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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.
24
29
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 t