fixed rate.
The effective dates and notional amounts subject to the swap arrangement
are as follows:
(IN MILLIONS)
-------------
July 31, 1995 -- October 31, 1995........................... $13
October 31, 1995 -- April 30, 1996.......................... $25
April 30, 1996 -- December 31, 1997......................... $35
The primary risks associated with interest rate swaps are the exposure to
movements in interest rates and the ability of the counterparties to meet the
terms of the contracts. Based on review and assessment of counterparty risk,
neither MPC nor EPNC anticipates non-performance by the other parties.
6. COMMITMENTS AND CONTINGENCIES
Rates and Regulatory Matters
The Company is accruing a provision for various matters discussed below, as
well as other pending regulatory matters, and the balance of the provision at
December 31, 1996, was approximately $309 million, including interest.
TGP -- In 1992, FERC issued Order No. 636 which restructured the natural
gas industry by requiring mandatory "unbundling" of pipeline sales and
transportation services. Numerous parties appealed to the Court of Appeals,
challenging the legality of Order No. 636 generally, as well as the legality of
specific provisions of Order No. 636. In July 1996, the Court of Appeals issued
its decision upholding, in large part, Order No. 636. and remanded to FERC
several issues for further explanation, including further explanation of FERC's
decision to allow pipelines to recover 100 percent of their GSR costs and FERC's
requirement that pipelines allocate 10 percent of GSR costs to interruptible
transportation customers. In February 1997, FERC reaffirmed its decision to
allow pipelines to recover 100 percent of GSR costs. In addition, FERC modified
the requirement that pipelines allocate 10 percent of GSR costs to interruptible
customers to permit pipelines to propose an allocation of any percentage of such
costs to their interruptible customers.
TGP implemented revisions to its tariff, which restructured its
transportation, storage and sales services to convert TGP from primarily a
merchant to primarily a transporter of gas as required by Order No. 636. As a
result of this restructuring, TGP's gas sales declined while certain obligations
to producers under long-term gas supply contracts continued, causing TGP to
incur significant restructuring transition costs. Pursuant to the provisions of
Order No. 636 allowing for the recovery of transition costs related to the
restructuring, TGP has made filings to recover the following transition costs:
(i) costs related to its Bastian Bay facilities; (ii) the "stranded" costs of
TGP's continuing contractual obligations to pay for capacity on other pipeline
systems ("TBO costs") (collectively referred to as "Transition Cost"); (iii) GSR
costs resulting from TGP's remaining gas purchase obligations; and (iv) the
remaining unrecovered balance of purchased gas ("PGA") costs. The filings
implementing TGP's recovery mechanisms for these transition costs were accepted
by FERC effective September 1, 1993, subject to refund and pending FERC review
and approval for eligibility and prudence.
TGP's filings to recover costs related to its Bastian Bay facilities have
been rejected by FERC based on the continued use of the gas production from the
field; however, FERC recognized the ability of TGP to file for the recovery of
any losses upon disposition of these assets. TGP has filed for appellate review
of FERC actions and is confident that the Bastian Bay costs will ultimately be
recovered; FERC has not contested the ultimate recoverability of these costs.
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47
TGP is recovering through a surcharge, subject to refund, TBO costs
formerly incurred to perform its sales function. FERC issued an order requiring
TGP to refund certain of these costs and refunds were made in May 1996. TGP is
appealing this decision and believes such appeal will likely be successful.
A phased proceeding was scheduled at FERC with respect to the recovery of
TGP's GSR costs. Testimony has been completed in connection with Phase I of that
proceeding relating to the eligibility of GSR cost recovery. Phase II of the
proceeding on the prudency of the costs to be recovered and on certain contract
specific eligibility issues has not yet been scheduled. Although the Order No.
636 transition cost recovery mechanism provides for complete recovery by
pipelines of eligible and prudently incurred transition costs, certain customers
have challenged the prudence and eligibility of TGP's GSR costs and TGP has
engaged in settlement discussions with its customers concerning the amount of
such costs in response to FERC's public statements encouraging such settlements.
On February 28, 1997, TGP filed with FERC a proposed settlement of all
issues related to the recovery by TGP of its GSR and other transition costs and
related proceedings, as discussed above. Upon final approval by FERC, this
settlement will become effective retroactive to January 1, 1997. The settlement
is based upon the preliminary GSR understanding, which called for sharing of
transition costs, that EPG reached with TGP's customers in October 1996 in
anticipation of the Merger. The GSR Stipulation and Agreement allows for TGP to
recover up to $770 million in GSR and other transition costs, including
interest, of which approximately $531 million has previously been recovered,
subject to refund, pending resolution of the transition costs issues. Assuming
FERC approves the GSR Stipulation and Agreement, TGP will be entitled to recover
additional transition costs, up to the remaining $239 million, through a
two-year demand transportation surcharge and an interruptible transportation
surcharge. The terms of the GSR Stipulation and Agreement provide for a rate
case moratorium through November 2000 (subject to certain limited exceptions)
and provide a rate cap, indexed to inflation, through October 31, 2005, for
certain of TGP's customers. The purchase accounting adjustments reflected in the
Company's consolidated financial statements assume approval of the settlement
with respect to TGP's GSR and other transition costs in accordance with the
terms of the GSR Stipulation and Agreement.
Although parties to TGP's Transition Cost proceedings do not have to
declare their support or opposition to the GSR Stipulation and Agreement until
mid-March, management believes that all of TGP's customers will support or not
oppose the GSR Stipulation and Agreement.
Following negotiations with its customers, TGP filed in July 1994 with FERC
a Stipulation and Agreement (the "PGA Stipulation"), which provides for the
recovery of PGA costs of approximately $100 million and the recovery of costs
associated with the transfer of storage gas inventory to new storage customers
in TGP's restructuring proceeding. The PGA Stipulation eliminates all challenges
to the PGA costs, but establishes a cap on the charges that may be imposed upon
former sales customers. In April 1995, FERC orders approving the PGA Stipulation
and resolving all outstanding issues became final. TGP implemented the terms of
the PGA Stipulation and made refunds in May 1995. The refunds had no material
effect on the Company's reported net income. The orders approving the PGA
Stipulation have been appealed to the Court of Appeals by certain customers. TGP
believes the FERC orders approving the PGA Stipulation will be upheld on appeal.
In order to resolve litigation concerning purchases made by TGP of
synthetic gas produced from the Great Plains coal gasification plant, TGP, along
with three other pipelines, executed four separate settlement agreements with
Dakota and the Department of Energy and initiated four separate proceedings at
FERC seeking approval to implement the settlement agreements. Among other
things, the settlement required TGP to pay Dakota over a limited period a
premium over the spot price for Dakota's production and resolves the litigation
with Dakota. As of December 31, 1996, TGP had paid $87 million of this
obligation and has accrued its estimated remaining obligation through December
2003 of $55 million. FERC previously ruled that the costs related to the Great
Plains project are eligible for recovery through GSR and other special recovery
mechanisms and that the costs are eligible for recovery for the duration of the
term of the original gas purchase agreements. In October 1994, FERC consolidated
the four proceedings and set them for hearing before an ALJ. The hearing, which
concluded in July 1995, was limited to the issue of whether the settlement
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48
agreements are prudent. The ALJ concluded, in his initial decision issued in
December 1995, that the settlement was not prudent. In December 1996, FERC
unanimously reversed that decision and upheld the settlements among the
pipelines, Department of Energy and Dakota. No parties filed for rehearing of
the FERC decision. TGP notified Dakota in December 1996, that it accepted the
settlement.
In December 1994, TGP filed the 1995 Rate Case. In January 1995, FERC
accepted the filing, suspended its effectiveness for the maximum period of five
months pursuant to normal regulatory process, and set the matter for hearing. On
July 1, 1995, TGP began collecting rates, subject to refund, reflecting an $87
million increase in TGP's annual revenue requirement. A Stipulation was filed
with an ALJ in this proceeding in April 1996. This Stipulation resolves the
rates that are the subject of the 1995 Rate Case, including a structural rate
design change that results in a larger proportion of TGP's transportation
revenues being dependent upon throughput. Under the Stipulation, TGP is required
to refund, upon final approval of the Stipulation, the difference between the
revenues collected under the July 1, 1995 motion rates and the revenues that
would have been collected pursuant to the rates underlying the Stipulation. In
October 1996, FERC approved the Stipulation with certain modifications and
clarifications which are not material. In January 1997, FERC issued an order
denying request for rehearing of the October 1996 order. Refunds will be made in
March 1997. The Company believes that these refunds will not have a material
impact on the Company's financial position or results of operations. One party
to the rate proceeding, a competitor of TGP, filed with the Court of Appeals a
Petition for Review of the FERC orders approving the Stipulation.
EPG -- In June 1995, EPG made a filing with FERC for approval of new system
rates for mainline transportation to be effective January 1, 1996. In July 1995,
FERC accepted and suspended EPG's filing to be effective January 1, 1996,
subject to refund and certain other conditions. FERC also set EPG's rates for
hearing.
In March 1996, EPG filed a comprehensive offer of settlement which, if
approved by FERC, would resolve issues related to the above mentioned rate case
and issues surrounding certain contract reductions and expirations that occur
from January 1, 1996 through December 31, 1997. The settlement provides for,
among other things: (i) a long term rate stability plan which establishes base
rates, for a 10-year period from January 1, 1996, through December 31, 2005,
subject to annual escalation after 1997; (ii) payments, over 8 years, or less,
to EPG by its customers totaling $255 million prior to interest, representing
approximately 35 percent of the revenues associated with the contract reductions
and expirations; (iii) the sharing between EPG (65 percent) and its customers
(35 percent) of revenues in excess of a threshold, as defined in the settlement;
and (iv) a mechanism to reflect in the base rate increases or decreases
resulting from laws or regulations which impact costs at a level in excess of
$10 million a year. The settlement provides that any party desiring not to be
bound by the settlement may have its rates determined pursuant to procedures
established by FERC. FERC staff, the regulatory agencies of California, Arizona,
and Nevada, the state of New Mexico, and customers representing 95 percent of
the firm throughput on EPG's mainline transmission system support EPG's
settlement.
In March 1996, Edison, a firm shipper on EPG's system, filed its own offer
of settlement. One party supported Edison's proposal, while several other
parties independently contested elements of EPG's settlement. In January 1997,
the Chief ALJ certified EPG's settlement to FERC and severed the contesting
parties. Edison requested reconsideration of the certification. Edison and other
contesting parties also provided notice of their intention to preserve their
rights to contest EPG's settlement, including through litigation. A decision by
FERC on both the certification and the merits of EGP's settlement is pending.
Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. Certain of EPG's
customers sought review in the Court of Appeals of FERC's determination in the
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 1996, FERC issued an
order to the effect that categories of costs which had been determined to be
eligible for recovery might in fact be ineligible for recovery and established a
technical conference which was held in May 1996. Management believes that the
costs at issue were eligible for recovery from EPG's customers pursuant
44
49
to the equitable sharing mechanism. If FERC should rule that the costs at issue
were not eligible for recovery, refunds by EPG of up to $42 million plus
interest may be required. A FERC decision is expected in 1997.
Management believes the ultimate resolution of the aforementioned rate and
regulatory matters, which are in various stages of finalization, will not have a
materially adverse effect on the Company's financial position or results of
operations.
Environmental Matters
As of December 31, 1996, the Company had a reserve of approximately $215
million to cover environmental assessments and remediation activities as
discussed below.
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, in order to assure that its
efforts meet regulatory requirements.
Due to the current uncertainty regarding the further activity necessary for
TGP to address the presence of PCBs, substances on the EPA List of Hazardous
Substances and other substances of concern on its sites, including the
requirements for additional site characterization, the actual amount of such
substances at the sites, and the final, site-specific cleanup decisions to be
made with respect to cleanup levels and remediation technologies, the Company
cannot at this time accurately project what additional costs, if any, may arise
from future characterization and remediation activities. While there are still
many uncertainties relating to the ultimate costs which may be incurred, based
upon the Company's evaluation and experience to date, the Company believes that
the recorded estimate for the reserve is adequate.
Following negotiations with its customers, TGP in May 1995 filed with FERC
a separate Stipulation and Agreement (the "Environmental Stipulation") that
establishes a mechanism for recovering a substantial portion of the
environmental costs. 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. This shipper filed a Petition for
Review in April 1996 in the Court of Appeals; TGP believes the FERC order
approving the Environmental Stipulation will be upheld on appeal. The
Environmental Stipulation, which was effective July 1, 1995, had no material
effect on the Company's financial position or results of operations. As of
December 31, 1996, the balance of the regulatory asset was $49 million.
TGP has completed settlements with and has received payments from the
majority of its liability insurance policy carriers for remediation costs and
related claims. TGP believes that additional recoveries from the remaining
carriers in the pending litigation against such carriers are reasonably
possible. In addition, TGP has settled its pending litigation against and
received payment from the manufacturer of the PCB-containing lubricant
previously used in the starting air systems in a portion of TGP's pipeline. TGP
has reduced the amount it is seeking to recover under the Environmental
Stipulation by the amount it has received in these proceedings.
In January 1994, the State of Tennessee notified EPG that it was a liable
party under state environmental laws for cleanup costs associated with a site in
Elizabethton, Tennessee. The Tennessee Department of Environment and
Conservation named EPG and two other parties as PRPs. The State is also seeking
to notify other PRPs that have been identified. The City of Elizabethton is
unilaterally cleaning up the site in cooperation with and under the authority of
the Tennessee Department of Environment and Conservation. As of December 31,
1996, the City has not sought contribution or reimbursement from EPG.
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 31 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
45
50
payment of the Company's allocable share of remediation costs. Because the
clean-up costs are estimates and are subject to revision as more information
becomes available about the extent of remediation required, the Company's
estimate of its share of remediation costs could change. Moreover, liability
under the federal Superfund statute is joint and several, meaning that the
Company could be required to pay in excess of its pro rata share of remediation
costs. The Company's understanding of the financial strength of other PRPs has
been considered, where appropriate, in its determination of its estimated
liability as described herein. The Company presently believes that the costs
associated with the current status of such entities as PRPs at the Superfund
sites referenced above will not have a materially adverse effect on the
financial position of the Company.
In addition, the Company has identified a number of formerly owned or
leased sites, and certain other sites associated with its discontinued
operations, where environmental remediation may be acquired. The Company
presently believes that the costs to remediate these sites will not have a
materially adverse effect on its financial position or results of operations.
The Company has identified other sites where environmental remediation may
be required should there be a change in ownership, operations or applicable
regulations. These possibilities cannot be predicted or quantified at this time
and, accordingly, no provision has been recorded. However, provisions have been
made for all instances where it has been determined that the incurrence of any
material remedial expense is reasonably probable. The Company believes that the
provisions recorded for environmental exposures are adequate based on current
estimates.
Legal Proceedings
See Item 3, Legal Proceedings, which is incorporated herein by reference.
Operating Leases
The Company leases certain property, facilities and equipment under various
operating leases. In addition, in 1995, EPNC entered into an unconditional
"triple net" lease for the Chaco Plant, which is a cryogenic liquids extraction
plant completed in 1996. 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
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. EPG unconditionally guaranteed all obligations of EPNC
under the lease.
Minimum annual rental commitments at December 31, 1996, were as follows:
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
1997..................................................... $ 19
1998..................................................... 18
1999..................................................... 18
2000..................................................... 18
2001..................................................... 17
Thereafter............................................... 75
------
Total............................................. $165
======
Aggregate minimum payments have not been reduced by minimum sublease
rentals of approximately $13 million due in the future under noncancelable
subleases.
Rental expense for operating leases for 1996, 1995, and 1994 was $14
million, $9 million, and $9 million, respectively.
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Guarantees
In addition to its guaranty of EPNC's obligations under the Chaco Plant
lease, EPG has also unconditionally guaranteed all obligations of EPED Sam
Holdings Company, an indirect subsidiary of EPEI, which obligations are not
expected to exceed $51 million in connection with its share of the financing for
the Samalayuca II Power Plant project. In addition, EPG has unconditionally
guaranteed the obligations of certain subsidiaries, which are not expected to
exceed $18 million, in connection with the TransColorado Pipeline Phase I
project and the Coyote Gulch natural gas treating plant.
Capital Commitments
At December 31, 1996, the Company had capital or investment commitments of
$85 million which are expected to be funded through cash provided by operations
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, the
Company has entered into unconditional purchase obligations for products and
services of $121 million ($94 million on a present value basis) at December 31,
1996. The Company's annual obligations under these agreements are $22 million
for the years 1997 and 1998, $21 million for the years 1999 and 2000, $11
million for the year 2001 and $24 million thereafter. Payments under such
obligations, including additional purchases in excess of contractual
obligations, were $25 million, $26 million and $34 million for the years 1996,
1995 and 1994, respectively. In addition, in connection with the Great Plains
coal gasification project, TGP continues to have an obligation to purchase 30
percent of the output of the plant's original design capacity through July 2009.
TGP has executed a settlement of this contract as a part of its GSR
negotiations.
Management is not aware of other commitments or contingent liabilities
which would have a materially adverse effect on the Company's financial
condition or results of operations.
7. INCOME TAXES
The following table reflects the components of income tax expense for the
periods ended December 31:
1996 1995 1994
---- ---- ----
(IN MILLIONS)
Current
Federal................................................... $23 $13 $15
State..................................................... 7 5 (6)
--- --- ---
30 18 9
--- --- ---
Deferred
Federal................................................... (4) 31 35
State..................................................... (1) (1) 14
--- --- ---
(5) 30 49
--- --- ---
Total tax expense................................. $25 $48 $58
=== === ===
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52
The following table reflects the components of the net deferred tax
liabilities at December 31:
1996 1995
------ ----
(IN MILLIONS)
Deferred tax liabilities
Property, plant, and equipment............................ $1,395 $290
Regulatory and other assets............................... 274 86
------ ----
Total deferred tax liability...................... 1,669 376
------ ----
Deferred tax assets
Accrual for regulatory issues............................. 76 --
Postretirement benefits................................... 124 1
Other liabilities......................................... 503 67
Other..................................................... 15 17
------ ----
Total deferred tax asset.......................... 718 85
------ ----
Net deferred tax liability.................................. $ 951 $291
====== ====
Tax expense of the Company differs from the amount computed by applying the
statutory federal income tax rate to income before taxes. The following table
outlines the reasons for the differences for the periods ended December 31:
1996 1995 1994
---- ---- ----
(IN MILLIONS)
Tax expense at the statutory federal rate of 35%............ $22 $47 $52
Increase (decrease)
State income tax, net of federal income tax benefit....... 4 2 5
Other..................................................... (1) (1) 1
--- --- ---
Income tax expense.......................................... $25 $48 $58
=== === ===
Effective tax rate.......................................... 39% 36% 39%
=== === ===
As of December 31, 1996, approximately $5 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, 1996, approximately $1 million of general business credit and
$10 million of net operating loss carryovers were available to offset future tax
liabilities through the years 2001 and 2011, respectively. Usage of both
carryovers are subject to the limitations provided for under Section 382 of the
IRS Code as well as the separate return limitation year rules of IRS
regulations.
Deferred credits, in the Consolidated Balance Sheets, include excess
deferrals resulting from the reduction of the statutory federal tax rate from 46
to 34 percent on July 1, 1987. Regulatory assets in the Consolidated Balance
Sheets include expected future recoveries resulting from the increase of the
statutory federal rate from 34 to 35 percent on January 1, 1993. Such amounts
have been included in EPG's offer of settlement filed with FERC in March 1996.
EPG and EPTPC each file a separate consolidated federal income tax return
which includes the operations of their respective subsidiaries as they existed
at the time of the Merger. Deferred taxes corresponding to the allocation of the
purchase price to the assets and liabilities acquired, have been reflected in
the Consolidated Balance Sheet at December 31, 1996.
8. CAPITAL STOCK
Common Stock
In December 1996, 18.8 million shares of EPG common stock were issued in
connection with the acquisition of EPTPC. Such shares were valued at
approximately $913 million.
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53
In February 1997, approximately 3 million shares of common stock were
issued under the Shelf Registration Statement. Proceeds of $152 million, net of
issuance costs, were received and used to repay borrowings under the Credit
Facility.
Treasury Stock
From time to time, the Board has authorized the repurchase of EPG's
outstanding shares of common stock to be used in connection with EPG employee
stock-based compensation plans and for other corporate purposes. As of December
31, 1996, and 1995, EPG held 1,451,922 and 3,127,077 shares of treasury stock,
respectively. Included in the balance at December 31, 1996, were 680,000 shares
of treasury stock used to secure benefits under certain of the Company's benefit
plans. These shares are subject to certain restrictions.
Other
EPG has 25,000,000 shares of authorized preferred stock, par value $0.01
per share, none of which have been issued.
9. STOCK-BASED COMPENSATION
At December 31, 1996, the Company had eight stock-based compensation plans,
which are generally described below. The compensation expense for all eight
stock-based compensation plans recognized for 1996 and 1995 was $13 million and
$10 million, respectively. Had compensation cost for the Company's plans been
determined based on the estimated fair value at the grant dates for stock option
awards under those plans consistent with the method prescribed in SFAS No. 123,
the Company's net income and earnings per share would have been reduced to the
pro forma amounts indicated below:
YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31,
1996 1995
------------ ------------
Net Income (in millions) As reported $ 38 $ 85
Pro forma $ 36 $ 83
Earnings Per Share As reported $1.06 $2.47
Pro forma $1.00 $2.41
The costs of stock options granted in 1996 and 1995 were calculated using
the Black-Scholes option pricing model. The Black-Scholes methodology values the
right to exercise an option over its expected life, taking into consideration
stock price volatility, exercise price, market price at grant, expected dividend
yield and risk-free rate of return.
The following significant assumptions were used to estimate the fair value
of options granted in 1996 and 1995:
- Expected life -- A weighted-average expected life of three years was
assumed based on assigned vesting schedules and historical exercise
experience.
- Volatility -- Volatility of approximately 20 percent and 17 percent was
assumed for 1996 and 1995, respectively, based on historical monthly
stock price changes for the time period equal to the expected life
assumption prior to the grant date.
- Dividend yield -- The expected dividend yield was estimated at 3 percent
based on historical experience.
- Risk-free rate of return -- A risk-free rate of return of approximately 6
percent and 7 percent was assumed for 1996 and 1995, respectively, which
is equivalent to the rate available on zero-coupon U.S. government issues
with a remaining term equal to the expected life of the options.
Stock Options
Under EPG's employee stock option plans, options may be granted to officers
and key employees, typically at fair market value on the date of grant,
exercisable in whole or part by the optionee after completion
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54
of 1 to 5 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, EPG may
grant SARs to certain holders of stock options. SARs are subject to the same
terms and conditions as the related stock options. 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 EPG 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.
Activity in EPG's stock option plans for 1994, 1995, and 1996 was as
follows:
EXERCISE PRICE
OPTIONS SARS PER SHARE
--------- ------ ----------------
Balance, January 1, 1994........................ 1,349,736 70,154 $13.51 to $38.19
Granted....................................... 663,100 -- 36.88 to 39.56
Exercised..................................... 50,162 22,000 13.51 to 30.81
Canceled...................................... 29,983 -- 19.00 to 36.88
--------- ------
Balance, December 31, 1994...................... 1,932,691 48,154 $18.14 to $39.56
Granted....................................... 709,000 -- 28.88 to 30.88
Converted in connection with Eastex
acquisition................................ 40,025 -- 15.62
Exercised..................................... 38,761 -- 18.14 to 22.91
Canceled...................................... 39,000 -- 29.94
--------- ------
Balance, December 31, 1995...................... 2,603,955 48,154 $15.62 to $39.56
Granted....................................... 2,429,500 -- 31.38 to 45.88
Converted in connection with Cornerstone
acquisition................................ 37,323 -- 15.62
Exercised..................................... 631,298 22,885 18.14 to 36.88
Canceled...................................... 15,885 -- 19.00 to 28.88
--------- ------
Balance, December 31, 1996...................... 4,423,595 25,269 $15.62 to $45.88
========= ======
Stock options shown as canceled in the table above may be a result of the
tandem SAR being exercised. SARs shown in the table above will be canceled when
the underlying stock options are exercised.
The weighted average fair value of options granted during 1996 and 1995 was
as follows:
1996 1995
------ ------
Options granted at market price............................. $32.37 $29.85
Options granted below market price.......................... $36.25 $28.88
The following table summarizes information about stock options outstanding
at December 31, 1996:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- ------------------------------
WEIGHTED AVERAGE
RANGE OF NUMBER REMAINING WEIGHTED AVERAGE NUMBER WEIGHTED AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
--------------- ----------- ---------------- ---------------- ----------- ----------------
$15.62 to $21.81 450,701 5.52 years $18.35 450,701 $18.35
25.69 to 38.19 3,786,894 8.37 32.56 1,524,394 32.94
39.56 to 45.88 186,000 9.87 45.61 5,000 39.56
--------- ---------
$15.62 to $45.88 4,423,595 8.14 $31.66 1,980,095 $29.64
========= =========
Restricted Stock
Under the Company's various stock-based compensation plans, common stock of
the Company 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
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stock awards will vest only if the Company achieves certain performance targets
over a specific period of time. The majority of shares outstanding as of
December 31, 1996, were approximately 70 percent vested. As of December 31,
1996, 1.6 million shares of restricted stock with a weighted average grant-date
fair value of $34.32 had been issued under the Company's various stock-based
compensation plans. The value of these shares is determined based on the fair
market value on the measurement date and is charged to compensation expense
ratably over the restriction period based on the number of shares earned over
the vesting period. Amortized to compensation expense for 1996 and 1995 was $6
million and $3 million, respectively. The unamortized balance at December 31,
1996, was $69 million and is recorded as a reduction to stockholder's equity.
Performance Units
Under the company's various stock-based compensation plans, 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 value of the performance units
may vary according to the plan under which they are granted, but is usually
based on the Company's stock price at the end of the vesting period or another
amount which is associated with 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 1996 and 1995 were $5 million and $7 million,
respectively.
The maximum number of shares for which stock options or restricted stock
awards may be granted under EPG's current stock-based compensation plans is
approximately 8 million shares of common stock
(which includes grants previously made), to be issued from shares held in EPG's
treasury, or out of authorized but unissued shares of EPG's common stock, or
partly out of each, as determined by the Board.
10. EMPLOYEE BENEFITS
Pensions
The Company maintains a defined benefit pension plan covering all employees
of the Company, except leased employees. Pension benefits are based on years of
credited service and final 5-year average compensation, and have maximum
limitations as defined in the pension plan.
During 1996, the Company offered early retirement window benefits to
employees with at least five years of service and at least 52 years old on
February 29, 1996. Under the early retirement window, benefits were determined
by adding three years to age and, if otherwise eligible for early retirement,
adding three years to credited service. Approximately 400 employees accepted the
offer and retired during 1996. The Company further reduced its workforce by
approximately 500 employees through an involuntary reduction-in-force. During
the first quarter of 1996, the Company recognized a $21 million charge for the
early retirement window and workforce reductions.
Effective January 1, 1997, the plan was amended to provide benefits
determined by a cash balance formula. Participants were credited with an initial
cash balance equivalent to accrued benefits on December 31, 1996. Participant
accounts are credited with a percentage of pay based on age and service, and
interest based on prevailing market yields on certain U.S. treasury obligations.
Participants receive the greater of cash balance benefits or prior plan benefits
accrued through December 31, 2001. EPTPC, Cornerstone and EPEM employees
commenced participation on January 1, 1997, with no account balance for prior
service.
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The following table sets forth the components of net periodic pension cost
for the years ended December 31.
1996 1995 1994
---- ---- ----
(IN MILLIONS)
Service cost -- benefits earned during the period........... $ 7 $ 9 $ 9
Interest cost on projected benefit obligation............... 41 41 40
Actual (return) loss on plan assets......................... (65) (86) 5
Net amortization and deferral............................... 26 49 (40)
Curtailment and special termination benefits expense........ 21 -- --
---- ---- ----
Net periodic pension cost................................... $ 30 $ 13 $ 14
==== ==== ====
The following table sets forth the qualified pension plan's funded status
and amounts recognized in the Company's Consolidated Balance Sheets at December
31:
1996 1995
----- -----
(IN MILLIONS)
Actuarial present value of benefit obligations
Vested benefits........................................... $483 $508
Nonvested benefits........................................ 1 1
---- ----
Accumulated benefit obligation.............................. 484 509
Additional amounts related to projected salary increases.... 21 78
---- ----
Projected benefit obligation for service rendered to date... 505 587
Plan assets at fair value, primarily listed stocks and
government securities..................................... 498 473
---- ----
Projected benefit obligation in excess of plan assets....... $ 7 $114
==== ====
Unrecognized net loss....................................... $ 4 $ 76
Unrecognized net transition obligation...................... 10 17
Unrecognized prior service cost............................. (40) --
Recognized pension liability................................ 33 21
---- ----
$ 7 $114
==== ====
The accumulated vested benefit obligation is the actuarial present value of
the vested benefits to which the employee is currently entitled, but it is based
on the employee's expected date of termination.
The following table reflects the actuarial assumptions used in the
valuation of the projected benefit obligation at December 31:
1996 1995
----- -----
Weighted average discount rate.............................. 7.75% 7.25%
Rate of increase in future compensation levels.............. 5.00% 5.00%
Weighted average expected long-term rate of return on plan
assets.................................................... 9.25% 9.25%
Retirement Savings Plan
The Company maintains a defined contribution plan covering all employees of
the Company. During 1994, 1995, and 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 has fewer than 10 years of employment with
the Company, or up to 8 percent where the participant has 10 or more years of
employment with the Company. In July 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
expensed under the plan were approximately $4 million, $8 million and $8 million
for the years ended December 31, 1996, 1995, and 1994, respectively.
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Postretirement Benefits, Other than Pensions
The Financial Accounting Standards Board issued SFAS No. 106, Employers'
Accounting for Post Retirement Benefits Other Than Pensions, which requires
companies to account for OPEB (principally retiree medical costs) on an accrual
basis versus the pay-as-you-go basis. The Company adopted SFAS No. 106 effective
January 1, 1993, and elected 20-year amortization of the transition obligation.
EPG provides a non-contributory defined benefit postretirement medical plan
that covers employees who retired on or before March 1, 1986, and limited
postretirement life insurance for employees who retire after January 1, 1985. As
such, EPG's obligation to accrue for 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.
EPG began recovering through its rates the OPEB costs included in the
January 1993 settlement agreement. To the extent actual OPEB costs differ from
the amounts funded, a regulatory asset or liability is recorded.
As a result of the Merger, TGP assumed responsibility for certain benefits
for former employees of Old Tenneco and the postretirement health care plans for
employees of TGP were significantly changed. TGP will be responsible for
benefits for both TGP former employees and former employees of operations
previously disposed of by Old Tenneco. TGP employees who retire before July 1,
1997 will receive the same benefits as former employees. While TGP employees who
retire on or after July 1, 1997 will continue to receive $10,000 of
postretirement life insurance, they will not receive any employer subsidized
postretirement health care benefits. All of these benefits may be subject to
deductibles, co-payment provisions and other limitations. The Company has
reserved the right to change these benefits.
The majority of TGP's postretirement benefit plans are not funded. In June
1994, two trusts were established to fund postretirement benefits for certain
plan participants of TGP. The contributions are collected from customers in
FERC-approved rates.
The following table reflects the components of net periodic postretirement
benefit cost for the years ended December 31:
1996 1995 1994
---- ---- ----
(IN MILLIONS)
Interest cost on accumulated postretirement benefit
obligation................................................ $ 6 $ 7 $ 7
Actual (return) loss on plan assets......................... (4) (5) --
Net amortization and deferral............................... 9 10 7
--- --- ---
Net periodic postretirement benefit cost.................... $11 $12 $14
=== === ===
The following table sets forth the funded status of the Company's
postretirement plans and amounts recognized in the Company's Consolidated
Balance Sheets at December 31:
1996 1995
----- -----
(IN MILLIONS)
Accumulated postretirement benefit obligation............... $426 $ 91
Plan assets at fair value, primarily U.S. stocks and U.S.
bonds..................................................... 41 30
---- ----
Accumulated postretirement benefit obligation in excess of
plan assets............................................... $385 $ 61
==== ====
Unrecognized net gain....................................... $(40) $(23)
Unrecognized transition obligation.......................... 79 88
(Prepaid) accrued postretirement benefit cost............... 346 (4)
---- ----
$385 $ 61
==== ====
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The accrued postretirement benefit cost for 1996 has been recorded based
upon certain actuarial estimates as described below. Those estimates are subject
to revision in future periods given new facts or circumstances.
Actuarial estimates for the Company's plans assumed a weighted average
annual rate of increase in the per capita costs of covered health care benefits
of 5.6 percent for 1997, gradually decreasing to 5.1 percent by the year 2003.
Increasing the assumed health care cost trend rates by one percentage point in
each year would increase the accumulated postretirement benefit obligation at
December 31, 1996, by approximately $10 million and increase the interest cost
component of net periodic postretirement benefit cost for 1996 by approximately
$0.5 million. A discount rate of 7.75 percent and 7.25 percent was used to
determine the accumulated postretirement benefit obligation at December 31,
1996, and 1995, respectively. The weighted average expected long-term rate of
return for 1996 was approximately 7.5 percent.
11. PREFERRED STOCK OF SUBSIDIARY
In November 1996, EPTPC issued in a public offering 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 the Company, after December 31, 2001, at a redemption price equal to
$50 per share, plus dividends accrued and unpaid up to the date of redemption.
On December 31, 1996, dividends of approximately $3 million were paid on
the cumulative preferred stock, of which approximately $2 million is reflected
as minority interest on the income statement for the 20 days EPTPC is included
in the consolidated results of operations.
12. SEGMENT INFORMATION
To the extent practicable, the following information for 1995 has been
reclassified to conform to the current business segment presentation.
Information for 1994 has not been presented due to the inability to reclassify
the data to conform to current presentation.
FOR YEARS ENDED NATURAL GAS FIELD & CORPORATE
DECEMBER 31 TRANSMISSION MERCHANT & OTHER ELIMINATIONS CONSOLIDATED
--------------- ------------ -------- --------- ------------ ------------
(IN MILLIONS)
Operating Revenues
1996....................... $ 569 $2,448 $ 1 $ (8) $3,010
1995....................... 540 492 8 (2) 1,038
Operating Income (Loss)
1996....................... 223 57 (110) -- 170
1995....................... 203 1 8 -- 212
Depreciation, Depletion and
Amortization
1996....................... 70 30 1 -- 101
1995....................... 53 19 -- -- 72
Identifiable Assets
1996....................... 6,162 1,287 1,501 (238) 8,712
1995....................... 1,867 556 138 (26) 2,535
Capital Expenditures
1996....................... 55 64 -- -- 119
1995....................... 92 74 -- -- 166
Operating revenues by segment include both sales to unaffiliated customers
and intersegment sales (which are accounted for principally at market prices and
eliminated in consolidation).
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13. INVENTORIES
Inventories consisted of the following at December 31:
1996 1995
---- ----
(IN MILLIONS)
Materials and supplies...................................... $29 $30
Gas in storage.............................................. 58 7
--- ---
Total $87 $37
=== ===
14. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
1996 1995
------ ------
(IN MILLIONS)
Property, plant, and equipment, at cost..................... $8,937 $3,041
Less accumulated depreciation and depletion................. 4,726 1,158
------ ------
4,211 1,883
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 1,727 94
------ ------
Total property, plant, and equipment, net......... $5,938 $1,977
====== ======
15. NATURE OF OPERATIONS AND SIGNIFICANT CUSTOMERS
The Company is principally engaged in the transportation, gathering and
processing, and marketing of natural gas. For the year ended December 31, 1996,
the Company's operating revenues were predominately derived from the marketing
and transportation of natural gas and other commodities. California was the
Company's principal market for the transportation of natural gas in 1996.
The Company had gross revenues equal to, or in excess of, 10 percent of
consolidated operating revenues from the following customers for the years ended
December 31:
1996 1995 1994
---- ---- ----
(IN MILLIONS)
Southern California Gas Company........................... --(a) $176 $191
Pacific Gas & Electric Company............................ --(a) 128 155
- ---------------
(a) Less than 10 percent of consolidated operating revenues.
16. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
1996 1995 1994
---- ---- ----
(IN MILLIONS)
Interest.................................................... $85 $77 $71
Income taxes, net of refunds................................ 49 10 31
See Note 2, Acquisitions, for a discussion of the non-cash investing
transaction related to certain acquisitions.
55
60
17. 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.
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
1996
Operating revenues................................ $1,072 $ 745 $ 587 $ 606
Operating income (loss)........................... 75 66 62 (33)
Net income (loss)................................. 24 25 24 (35)
Earnings (loss) per common share.................. 0.61 0.70 0.69 (1.01)
1995
Operating revenues................................ $ 409 $ 240 $ 185 $ 204
Operating income.................................. 51 53 53 55
Net income........................................ 23 20 20 22
Earnings per common share......................... 0.67 0.60 0.58 0.62
56
61
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
El Paso Natural Gas Company:
We have audited the consolidated financial statements and the financial
statement schedule of El Paso Natural Gas Company listed in Item 14(a) of this
Form 10-K. 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 in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of El Paso Natural
Gas Company as of December 31, 1996 and 1995, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement schedule
referred to above, when considered in relation to the basic financial statements
taken as a whole, presents fairly, in all material respects, the information
required to be included therein.
COOPERS & LYBRAND L.L.P.
El Paso, Texas
February 28, 1997
57
62
SCHEDULE II
EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1996, 1995, AND 1994
(IN MILLIONS)
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
----------- ---------- -------- -------- ---------- ---------
1996
Allowance for bad debts.................. $ 10 $ 2 $ 51(a) $ 3 $ 60
Allowance for take-or-pay receivables.... 1 -- -- 1 --
1995
Allowance for bad debts.................. $ 15 $ 2 $ 2 $ 9(b) $ 10
Allowance for take-or-pay receivables.... 9 -- -- 8 1
1994
Allowance for bad debts.................. $ 9 $ 2 $ 4 $ -- $ 15
Allowance for take-or-pay receivables.... 19 -- -- 10 9
- ---------------
(a) Primarily due to acquisition of EPTPC.
(b) Primarily accounts written off.
58
63
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 caption "Proposal No. 1 -- Election of
Directors" in EPG's proxy statement for the 1997 Annual Meeting of Stockholders
is incorporated herein by reference. Information regarding executive officers of
the Company is presented in Item 1 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 EPG's
proxy statement for the 1997 Annual Meeting of Stockholders is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF A BENEFICIAL OWNER AND MANAGEMENT
Information appearing under the caption "Security Ownership of Beneficial
Owners and Management" in EPG's proxy statement for the 1997 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:
PAGE
----
Consolidated statements of income...................... 28
Consolidated balance sheets............................ 29
Consolidated statements of cash flows.................. 30
Consolidated statements of stockholders' equity........ 31
Notes to consolidated financial statements............. 32
Report of independent accountants...................... 57
2. Financial statement schedules and supplementary information
required to be submitted.
Schedule II -- Valuation and qualifying accounts....... 58
Schedules other than that listed above are omitted
because they are not applicable
3. Exhibit list............................................. 61
59
64
(B) REPORTS ON FORM 8-K:
On October 22, 1996, EPG filed a report under Item 5 on Form 8-K, dated
October 22, 1996, as amended pursuant to a Form 8-K/A filed November 5, 1996,
with respect to the filing of Amendments No. 1 and No. 2, respectively, to the
Registration Statement on Form S-4 with the SEC.
On November 13, 1996, EPG filed a report under Item 5 on Form 8-K, dated
November 13, 1996, with respect to the issuance by the Company of $200,000,000
of 6 3/4% Notes due 2003 and $200,000,000 of 7 1/2% Debentures due 2026, under
an Indenture dated as of November 13, 1996, between EPG and The Chase Manhattan
Bank, as trustee.
On December 26, 1996, EPG filed a report under Items 2, 5 and 7 on Form
8-K, dated December 26, 1996, as amended pursuant to amendments on Form 8-K/A
filed January 21, 1997 and January 22, 1997, respectively, with respect to the
Company's acquisition of EPTPC. Financial statements of EPTPC were filed.
60
65
EL PASO NATURAL GAS COMPANY
EXHIBIT LIST
DECEMBER 31, 1996
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.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2 -- Amended and Restated Merger Agreement dated as of June
19, 1996 among El Paso Natural Gas Company, El Paso
Merger Company and Tenneco Inc. (Exhibit 2.A to
Registration No. 333-10911).
3.A -- Restated Certificate of Incorporation of EPG dated
January 22, 1992. (Form 10-K, No. 1-2700, filed January
29, 1992); Certificate of Designation, Preferences and
Rights of Series A Junior Participating Preferred Stock
of EPG, dated July 7, 1992, (Form 10-K, No. 1-2700, filed
February 3, 1993).
3.B -- By-laws of EPG, as amended April 1, 1996. (Exhibit 3(ii)
to Registration Statement No. 10911).
4 -- Shareholder Rights Plan (Form 10-Q, No. 1-2700, filed
November 12, 1992).
10.A -- Transportation Service Agreement as Amended and Restated,
effective November 1, 1993, between EPG and Pacific Gas
and Electric Company. (Form 10-K, No. 1-2700, filed
January 26, 1995).
10.B -- Transportation Service Agreement as Amended and Restated,
effective July 16, 1993, between EPG and Southern
California Gas Company. (Form 10-K, No. 1-2700, filed
January 26, 1995).
10.C -- Transportation Service Agreement, dated August 9, 1991,
and effective September 1, 1991, between EPG and
Southwest Gas Corporation for service to Arizona;
Transportation Service Agreement, dated August 9, 1991,
and effective September 1, 1991, between EPG and
Southwest Gas Corporation for service to Nevada (Form
10-Q, No. 1-2700, filed November 14, 1991); Amendatory
Agreement and replacement of Exhibit B to Transportation
Service Agreement dated August 9, 1991, and effective May
8, 1992, between EPG and Southwest Gas Corporation for
service to Nevada. (Form 10-K, No. 1-2700, filed February
3, 1993). Exhibit B to the Transportation Service
Agreement dated August 9, 1991, and effective March 1,
1994, between EPG and Southwest Gas Corporation for
service to Arizona. (Form 10-K, No. 1-2700, filed January
26, 1995).
10.D -- Master Separation Agreement and documents related thereto
dated January 15, 1992, by and among Burlington Resources
Inc., EPG and Meridian Oil Holding Inc., including
Exhibits (Form 10-K, No. 1-2700, filed January 29, 1992).
*10.E -- $750 million Revolving Credit and Competitive Advance
Facility Agreement dated as of November 4, 1996 between
EPG, The Chase Manhattan Bank and certain other banks.
*10.F -- $3 billion Revolving Credit and Competitive Advance
Facility Agreement dated as of November 4, 1996 between
Tenneco (renamed El Paso Tennessee Pipeline Co.), The
Chase Manhattan Bank and certain other banks.
*10.G -- $250 million Revolving Credit and Competitive Advance
Facility Agreement dated as of November 4, 1996 between
EPG, The Chase Manhattan Bank and certain other banks.
+10.H -- Omnibus Compensation Plan dated as of January 1, 1992,
(Amendment No. 1 to Form S-2, No. 33-45369, filed
February 27, 1992).
61
66
EXHIBIT
NUMBER DESCRIPTION
------- -----------
+10.I -- 1995 Incentive Compensation Plan effective as of January
13, 1995 (Form S-8, No. 33-57553, filed February 2,
1995); Amendment No. 1 to EPG's 1995 Incentive
Compensation Plan, effective as of July 1, 1995 (Form
10-Q, No. 1-2700, filed July 21, 1995); Amendment No. 2
to the 1995 Incentive Compensation Plan effective January
1, 1996 (Exhibit 10.I.1 to EPG's Form 10-K for the fiscal
year ended December 31, 1995, File No. 1-2700).
+10.J -- 1995 Compensation Plan for Non-Employee Directors
effective as of January 13, 1995 (Form S-8, No. 33-57553,
filed February 2, 1995).
+10.K -- Stock Option Plan for Non-Employee Directors dated as of
January 1, 1992, (Amendment No. 1 to Form S-2, No.
33-45369, filed February 27, 1992).
+10.L -- 1995 Omnibus Compensation Plan effective as of January
13, 1995 (Form S-8, No. 33-57553, filed February 2,
1995); Amendment No. 1 to EPG's 1995 Omnibus Compensation
Plan, effective as of July 21, 1995 (Form 10-Q, No.
1-2700, filed July 21, 1995).
+10.M -- Supplemental Benefits Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
+10.N -- Senior Executive Survivor Benefit Plan effective January
1, 1992, (Amendment No. 1 to Form S-2, No. 33-45369,
filed February 27, 1992).
+10.O -- Deferred Compensation Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
+10.P -- Retirement Income Plan for Non-Employee Directors,
Amended and Restated Effective as of January 13, 1995
(Form 10-K, No. 1-2700, filed January 26, 1995).
+10.Q -- Key Executive Severance Protection Plan, Amended and
Restated Effective as of January 13, 1995 (Form 10-K, No.
1-2700, filed January 26, 1995).
+10.R -- Director Charitable Award Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995); Amendment No. 1 to the Director
Charitable Award Plan effective as of January 22, 1996
(Exhibit 10.R.1 to EPG's Form 10-K for the fiscal year
ended December 31, 1995, File No. 1-2700).
+10.S -- Employment Agreement dated July 31, 1992, between EPG and
William A. Wise (Form 10-K, No. 1-2700, filed February 3,
1993); Amendment to Employment Agreement dated January
29, 1996 between EPG and William A. Wise (Exhibit 10.T.1
to EPG's Form 10-K for the fiscal year ended December 31,
1995, File No. 1-2700).
+10.T -- Letter Agreement dated February 22, 1991, between EPG and
Britton White, Jr. (Form 10-K, No. 1-2700, filed February
3, 1993).
+10.U -- Letter Agreement dated January 13, 1995, between EPG and
William A. Wise (Form 10-K, No. 1-2700, filed January 26,
1995).
10.V -- Amended and Restated Limited Liability Company Agreement
of Aguaytia Energy, LLC entered into November 30, 1995,
by and among The Maple Gas Corporation del Peru Ltd, The
Maple Gas Corporation, P.I.D.C. Aguaytia, L.L.C., EPED
Aguaytia Company, IGC Aguaytia Partners, L.L.C., Scudder
Latin American Power I-P L.D.C., and PMDC Aguaytia, Ltd.
(Exhibit 10.G to EPG's Form 10-K for the fiscal year
ended December 31, 1995, File No. 1-2700).
*11 -- Computation of Earnings per Common Share.
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*21 -- Subsidiaries of the Registrant.
*23 -- Consent of Experts.
*27 -- Financial Data Schedule.
62
67
UNDERTAKING.
The undersigned, El Paso Natural Gas Company, hereby undertakes, pursuant
to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities
and Exchange Commission upon request all constituent instruments defining the
rights of holders of long-term debt of El Paso Natural Gas Company 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 El Paso Natural Gas Company and its
consolidated subsidiaries.
63
68
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized on the 7th
day of March 1997.
EL PASO NATURAL GAS COMPANY
Registrant
By /s/ WILLIAM A. WISE
------------------------------------
William A. Wise
Chairman of the Board and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of El Paso
Natural Gas Company and in the capacities and on the dates indicated:
SIGNATURE TITLE DATE
--------- ----- ----
/s/ WILLIAM A. WISE Chairman of the Board, Chief March 7, 1997
- ----------------------------------------------------- Executive Officer and
(William A. Wise) Director
/s/ RICHARD O. BAISH President March 7, 1997
- -----------------------------------------------------
(Richard O. Baish)
/s/ H. BRENT AUSTIN Executive Vice President and March 7, 1997
- ----------------------------------------------------- Chief Financial Officer
(H. Brent Austin)
/s/ JEFFREY I. BEASON Vice President, Controller, and March 7, 1997
- ----------------------------------------------------- Chief Accounting Officer
(Jeffrey I. Beason)
/s/ BYRON ALLUMBAUGH Director March 7, 1997
- -----------------------------------------------------
(Byron Allumbaugh)
/s/ EUGENIO GARZA LAGUERA Director March 7, 1997
- -----------------------------------------------------
(Eugenio Garza Lag(i)uera)
/s/ JAMES F. GIBBONS Director March 7, 1997
- -----------------------------------------------------
(James F. Gibbons)
/s/ BEN F. LOVE Director March 7, 1997
- -----------------------------------------------------
(Ben F. Love)
/s/ KENNETH L. SMALLEY Director March 7, 1997
- -----------------------------------------------------
(Kenneth L. Smalley)
/s/ MALCOLM WALLOP Director March 7, 1997
- -----------------------------------------------------
(Malcolm Wallop)
64
69
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3(i) -- Restated Certificate of Incorporation of EPG dated
January 22, 1992. (Form 10-K, No. 1-2700, filed January
29, 1992); Certificate of Designation, Preferences and
Rights of Series A Junior Participating Preferred Stock
of EPG, dated July 7, 1992, (Form 10-K, No. 1-2700, filed
February 3, 1993).
3(ii) -- By-laws of EPG, as amended September 1, 1994. (Form 10-K,
No. 1-2700, filed January 26, 1995).
4.B.1 -- Indenture, dated as of March 1, 1987, between EPG and
Citibank, N.A., Trustee, with respect to EPG's 8 5/8%
Debentures due 2012 (Form S-3, No. 33-34284, filed April
20, 1990); Supplemental Indenture, dated December 24,
1991, (Form 10-K, No. 1-2700, filed January 29, 1992).
4.B.2 -- Indenture, dated as of August 1, 1987, between EPG and
Citibank, N.A., Trustee, with respect to EPG's 9.45%
Notes due 1999 (Form S-3, No. 33-34284, filed April 20,
1990); Supplemental Indenture, dated December 24, 1991,
(Form 10-K, No. 1-2700, filed January 29, 1992).
4.B.3 -- Indenture, dated as of January 1, 1992, between EPG and
Citibank, N.A., Trustee, with respect to EPG's 6.90%
Notes due 1997, 7 3/4% Notes due 2002 and 8 5/8%
Debentures due 2022 (Form 10-K, No. 1-2700, filed January
29, 1992).
4.C -- Shareholder Rights Plan (Form 10-Q, No. 1-2700, filed
November 12, 1992).
10.A -- Mojave Pipeline General Partnership Agreement by and
among El Paso Mojave Pipeline Co., HNG Mojave, Inc., and
Pacific Interstate Mojave Company, dated as of March 26,
1985, (Form 10-Q, No. 1-2700, filed May 15, 1985);
Amendment No. 1 to General Partnership Agreement dated as
of September 29, 1986, (Form 10-Q, No. 1-2700, filed May
13, 1988); Amendment No. 2 to General Partnership
Agreement dated as of September 30, 1991, (Form 10-Q, No.
1-2700, filed November 14, 1991).
10.B -- Lease, dated May 27, 1982, between EPG and First Capital
Kayser Center (Form 10-Q, No. 1-2700, filed November 14,
1991).
10.C -- Transportation Service Agreement as Amended and Restated,
effective November 1, 1993, between EPG and Pacific Gas
and Electric Company. (Form 10-K, No. 1-2700, filed
January 26, 1995).
10.D -- Transportation Service Agreement as Amended and Restated,
effective July 16, 1993, between EPG and Southern
California Gas Company. (Form 10-K, No. 1-2700, filed
January 26, 1995).
10.E -- Transportation Service Agreement, dated August 9, 1991,
and effective September 1, 1991, between EPG and
Southwest Gas Corporation for service to Arizona;
Transportation Service Agreement, dated August 9, 1991,
and effective September 1, 1991, between EPG and
Southwest Gas Corporation for service to Nevada (Form
10-Q, No. 1-2700, filed November 14, 1991); Amendatory
Agreement and replacement of Exhibit B to Transportation
Service Agreement dated August 9, 1991, and effective May
8, 1992, between EPG and Southwest Gas Corporation for
service to Nevada. (Form 10-K, No. 1-2700, filed February
3, 1993). Exhibit B to the Transportation Service
Agreement dated August 9, 1991, and effective March 1,
1994, between EPG and Southwest Gas Corporation for
service to Arizona. (Form 10-K, No. 1-2700, filed January
26, 1995).
70
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.F -- Credit Agreement among Mojave Pipeline Company and
Deutsche Bank AG, New York Branch, and Swiss Bank
Corporation, New York Branch, individually and as Agents,
and the Banks named therein, dated as of September 30,
1991, and the following documents related thereto:
Sponsor Performance Agreement among EPG and Deutsche Bank
AG, New York Branch, as Collateral Agent and Deutsche
Bank AG, New York Branch and Swiss Bank Corporation, New
York Branch, as Agents, dated as of September 30, 1991;
Partner Performance Agreement among El Paso Mojave
Pipeline Co. and Deutsche Bank AG, New York Branch, as
Collateral Agent and Deutsche Bank AG, New York Branch
and Swiss Bank Corporation, New York Branch, as Agents,
dated as of September 30, 1991; Pledge Agreement made by
El Paso Mojave Pipeline Co. with and to Deutsche Bank AG,
New York Branch (as Collateral Agent) for the Secured
Creditors, dated as of September 30, 1991; $90,000,000
Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Deutsche Bank AG, New
York Branch; $90,000,000 Note dated September 30, 1991,
executed by Mojave Pipeline Company and payable to Swiss
Bank Corporation, New York Branch (Form 10-Q, No. 1-2700,
filed November 14, 1991); Syndication and replacement of
Notes with a $52,750,000 Note dated September 30, 1991,
executed by Mojave Pipeline Company and payable to Swiss
Bank Corporation, New York Branch; a $40,000,000 Note
dated September 30, 1991, executed by Mojave Pipeline
Company and payable to Deutsche Bank AG, New York Branch;
a $30,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Banque Indosuez; a
$20,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to the Sumitomo Bank,
Limited, Houston Agency; a $20,000,000 Note dated
September 30, 1991, executed by Mojave Pipeline Company
and payable to the Bank of Nova Scotia; a $17,250,000
Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Credit Lyonnais Cayman
Islands Branch (Form 10-K, No. 1-2700, filed January 29,
1992). First Amendment to Credit Agreement dated as
effective December 23, 1992, among Mojave Pipeline
Company and Deutsche Bank AG, New York Branch and Swiss
Bank Corporation, New York Branch; Amendment to Sponsor
and Partner Performance Agreements entered into effective
as of December 23, 1992; Syndication and replacement of
Note for $52,750,000 payable to Swiss Bank Corporation,
New York Branch and Note for $17,250,000 payable to
Credit Lyonnais Cayman Islands Branch with a $40,000,000
Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Swiss Bank Corporation,
New York Branch; and a $30,000,000 Note dated September
30, 1991, executed by Mojave Pipeline Company and payable
to Credit Lyonnais Cayman Islands Branch, Second
Amendment to Credit Agreement dated as effective June 1,
1993, among Mojave Pipeline Company and Deutsche Bank AG,
New York Branch and Swiss Bank Corporation, New York
Branch; Amended and Restated Sponsor Performance
Agreement dated as effective June 1, 1993, among El Paso
Natural Gas Company and Deutsche Bank AG, New York Branch
and Swiss Bank Corporation, New York Branch; Amendment
and Ratification of Partner Documents dated as effective
June 1, 1993, among EPNG Mojave, Inc. and El Paso Mojave
Pipeline Co. and Deutsche Bank AG, New York Branch and
Swiss Bank Corporation, New York Branch (Form 10-Q, No.
1-2700, filed August 16, 1993). Replacement of
$30,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Banque Indosuez
with a $30,000,000 Note dated September 30, 1991,
executed by Mojave Pipeline Company and payable to Bank
of Scotland. (Form 10-Q, No. 1-2700, filed May 13, 1994).
71
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.G -- Master Separation Agreement and documents related thereto
dated January 15, 1992, by and among Burlington Resources
Inc., EPG and Meridian Oil Holding Inc., including
Exhibits (Form 10-K, No. 1-2700, filed January 29, 1992).
10.H -- Revolving Credit and Competitive Advance Facility
Agreement dated as of August 10, 1994 between EPG,
Chemical Bank and certain other banks (Form 10-Q, No.
1-2700, filed November 14, 1994).
+10.I -- Omnibus Compensation Plan dated as of January 1, 1992,
(Amendment No. 1 to Form S-2, No. 33-45369, filed
February 27, 1992).
+10.J -- 1995 Incentive Compensation Plan effective as of January
13, 1995 (Form S-8, No. 33-57553, filed February 2,
1995); Amendment No. 1 to EPG's 1995 Incentive
Compensation Plan, effective as of July 1, 1995 (Form
10-Q, No. 1-2700, filed July 21, 1995).
*+10.J.1 -- Amendment No. 2 to the 1995 Incentive Compensation Plan
effective January 1, 1996.
+10.K -- 1995 Compensation Plan for Non-Employee Directors
effective as of January 13, 1995 (Form S-8, No. 33-57553,
filed February 2, 1995).
+10.L -- Stock Option Plan for Non-Employee Directors dated as of
January 1, 1992, (Amendment No. 1 to Form S-2, No.
33-45369, filed February 27, 1992).
+10.M -- 1995 Omnibus Compensation Plan effective as of January
13, 1995 (Form S-8, No. 33-57553, filed February 2,
1995); Amendment No. 1 to EPG's 1995 Omnibus Compensation
Plan, effective as of July 21, 1995 (Form 10-Q, No.
1-2700, filed July 21, 1995).
+10.N -- Supplemental Benefits Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
+10.O -- Senior Executive Survivor Benefit Plan effective January
1, 1992, (Amendment No. 1 to Form S-2, No. 33-45369,
filed February 27, 1992).
+10.P -- Deferred Compensation Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
+10.Q -- Retirement Income Plan for Non-Employee Directors,
Amended and Restated Effective as of January 13, 1995
(Form 10-K, No. 1-2700, filed January 26, 1995).
+10.R -- Key Executive Severance Protection Plan, Amended and
Restated Effective as of January 13, 1995 (Form 10-K, No.
1-2700, filed January 26, 1995).
+10.S -- Director Charitable Award Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
*+10.S.1 -- Amendment No. 1 to the Director Charitable Award Plan
effective as of January 22, 1996.
10.T -- Receivables Purchase and Sale Agreement dated as of
January 14, 1992, between EPG, CIESCO L.P., Corporate
Asset Funding Company, Inc. and Citicorp North America,
Inc. (Form 10-K, No. 1-2700, filed February 3, 1993).
+10.U -- Employment Agreement dated July 31, 1992, between EPG and
William A. Wise (Form 10-K, No. 1-2700, filed February 3,
1993).
*+10.U.1 -- Amendment to Employment Agreement dated January 29, 1996
between EPG and William A. Wise.
72
EXHIBIT
NUMBER DESCRIPTION
------- -----------
*10.V -- Amended and Restated Limited Liability Company Agreement
of Aguaytia Energy, LLC entered into November 30, 1995,
by and among The Maple Gas Corporation del Peru Ltd, The
Maple Gas Corporation, P.I.D.C. Aguaytia, L.L.C., EPED
Aguaytia Company, IGC Aguaytia Partners, L.L.C., Scudder
Latin American Power I-P L.D.C., and PMDC Aguaytia, Ltd.
+10.W -- Letter Agreement dated February 22, 1991, between EPG and
Britton White, Jr. (Form 10-K, No. 1-2700, filed February
3, 1993).
+10.X -- Letter Agreement dated January 13, 1995, between EPG and
William A. Wise (Form 10-K, No. 1-2700, filed January 26,
1995).
10.Y -- Participation and Credit Agreement dated as of February
9, 1995, among EPG, El Paso New Chaco Company, State
Street Bank and Trust Company, Chemical Bank, as Agent,
the Note Holders Signatories and the Certificate Holders
Signatories (without exhibits and schedules, except for
the schedule of defined terms), and the following
documents related thereto: Lease Agreement dated as of
February 9, 1995, between State Street Bank and Trust
Company and El Paso New Chaco Company, Support Agreement
between El Paso New Chaco Company and State Street Bank
and Trust Company dated as of February 9, 1995; Guaranty
Agreement by EPG in favor of Chemical Bank, as Agent, and
Each of the Participants as of February 9, 1995; Sponsor
Agreement by EPG in favor of State Street Bank and Trust
Company, as of February 9, 1995; Mortgage, Assignment,
Security Agreement and Financing Statement, executed
February 7, 1995, between State Street Bank and Trust
Company (Mortgagor) and Chemical Bank (Mortgagee);
Security Agreement among State Street Bank and Trust
Company and Chemical Bank, as Agent, dated February 9,
1995 (Form 10-Q, No. 1-2700, filed April 28, 1995).
*+10.Z -- Letter dated February 4, 1992 between EPG and Michael C.
Holland.
*11 -- Computation of Earnings per Common Share.
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*21 -- Subsidiaries of the Registrant.
*23 -- Consent of Experts.
*27 -- Financial Data Schedule.
Each exhibit identified on this Exhibit List 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.