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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 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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
(STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION)
ONE PAUL KAYSER CENTER
100 NORTH STANTON STREET, EL PASO, TEXAS
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
74-0608280
(I.R.S. EMPLOYER
IDENTIFICATION NO.)
79901
(ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (915) 541-2600
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
COMMON STOCK, PAR VALUE $3 PER SHARE
PREFERRED STOCK PURCHASE RIGHTS
9.45% Notes due 1999
8 5/8% Debentures due 2012
THE ABOVE SECURITIES ARE REGISTERED ON THE 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 .
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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 29,
1996, computed by reference to the closing sale price of the registrant's common
stock on the New York Stock Exchange on such date: $1,190,527,503.
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Class: common stock, par value $3 per share. Shares outstanding on February
29, 1996: 35,274,889
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
1996 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
ITEM NO. CAPTION PAGE
- -------- ------- ----
Glossary................................................................................. ii
PART I
1. and 2. Business and Properties.................................................... 1
3. Legal Proceedings.......................................................... 12
4. Submission of Matters to a Vote of Security Holders........................ 12
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters...... 13
6. Selected Financial Data.................................................... 14
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 15
(a) Cautionary Statement for Purposes of the "Safe Harbor" Provisions of
the Private Securities Litigation Reform Act of 1995................. 24
8. Financial Statements and Supplementary Data................................ 26
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure............................................................... 54
PART III
10. Directors and Executive Officers of the Registrant......................... 54
11. Executive Compensation..................................................... 54
12. Security Ownership of Certain Beneficial Owners and Management............. 54
13. Certain Relationships and Related Transactions............................. 54
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............ 55
Signatures................................................................. 60
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GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
ABBREVIATIONS,
ACRONYMS, OR DEFINED TERMS TERMS
-------------------------- -----
Amoco........................................ Amoco Production Company
APB.......................................... Accounting Principles Board Opinion
Bcf.......................................... Billion cubic feet
Bcf/d........................................ Billion cubic feet per day
Board........................................ Board of directors of El Paso Natural Gas
Company
BR........................................... Burlington Resources Inc.
CAAA......................................... Clean Air Act Amendments of 1990
CFE.......................................... Comision Federal de Electricidad, the Mexican
government-owned electric utility
Company...................................... El Paso Natural Gas Company and its
subsidiaries
Court of Appeals............................. United States Court of Appeals for the
District of Columbia Circuit
CPUC......................................... California Public Utilities Commission
Dth.......................................... Decatherm
Eastex....................................... Eastex Energy Inc., a wholly owned subsidiary
of El Paso Natural Gas Company
EIS/EIR...................................... Environmental Impact Statement/Environmental
Impact Report
EPA.......................................... United States Environmental Protection Agency
EPED......................................... El Paso Energy Development Company, a wholly
owned subsidiary of El Paso Natural Gas
Company
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
EPGM......................................... El Paso Gas Marketing Company, a wholly owned
subsidiary of El Paso Natural Gas Company
EPNC......................................... El Paso New Chaco Company, a wholly owned
subsidiary of El Paso Natural Gas Company
FERC......................................... Federal Energy Regulatory Commission
Holding Company.............................. A new Delaware corporation, which is proposed
to be formed to become the holding company
parent of the Company
ICA.......................................... Empresas ICA Sociedad Controladora, S.A. de
C.V.
IRS.......................................... Internal Revenue Service
Merger....................................... Proposed merger of El Paso Natural Gas
Company with a direct subsidiary of Holding
Company to implement the reorganization of
the Company into a holding company structure
MFV.......................................... Modified Fixed Variable
MMbtu........................................ Million British thermal units
MMcf/d....................................... Million cubic feet per day
MPC.......................................... Mojave Pipeline Company, a wholly owned
subsidiary of El Paso Natural Gas Company
MPOC......................................... Mojave Pipeline Operating Company, a wholly
owned subsidiary of Mojave Pipeline Company
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ABBREVIATIONS,
ACRONYMS, OR DEFINED TERMS TERMS
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MSG.......................................... Merchant Services Group, comprised of Eastex
Energy Inc. and subsidiaries, and El Paso Gas
Marketing Company
NGL.......................................... Natural gas liquids
NOx.......................................... Nitrogen oxides
NYMEX........................................ New York Mercantile Exchange
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
OPEB......................................... Other Postretirement Employee Benefits
OTC.......................................... Over-The-Counter
PCB.......................................... Polychlorinated biphenyl
PG&E......................................... Pacific Gas & Electric Company
Plan......................................... Dividend Reinvestment and Common Stock
Purchase Plan
Premier...................................... Premier Gas Company, a wholly owned
subsidiary of Eastex Energy Inc.
Program...................................... Continuous Odd-Lot Stock Sales Program
PRP(s)....................................... Potentially Responsible Party(ies)
Restructuring Rules.......................... A series of orders directing a number of
significant changes to the structure of the
services provided by interstate natural gas
pipelines
RI/FS........................................ Remedial Investigation/Feasibility Study
SAR(s)....................................... Stock Appreciation Right(s)
SEC.......................................... Securities and Exchange Commission
SFAS......................................... Statement of Financial Accounting Standards
SFV.......................................... Straight Fixed Variable
SoCal........................................ Southern California Gas Company
SOP.......................................... Statement of Position
Tcf.......................................... Trillion cubic feet
TEPCO........................................ The El Paso Company, formerly the parent
company of El Paso Natural Gas Company
Transwestern................................. Transwestern Pipeline Company
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
EL PASO NATURAL GAS COMPANY
Business
EPG, incorporated in Delaware in 1928, owns and operates one of the
nation's largest mainline natural gas transmission and gathering systems,
connecting natural gas supply regions in New Mexico, Texas, Oklahoma, and
Colorado to markets in California, Nevada, Arizona, New Mexico, Texas, and
northern Mexico. At December 31, 1991, EPG was a wholly owned subsidiary of BR.
In March 1992, EPG completed an initial public offering of approximately 15
percent of its common stock in the form of newly issued shares. In June 1992, BR
distributed all of the EPG common shares it held to BR shareholders, the effect
of which was to place all of EPG's common stock in public ownership.
EPG's natural gas transmission system consists of approximately 17,000
miles of pipeline. In 1995, EPG transported 1.3 Tcf of gas, equivalent to
roughly 6 percent of the nation's total gas consumption. California is the
largest single market served by EPG and is the second largest natural gas market
in the nation. EPG is also the primary transporter to the growing
East-of-California markets in Arizona (particularly Phoenix and Tucson); Las
Vegas, Nevada; New Mexico; and El Paso, Texas.
EPG's natural gas transmission 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. Since 1992, production of gas from the San Juan Basin has
more than doubled. EPG added 1 Bcf/d of capacity out of the San Juan Basin
between December 1991 and April 1992. In December 1995, EPG added an additional
300 MMcf/d of new capacity which brought its total capacity out of the San Juan
Basin to 2.9 Bcf/d. The expansion virtually eliminated the capacity constraints
on EPG's San Juan Triangle facilities that were experienced during 1995. The
dramatic growth of production in the San Juan Basin, combined with the decrease
in demand for San Juan Basin supplies in California, has caused San Juan Basin
producers to seek new markets off the east end of EPG's natural gas transmission
system. EPG has been accommodating such off-system demand through displacement
transportation, as well as through the redirection of gas flow over a
bi-directional portion of the pipeline. In addition to having access to
substantial gas supplies, EPG is uniquely positioned to serve developing markets
along the northern border of Mexico including Ciudad Juarez, Cananea, and
Hermosillo.
In addition to its own pipeline operations, the Company has a one-third
interest in the TransColorado Gas Transmission Company. For a further discussion
see Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Regulatory Environment
EPG's pipeline facilities, services, and rates are regulated by FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. The primary change in EPG's operating environment is due to FERC's
increasing reliance on market forces as a substitute for cost-of-service
regulation. This change in policy has allowed the construction of significant
excess pipeline capacity into California.
In the mid-1980's, FERC began a series of actions designed to replace
strict cost-of-service regulation with market forces. The first significant
change was to eliminate a pipeline's obligation to hold supply and to allow
shippers to transport their own gas across an interstate pipeline system rather
than depend on the pipeline's merchant function. One of the obstacles to this
transition was the renegotiation of gas purchase contracts between pipelines and
producers. These negotiations reduced the pipeline's purchase obligations,
reformed the contract pricing provisions, and/or settled take-or-pay claims. EPG
has completed the renegotiation of its purchase contracts and expects no further
significant liability in this area. For a further
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discussion of EPG's take-or-pay matters see, Note 5 of Item 8, Financial
Statements and Supplementary Data.
The second effort, which began in April 1992, was a series of orders
commonly known as the Restructuring Rules. These rules mandated significant
changes to the structure of the services provided by interstate natural gas
pipelines and were intended principally to assure "comparability" (i.e., that
pipeline and non-pipeline gas merchants were placed on an equal footing in
competing for sales), to provide a mechanism for the allocation of pipeline
capacity, and to eliminate competitive distortions arising from rate design
differences between United States and Canadian pipelines. The most significant
of these rules for EPG was the rate design change. Under the Restructuring Rules
SFV rate design, all fixed pipeline costs (including return on equity and
related income taxes) are recovered through reservation charges which do not
vary with actual throughput. Under the previously required MFV rate design,
return on equity and related taxes were excluded from reservation charges but
were recovered along with variable costs through volumetric rates (rates
collected based on the actual volumes transported on the pipeline). Generally,
under SFV rate design, volumetric rates are considerably lower than under MFV
rate design and pipeline earnings are less sensitive to variations in actual
throughput; however, as discussed in the following sections, it is anticipated
that EPG's future rates will be more sensitive to pipeline throughput.
California Markets
EPG maintains a strong 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. EPG currently delivers about 48 percent
of the total interstate pipeline capacity serving that state. In addition, gas
shipped to California across the EPG system represented about 36 percent of the
gas consumed in the state in 1995.
Interstate pipeline capacity utilization to California is currently about
65 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 89 percent of its 3.3 Bcf/d of capacity
to California. By 1998, that figure has the potential to drop to approximately
53 percent. EPG's largest contracts for interstate capacity to California are
with SoCal and PG&E. Both SoCal and PG&E have exercised options in their
contracts 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 is seeking to offset the effects of these and other future reductions
in existing firm capacity commitments by actively seeking new markets, pursuing
attractive opportunities to increase traditional market share, and controlling
costs.(1) The new markets EPG has targeted include various natural gas users in
California who are now served 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.
East-of-California Markets
EPG's current delivery capacity to East-of-California markets is
approximately 1.3 Bcf/d. EPG is the principal interstate natural gas
transmission system serving Arizona, including the cities of Phoenix and Tucson;
southern Nevada, including Las Vegas; New Mexico; and El Paso, Texas. EPG also
serves the cities of Ciudad Juarez, Cananea, and Hermosillo in northern Mexico.
In addition, EPG has filed an application with FERC to expand its system in
order to provide natural gas service to the proposed Samalayuca II Power Plant
near Ciudad Juarez. For a further discussion of the Samalayuca II Power Plant,
see Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations.
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(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the
important factors that may affect actual results.
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Markets off the East End of EPG's System
Since the late 1980's, in response to changing market demands, EPG has been
delivering substantial quantities of gas from the San Juan, Permian, and
Anadarko Basins to interconnecting pipelines for re-delivery to off-system
markets on the Gulf Coast and in the Midwest.
The alternate routing of the San Juan Basin gas was originally effectuated
by back-hauls between EPG's system and an interconnecting pipeline. Volumes of
gas, which the interconnecting pipeline is otherwise scheduled to deliver to EPG
for re-delivery in EPG's traditional markets, are traded for like volumes of San
Juan Basin gas which EPG has accepted for delivery to the interconnecting
pipeline. With EPG's 1992 completion of a system modification, which made an
existing pipeline segment linking the San Juan Basin and Permian Basin
bi-directional, physical forward-haul deliveries are also being made.
Permian Basin and Anadarko Basin gas is delivered to these new markets both
by displacement and through forward-haul transactions. A segment of pipeline in
the Texas panhandle that has been modified to allow for re-directed gas flow
allows EPG to physically transport San Juan Basin or Permian Basin gas to
delivery points in the Anadarko Basin. New interconnects were constructed with
NorAm Gas Transmission Company and TransOK Inc. to exploit this additional
capability. Similarly, a segment of pipeline between the Cornudas and Waha
stations in Texas has been modified to allow for additional capacity to move gas
to the Texas intrastate pipelines in the Permian Basin. As a result of these
system modifications, total deliveries to off-system markets east of EPG's
system were as high as 1.5 Bcf/d during 1995.
Although the contributions to revenues and earnings are still comparatively
small, off-system deliveries represent a strategic long-term diversification of
EPG's market base. Presently, EPG is the largest provider of access to
off-system markets for San Juan Basin producers. To maintain this position,
during 1995 EPG constructed a new interconnect with Transwestern near Window
Rock, Arizona that allows EPG to move an additional 300 MMcf/d of San Juan Basin
gas to Transwestern for re-delivery to these new markets.
In addition, based on the results of an "open season" which concluded on
February 29, 1996, EPG believes that sufficient market demand exists to support
the addition of new capacity to move additional San Juan Basin gas to east end
markets. For a further discussion of EPG's proposed expansion, see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
Summary of Historical Throughput
Set forth below is a breakdown of EPG's natural gas deliveries by market
area for the years ended December 31:
1995 1994 1993
----- ----- -----
(MMCF/D)
California.................................................. 1,791 2,257 2,288
East-of-California.......................................... 550 630 599
Off-system.................................................. 1,103 747 691
----- ----- -----
Total Throughput.................................. 3,444 3,634 3,578
===== ===== =====
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Competition
EPG faces significant competition from three other companies which
transport natural gas to the California market. Competition generally occurs on
the basis of delivered price. The combined capacity of the four pipelines
transporting natural gas to the California market is 6.9 Bcf/d. In 1995, the
demand for interstate pipeline capacity to California averaged 5.0 Bcf/d. EPG's
California competitors can be summarized as follows:
Transwestern -- has the capacity to deliver approximately 1.1 Bcf/d to
California from Permian, Anadarko, and San Juan Basin supply sources.
Kern River Gas Transmission -- has the capacity to deliver approximately
700 MMcf/d to California from Rocky Mountain supply sources. In 1992, Kern River
Gas Transmission applied to FERC for permission to expand its system capacity by
452 MMcf/d and held an open season to solicit market support for that effort.
Market demand will determine whether or not the project will be built.
Pacific Gas Transmission Company -- has the capacity to deliver
approximately 1.8 Bcf/d to California from Canadian gas supply sources after
completion, in November 1993, of its 755 MMcf/d expansion. This project was
supported by Canadian marketers and producers seeking a new market for their
supplies. While the impact of the expansion project on EPG's operating revenues
was minimal in 1994 due to an overall increase in demand for natural gas in the
California market, which occurred due to a decrease in the availability of
hydroelectric power, the impact of the expansion project on EPG's operating
revenues has been more significant in 1995. See Item 7, Management's Discussion
and Analysis of Financial Condition and Results of Operations.
EPG 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, which
both the CPUC and FERC are supporting, 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, EPG is not projecting a significant increase in gas demand as a result of
such restructuring, particularly in the California market.
Future Outlook
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 which occur
from January 1, 1996, through December 31, 1997. For a further discussion of the
settlement, see Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations.
This settlement would mitigate the revenue reductions expected as a
consequence of the various contract demand step-downs and the PG&E contract
termination at year-end 1997.
MOJAVE PIPELINE COMPANY
Business
On June 1, 1993, the Company acquired from a wholly owned subsidiary of
Enron Corp., that subsidiary's 50 percent interest in MPC, a general
partnership. This acquisition gave the Company 100 percent ownership of MPC. MPC
is a general partnership formed pursuant to the Uniform Partnership Act of the
State of Texas
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for the purpose of constructing, owning, and operating a federally regulated
interstate natural gas pipeline to serve the enhanced oil recovery operations
and associated cogeneration projects in the heavy oil fields in central
California. MPOC, a wholly owned subsidiary of MPC, is a Texas corporation,
which serves as MPC's agent in the management of MPC's pipeline facilities and
the design and construction of future MPC pipeline expansions.
MPC's pipeline facilities, services, and rates are regulated by FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. MPC's system connects at Topock, Arizona with EPG's and Transwestern's
interstate pipeline systems. MPC's only business is natural gas transportation
and related hub services.
Set forth below are MPC's natural gas deliveries for the years ended
December 31:
1995 1994 1993
---- ---- ----
(MMCF/D)
Total MPC Throughput............................................ 328 247 231
=== === ===
Regulatory Environment
MPC filed a service and rate design restructuring plan in November 1992
which was essentially approved by FERC in March 1993. Several of MPC's customers
have filed petitions with the Court of Appeals for review of the March 1993
order and certain other FERC orders. These petitions are currently pending
before the Court of Appeals. The primary issues on appeal pertain to FERC's
requirement that MPC's rates for firm transportation service be based upon SFV
rate design rather than MFV rate design. Management believes the Court of
Appeals will uphold SFV rates as applied to MPC.(1)
In February 1995, MPC made a filing with FERC seeking authorization to
maintain its existing rates. In March 1995, FERC accepted the filing and allowed
the rates to become effective as of March 30, 1995, subject to refund. In
September 1995, MPC filed a settlement agreement supported by FERC and the
majority of MPC's firm shippers which would continue rates at existing levels
for a 5-year period. In December 1995, FERC approved the settlement agreement as
it relates to the supporting parties. Contested issues applicable solely to the
minority customer group not supporting the settlement will be resolved following
a hearing before FERC.
System Expansion
In March 1993, MPC filed an application, which was amended in November 1993
and April 1994, for a certificate of public convenience and necessity to build
and operate a 475 MMcf/d expansion of its existing system. The proposed
expansion was estimated to cost approximately $500 million. For a further
discussion of the proposed expansion see Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations.
EL PASO FIELD SERVICES COMPANY
Business
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. In January 1994 and in May 1995, EPG filed
applications with FERC seeking orders that would terminate, effective January 1,
1996, certificates applicable to certain gathering and processing facilities
owned by EPG on the basis that such facilities are not subject to FERC
jurisdiction. In September 1995, FERC granted the abandonments requested in the
applications, subject to certain conditions, and determined that the facilities
would be exempt from FERC jurisdiction upon transfer to EPFS. In November 1995,
FERC denied rehearing petitions on the
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(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
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September 1995 order. Certain parties have filed petitions for review of the
September 1995 and November 1995 FERC orders with the United States Court of
Appeals for the Fifth Circuit.
Effective January 1, 1996, EPG transferred to EPFS the gathering and
processing facilities which were subject to the January 1994 and May 1995 orders
together with its non-certificated gathering facilities. The following table
provides information concerning the gathering and processing facilities at
January 1, 1996:
GAS PRODUCTS
MILES OF INSTALLED GATHERING EXTRACTION
SYSTEM PIPELINE HORSEPOWER CAPACITY CAPACITY
------ -------- ---------- --------- ----------
(MMCF/D)
San Juan Basin............................... 5,500 42,721 1,180 590(a)
Anadarko Basin............................... 667 11,705 425 --
Permian Basin
Carlsbad................................... 800 6,144 150 8
Waha....................................... 160 3,609 250 --
----- ------ ----- ---
Total.............................. 7,127 64,179 2,005 598
===== ====== ===== ===
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(a) This capacity represents the existing lean oil processing plant which will
be partially replaced by the completion of the 600 MMcf/d cryogenic plant
discussed below. EPFS will retain approximately 325 MMcf/d of lean oil
processing capacity.
EPFS focuses on providing its customers innovative, reliable, competitively
priced wellhead-to-mainline field services including gathering, products
extraction, dehydration, purification, and compression. With the formation of
MSG, EPFS is able to offer its customers fully bundled natural gas services with
a broad range of pricing options including innovative financial risk management
products. EPFS also provides well tie-ins and state-of-the-art, cost effective,
near real-time information services including electronic wellhead gas flow
measurement.
EPFS provides services on a variety of fee structures including fixed fee
per Dth, floating fee per Dth indexed to the applicable local area price of gas,
or by taking NGL in kind. EPFS's leverage to gas and liquid prices increased in
1995 as a result of the completion of numerous long-term gathering, processing,
and compression contracts for services in the San Juan Basin. These contracts
represent approximately 77 percent of EPFS's San Juan Basin throughput which
totaled 1,012 MMcf/d in 1995 and include dedication of gas production and
drilling acreage with gathering fees indexed to the San Juan Basin price of gas,
and product extraction fees based on a percentage of NGL extracted. The Company
believes that low California gas demand, excess interstate pipeline capacity to
California, continued increases in gas supply availability, and pipeline
constraints to move gas to eastern markets were significant factors that caused
San Juan Basin gas prices to average $1.18 in 1995, the lowest in over 7 years.
EPFS believes it is well positioned to benefit from upswings in gas and NGL
prices. In January and February of 1996, EPFS implemented a hedging strategy
through MSG. This strategy retains upside potential for gas and NGL indexed fees
while mitigating the financial impact should lower gas or NGL prices occur
during 1996.
In 1995 EPFS's gathering throughput was depressed due in large part to low
gas prices, which dampened overall drilling and workover activity, and to
pipeline curtailments on EPG's mainline. The pipeline curtailments resulted from
mainline capacity constraints in the San Juan Basin. In late 1995, EPG
eliminated the constraints by expanding San Juan Basin mainline capacity by 300
MMcf/d and putting into service a 300 MMcf/d interconnect with Transwestern. As
a result, pipeline curtailments in the San Juan Basin are not expected to
negatively impact gathering throughput in 1996.
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Set forth below are the gathered and products extraction volumes for the
years ended December 31:
1995 1994 1993
----- ----- -----
(MMCF/D)
Gathered Volumes............................................ 1,284 1,314 1,304
===== ===== =====
Products Extraction Volumes................................. 436 458 446
===== ===== =====
EPFS plans to increase gathering and processing volumes and profits through
a strategy of project development, acquisitions, and joint ventures.(1) EPFS's
strategies are focused on increasing its ability to offer gathering and
processing services in its traditional services areas, as well as in other
active gas producing areas. EPFS has made significant progress in implementing
these strategies. In September 1995, EPFS acquired the Burton Flats cryogenic
products extraction plant from Amoco for approximately $5.6 million. The plant
and related 14 mile gathering system has a capacity of 7.5 MMcf/d and at year
end 1995 had throughput of about 6.0 MMcf/d. The Burton Flats plant and
gathering system is located in Eddy County, New Mexico and is adjacent to EPFS's
Carlsbad gathering system. This facility will enable EPFS to offer products
extraction services to its existing customers in the Carlsbad gathering system,
as well as to new gas suppliers.
The Hart Canyon compression project was completed in November 1995 and
consists of three field compressor sites with combined horsepower of 7,675 and
loops several sections of gathering lines in the San Juan Basin. The effect of
this project has been to lower gathering line pressures from an average of 280
pounds per square inch gauge to 120 pounds per square inch gauge resulting in
increased production of up to 20 MMcf/d from approximately 280 wells connected
to the system. EPFS charges a compression fee on approximately 80 MMcf/d
compressed by this new horsepower. EPFS believes that similar compression
projects throughout its system hold significant potential as a new revenue
source for EPFS in the future.(1)
In February 1996, EPFS, through its wholly owned subsidiary El Paso
Intrastate Company, acquired the Linc and Pandale gathering systems from Tejas
Power Corporation. For a further discussion of the gathering systems see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
EPFS is constructing a new 600 MMcf/d cryogenic gas processing plant at its
existing Chaco Plant facility which is expected to cost approximately $80
million. The first 400 MMcf/d of capacity at the Chaco Plant facility is
scheduled to be in service during the first quarter of 1996, with the remaining
200 MMcf/d of capacity expected to be available in the second quarter of 1996.
The efficiency of the plant's high natural gas liquids extraction capability of
50,000 barrels of NGL per day is expected to increase the profitability to the
customers of EPFS, thereby increasing the profit contribution of EPFS's NGL
processing activities. For information on the lease for the plant, which is
unconditionally guaranteed by EPG, see Note 5 of Item 8, Financial Statements
and Supplementary Data.
Competition
EPFS operates in a highly competitive environment that includes independent
gathering and processing companies, interstate and intrastate pipeline
companies, gas marketers, and oil and gas producers. EPFS competes for
throughput primarily based on price, efficiency of facilities, gathering system
line pressures, availability of facilities near drilling activity, service, and
access to favorable downstream markets.
Future Outlook
EPFS is the primary vehicle by which EPG plans to grow its non-regulated
domestic natural gas gathering and processing business. EPFS expects to increase
the profitability of its existing business through aggressive cost control and
expand by adding to its current service offerings through synergies with MSG.(1)
To accelerate that process EPFS will relocate its headquarters to Houston, Texas
during the second quarter of
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
7
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1996. Furthermore, aided by the free cash flow generated by EPG, EPFS plans to
aggressively pursue growth opportunities through acquisition and development of
assets in and outside of its current service area.(1)
MERCHANT SERVICES GROUP
Business
The Company significantly increased its non-regulated natural gas activity
in 1995 through the formation of MSG which consists of Eastex, its subsidiaries,
and EPGM. EPGM was incorporated and commenced operations in late 1992 for the
purpose of conducting all of EPG's new gas marketing business, while also acting
as EPG's agent in winding down its remaining role as a natural gas merchant
predominately in the southwestern region of the United States. Due to the
emerging market for natural gas sales and services in recent years and the
Company's emphasis on developing its non-regulated business, the Company sought
to expand the size and geographical scope of its gas marketing activities to
become a national gas merchant through the acquisition of Eastex, effective
September 1, 1995.
Eastex is a full service natural gas merchant which conducts wholesale gas
marketing and related services on a national basis. To complement its business,
Eastex offers storage and hub services at its Rotherwood Storage Field and
Houston Hub pipeline facility, located in Texas, and direct end user sales in
the eastern United States, principally through Heath Petra Resources, a wholly
owned subsidiary of Eastex. Subsequent to the acquisition by EPG, the operations
of Eastex and EPGM were integrated. On December 7, 1995, Eastex purchased all of
the outstanding stock of Premier, a gas marketing company located in Tulsa,
Oklahoma, specializing in long-term sales to utilities in the Great Lakes region
and industrial and commercial sales to end users in the Mid-continent region.
The consolidation of these regional gas marketing entities into MSG, with
headquarters in Houston, Texas and sales offices throughout the United States,
has created one of the industry's leading natural gas services providers with
year end 1995 sales level exceeding 2 Bcf/d. MSG provides a broad range of
energy products and services to its customers including supply aggregation,
transportation management, integrated price risk management, and storage
inventory optimization services. Due to the emerging deregulation of the
electric power industry, MSG recently formed a power marketing subsidiary to
participate in wholesale power trading and to offer similar products and
services to industrial and commercial end users of electricity.
MSG 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 1995,
MSG served approximately 325 producer/suppliers and 692 sales customers in 37
states with transportation of gas supplies on 45 pipelines.
Set forth below are marketed gas volumes for the years ended December 31:
1995 1994(A) 1993(A)
---- ------- -------
(MMCF/D)
Marketed Gas Volumes....................................... 750 345 362
=== === ===
- ---------------
(a) Volumes represent EPGM activity only.
Demand for natural gas products and services has primarily resulted from
the deregulation effects of FERC Order 636, the commercialization of natural
gas, and the intense gas-to-gas competition within the industry. Volatility in
the physical and financial gas markets has compounded the effects of these
changes creating greater service opportunities. MSG's marketing strategy is to
focus on customer driven solutions for fully bundled natural gas services
through its capability to provide reliable physical deliveries and innovative
financial risk management products. MSG expects to benefit from a lower cost
structure through the consolidation of operations, price competitive supplies
due to its expanded nationwide scope, lower credit costs
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
8
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due to the financial strength of its parent, and new customers and business
opportunities through its relationships with EPFS and EPED.(1)
In the course of its business, MSG 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 gas merchants. MSG seeks to maintain a
balanced portfolio of supply and demand contracts and utilizes the NYMEX and OTC
financial markets to hedge against price and basis risk which may affect those
obligations. To support these activities, MSG employs centralized corporate risk
management and hedging strategies. See Note 4 of Item 8, Financial Statements
and Supplementary Data.
Competition
MSG's 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 natural gas marketers with varying scopes of
operations and financial resources. To effectively compete, MSG must expand
existing customer relationships as market conditions change, develop new
customers in emerging markets, and remain a low cost provider of a broad array
of natural gas and other energy related services.
Future Outlook
MSG believes there is opportunity for significant growth from its gas
marketing activities and expansion into related business lines such as power
marketing, producer settlement services, small end user sales, and demand side
management. Average daily volumes for 1996 are projected to be over 2.5 Bcf/d.
Further, MSG is expected to add value to EPG through its earnings contributions,
from synergies with the Company's natural gas transmission business, and by
benefiting EPFS through greater producer services and expanded gathering and
processing opportunities.(1) As the deregulation of the electric power industry
and the expansion of business opportunities in Mexico and Latin America
continues, MSG will seek opportunities to work with EPED in the joint
development of natural gas and energy related projects.
EL PASO ENERGY DEVELOPMENT
Business
EPED was incorporated in June 1991 for the purpose of investing in energy
projects with an emphasis on projects involving the development of
infrastructure to gather, transport, and utilize natural gas in northern Mexico
and Latin America. EPED is especially interested in those projects in northern
Mexico that present opportunities to utilize EPG's existing mainline
transmission system. EPED invests in projects outside of the United States which
possess a higher potential rate of return, as well as a higher degree of risk,
than similar projects in the United States.
Future Outlook
Currently, EPED is actively working on two projects: the Samalayuca II
Power Plant and the Aguaytia Energy Project and is evaluating several other
projects. For a further discussion of the current projects see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
GAS SUPPLY
During 1995, approximately 188 wells first delivered gas into the Company's
system. The total gas well availability physically connected to the Company's
gathering systems was approximately 1.4 Bcf/d, with total reserves estimated at
11.2 Tcf. During 1995, an average of 2.8 Bcf/d was received from physical points
interconnected with other pipelines or from receipt points pursuant to
transportation and exchange
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
9
14
agreements. EPG's maximum mainline system capacity is 4.7 Bcf, and MPC's
designed mainline system capacity is 400 MMcf/d.
SIGNIFICANT CUSTOMERS
In 1995, natural gas deliveries to SoCal and PG&E accounted for 17 percent
and 12 percent, respectively, of the Company's consolidated operating revenues.
No other customer accounted for 10 percent or more of the Company's consolidated
operating revenues.
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, 1995, EPG had a reserve of
approximately $35 million to cover these remediation activities. EPG estimates
that it will have capital expenditures for environmental matters of
approximately $10 million from 1996 through 2005. EPG has spent approximately
$33 million through 1995 for remediation projects of a capital nature. Details
regarding specific environmental contingencies are presented in Note 5 of Item
8, Financial Statements and Supplementary Data.
ENCUMBRANCES
Substantial portions of the Company's pipeline systems are constructed and
maintained pursuant to rights-of-way, easements, permits, and licenses or
consents on and across properties owned by others. Compressor stations, related
facilities, storage facilities, and two NGL extraction plants are located in
whole or in part upon land owned by the Company or upon sites held under leases
or under permits issued or approved by public authorities.
COMPANY RESTRUCTURING
In response to changes in the natural gas industry, increased competition,
recent and future firm capacity contract step-downs and terminations, the
Company has initiated an extensive review of its business processes. As a result
of this review, the Company has adopted a program to restructure its businesses
and reduce operating costs through work force reductions and improved work
processes.
In addition, the Company intends to realign itself into a holding company
structure. For a further discussion of the company restructuring and holding
company structure see Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations.
EMPLOYEES
The Company had 2,393 and 2,403 full-time employees on December 31, 1995,
and 1994, respectively. The Company has no collective bargaining arrangements.
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15
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPG as of February 29, 1996, were as follows:
OFFICER
NAME OFFICE SINCE AGE
---- ------ ------- ---
William A. Wise Chairman of the Board, President, and 1983 50
Chief Executive Officer
H. Brent Austin Executive Vice President and Chief 1992 41
Financial Officer
Richard Owen Baish Executive Vice President 1987 49
Michael C. Holland Senior Vice President 1982 54
Robert G. Phillips Senior Vice President 1995 41
Joel Richards III Senior Vice President 1990 49
John W. Somerhalder II Senior Vice President 1990 40
Larry R. Tarver Senior Vice President 1988 52
Britton White, Jr. Senior Vice President and General 1991 52
Counsel
Mr. Wise has been Chairman of the Board of EPG since January 1994. He has
been Chief Executive Officer since January 1990 and President since April 1989.
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. 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. Baish has been Executive Vice President of EPG since September 1994. He
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. Holland has been Senior Vice President of EPG since January 1991. He
was a Vice President from June 1982 to December 1990. He has also been President
and Chief Executive Officer of MPOC since October 1989. Mr. Holland has
announced his intention to retire in 1996.
Mr. Phillips has been Senior Vice President of EPG since September 1995. He
has been Chief Executive Officer of Eastex since March 1983.
Mr. Richards has been Senior Vice President of EPG since January 1991. 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. Somerhalder has been Senior Vice President of EPG since August 1992. He
was Vice President from January 1990 to July 1992.
Mr. Tarver has been Senior Vice President of EPG since September 1994. He
was Vice President from December 1988 to August 1994. Mr. Tarver has announced
his intention to retire in 1996.
Mr. White has been Senior Vice President and General Counsel of EPG since
March 1991. 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.
11
16
Luino Dell'Osso, Jr. retired in May 1995 as Vice-Chairman, Chief Operating
Officer, and a Director of EPG after 22 years of service with EPG, BR, and
Burlington Northern Inc.
Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
ITEM 3. LEGAL PROCEEDINGS
In November 1993, TransAmerican Natural Gas Corporation filed a complaint
in a Texas state court against various parties, including EPG, 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 Natural Gas Corporation 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, and the parties have stipulated to transfer this case to
the State District Court of Dallas County, Texas. Based on information available
at this time, management believes that the claims made by TransAmerican Natural
Gas Corporation have no factual or legal basis and that the ultimate resolution
of this matter will not have a materially adverse effect on the Company's
financial condition.
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
condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1995 no matters were submitted to a vote of
security holders.
12
17
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
29, 1996, the approximate number of holders of record of common stock was
19,843. 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, and cash
dividends declared on, EPG's common stock based on the daily composite listing
of stock transactions for the New York Stock Exchange.
HIGH LOW DIVIDENDS
------- ------- ---------
(PER SHARE)
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
1994
First Quarter............................... $41.875 $35.250 $0.3025
Second Quarter.............................. $39.000 $31.500 $0.3025
Third Quarter............................... $35.375 $31.625 $0.3025
Fourth Quarter.............................. $34.750 $29.875 $0.3025
In January 1996, the Board declared a quarterly dividend of $0.3475 per
share on EPG's common stock, payable on April 1, 1996, to shareholders of record
on March 8, 1996. The declaration of future dividends will be dependent upon
business conditions, earnings, the cash requirements of EPG, and other relevant
factors.
EPG has made available the Program, in which Odd-lot Holders are offered a
convenient method of disposing of all their shares without incurring the
customary 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 shareholders of record
a convenient and economical means of increasing their holdings in EPG's common
stock. A shareholder 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 shareholder's name. The Plan is
strictly voluntary, and no shareholder of record is obligated to participate in
the Plan. A brochure and related materials describing the Plan were sent to
shareholders 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,
--------------------------------------------------------------
1995 1994 1993(E) 1992 1991
--------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNTS)
OPERATING RESULTS
Operating revenues.............. $1,037,997 $869,872 $908,928 $802,812 $735,196
Depreciation, depletion, and
amortization................. 72,077 65,037 54,051 73,229 61,300
Litigation special charge(a).... -- 15,062 -- -- --
Operating income................ 212,411 222,295 229,245 184,910 184,919
Income from continuing
operations before income
taxes........................ 132,976 148,076 150,826 123,289 140,500
Income taxes.................... 47,613 58,463 59,153 46,963 51,956
Income from continuing
operations................... 85,363 89,613 91,673 76,326 88,544
Earnings per common share --
continuing operations........ 2.47 2.45 2.46 2.12 2.82
Cash dividends declared per
common share(b).............. 1.32 1.21 1.10 0.75 --
Average common shares
outstanding.................. 34,495 36,632 37,212 36,049 31,422
DECEMBER 31,
------------------------------------------------------------------
1995 1994 1993(E) 1992 1991
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
FINANCIAL POSITION
Total assets................... $2,434,625 $2,331,771 $2,269,663 $2,050,729 $2,301,932
Payable to BR, including
current portion............. -- -- -- -- 624,804
Long-term debt(c).............. 771,892 779,097 795,783 637,074 249,942
Stockholders' equity(d)........ 712,155 709,636 707,548 668,992 814,878
- ------------
(a) Charge related to the Amoco litigation (see Item 7, Management's Discussion
and Analysis of Financial Condition and Results of Operations). The
settlement payment was made in the first quarter of 1995.
(b) Represents dividends declared subsequent to the Company's March 1992
initial public offering.
(c ) Excludes current maturities.
(d) In May 1991, EPG declared and paid a dividend of $175 million to TEPCO. In
September 1991, EPG declared a dividend of all its Oil and Gas Operations
Segment to TEPCO. The total amount of that dividend was $925 million. In
addition, EPG declared and paid dividends to BR totaling $55 million in
1991 and $274 million prior to the Company's March 1992 initial public
offering.
(e) MPC was consolidated for May 1993 through December 1993.
14
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Year Ended December 31, 1995, Compared to Year Ended December 31, 1994
Operating revenues for the year ended December 31, 1995, were $168 million
higher than for the same period of 1994. The consolidation of Eastex and net
reserve reversals contributed $257 million and $12 million to the increase,
respectively. Higher gathering and processing rates and return on take-or-pay
receivables of $3 million, and $2 million, respectively, also contributed to the
increase. Partially offsetting the increase in operating revenues were lower gas
sales volumes, gas sales rates, transportation rates, transportation volumes,
gathering and processing volumes, and reservation revenues of $46 million, $33
million, $10 million, $6 million, $2 million, and $3 million, respectively.
Operating charges for the year ended December 31, 1995, were $178 million
higher than for the same period of 1994. The consolidation of Eastex, increases
in operation and maintenance expense, and depreciation contributed $247 million,
$16 million, and $7 million, respectively, to the increase in operating charges.
The increase in operation and maintenance expense was due primarily to higher
stock related benefits, higher consultant fees, and higher severance accruals.
Offsetting the increase in operating charges were lower gas purchase volumes,
lower average cost of gas, a 1994 litigation special charge, and net reserve
reversals of $48 million, $29 million, $15 million, and $5 million,
respectively.
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 $2 million higher for the
year ended December 31, 1995, than for the same period of 1994 due primarily to
an increase in the average construction work in progress balance.
EPG's mainline throughput for the year ended December 31, 1995, was 1,257
Bcf compared to 1,326 Bcf for the same period of 1994. The lower throughput was
primarily due to a decrease in deliveries to the California market resulting
from an increase in the availability of hydroelectric power. The decrease in
California deliveries was partially offset by higher off-system deliveries,
resulting from producers and marketers seeking alternative markets for their
gas.
Year Ended December 31, 1994, Compared to Year Ended December 31, 1993
Operating revenues for the year ended December 31, 1994, were $39 million
lower than for the same period of 1993. New system rates that became effective
January 1, 1994, resulted in lower reservation revenues of $28 million and lower
transportation revenues of $28 million. Additionally, lower gas sales rates,
lower gas sales volumes, and the 1993 sale of gas in storage contributed $25
million, $12 million, and $18 million, respectively, to the decrease to
operating revenues. The decrease due to the 1993 sale of gas in storage is
offset in operating charges. Lower accruals for regulatory issues, the
consolidation of MPC, and higher rates for gathering and processing offset the
decrease in operating revenues by $41 million, $18 million, and $15 million,
respectively.
Operating charges were $32 million lower for the year ended December 31,
1994, than for the same period of 1993. Lower gas purchase volumes and the 1993
sale of gas in storage contributed $11 million and $18 million, respectively, to
the decrease in operating charges. The decrease due to the 1993 sale of gas in
storage is offset in operating revenues. Additionally, operation and maintenance
expense decreased primarily due to a 1993 accrual for estimated take-or-pay
undercollections, a 1993 litigation settlement, lower plant and pipeline
maintenance, 1994 adjustments to the 1993 take-or-pay undercollections accrual,
and lower environmental cleanup expenses. Offsetting the decrease in operating
charges was a litigation special charge of $15 million related to the litigation
brought by Amoco, alleging breaches of certain gas purchase, gathering
15
20
and transportation agreements. In addition, higher average cost of gas, an
increase in depreciation expense, and the consolidation of MPC further offset
the decrease in operating charges by $15 million, $8 million, and $9 million,
respectively.
Interest and debt expense for the year ended December 31, 1994, was $3
million higher than for the same period of 1993 due primarily to the
consolidation of MPC.
Allowance for funds used during construction was $5 million lower for the
year ended December 31, 1994, than for 1993 due primarily to a decrease in the
average construction work in progress balance.
Other -- net income was $13 million higher for the year ended December 31,
1994, than for the same period of 1993. Contributing to the higher other income
in 1994 were $14 million related to the recovery of EPG's investment in its
underground storage facility and lower environmental cleanup expenses. The
increase in other income was partially offset by interest expense related to the
Amoco litigation special charge of approximately $4 million, and a reduction in
partnership earnings due to the consolidation of MPC.
EPG's mainline throughput for the year ended December 31, 1994, was 1,326
Bcf compared to 1,306 Bcf for the same period of 1993. Throughput was higher due
to an increase in deliveries to off-system and East-of-California markets. The
increase in throughput was partially offset by lower deliveries to the
California market due to higher storage withdrawals and increased competition.
Gathered volumes for the year ended December 31, 1994, were relatively unchanged
compared to the same period of 1993.
LIQUIDITY, FINANCIAL POSITION, AND CAPITAL RESOURCES
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
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.
Net cash provided by operating activities was $253 million for 1994,
compared with $236 million for the same period of 1993. The increase from the
previous year was primarily due to net insurance reimbursements, lower net tax
payments, lower insurance prepayments, higher collections of EPG's investment in
its underground storage facility, and timing differences in working capital
receipts and disbursements, partially offset by lower reserves for regulatory
issues and take-or-pay refunds to customers.
Rates and Regulatory Matters
EPG -- On 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 1995 were approximately $128 million. At February 29,
1996, known reductions in existing firm capacity commitments totaled
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.(1)
The new markets EPG has targeted include various natural gas users in California
who are now served 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.
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
16
21
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 which 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 which are attributable to
unsubscribed capacity sales during the period 1996 through 2003; 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.
In January 1994, EPG filed an application with FERC seeking an order that
would terminate, effective January 1, 1996, certificates applicable to certain
gathering and processing facilities owned by EPG on the basis that such
facilities are not subject to FERC jurisdiction. In May 1995, EPG filed an
application with FERC seeking an order that would terminate, effective January
1, 1996, certificates applicable to certain offshore gathering facilities owned
by EPG on the basis that such facilities are not subject to FERC jurisdiction.
In September 1995, FERC granted the abandonments requested in the January 1994
and May 1995 applications, subject to certain conditions, and determined that
the facilities would be exempt from FERC jurisdiction upon transfer to EPFS. In
November 1995, FERC denied rehearing petitions on the September 1995 order.
Certain parties have filed petitions for review of the September 1995 and
November 1995 FERC order with the United States Court of Appeals for the Fifth
Circuit.
Effective January 1, 1996, EPG transferred to EPFS the gathering and
processing facilities which were subject to the January 1994 and May 1995 orders
together with its non-certificated gathering facilities. The net assets
transferred to EPFS totaled approximately $236 million.
EPG has filed to recover $1.1 billion of its buy-out and buy-down costs
under FERC cost recovery procedures. The collection period for such costs
extends through March 1996. Through December 31, 1995, EPG recovered
substantially all of the $1.1 billion. EPG has established a reserve, based on
throughput projections, for that portion of the receivables balance which is
unlikely to be collected over the period through March 1996. The balances of
this reserve were $1 million and $9 million at December 31, 1995, and 1994,
respectively. Under FERC procedures, take-or-pay cost recovery filings may be
challenged by pipeline customers on prudence and certain other grounds. In
October 1992, FERC issued an order resolving all but one of the outstanding
issues regarding EPG's take-or-pay proceedings. The issue unresolved by FERC
involved the claim by several customers that EPG sought to recover an excessive
amount for the value of certain production properties which were transferred to
a producer as part of a 1989 take-or-pay settlement. Following a hearing on this
issue, in June 1994, FERC affirmed a decision of an Administrative Law Judge
which found that the valuation proposed by EPG was excessive and required EPG to
refund to its customers the costs found to be ineligible for take-or-pay
recovery. In accordance with FERC decision, EPG refunded $34 million, inclusive
of interest, to its customers in September 1994. In December 1994, EPG filed a
petition with the Court of Appeals for review of FERC decision, which petition
is currently pending. In addition, certain of EPG's customers sought review of
certain aspects of the October 1992 order in the Court of Appeals. In January
1996, the Court of Appeals remanded the order to FERC with a direction to
clarify the distinction between take-or-pay buydown or buyout costs which were
ineligible for recovery and those which were imprudently incurred and,
therefore, not recoverable. FERC has not yet taken action on the Court of
Appeals remand.
17
22
MPC -- MPC filed a service and rate design restructuring plan in November
1992 which was essentially approved by FERC in March 1993. Several of MPC's
customers have filed petitions with the Court of Appeals for review of the March
1993 order and certain other FERC orders. These petitions are currently pending
before the Court of Appeals. The primary issues on appeal pertain to FERC's
requirement that MPC's rates for firm transportation service be based upon SFV
rate design rather than MFV rate design. Management believes the Court of
Appeals will uphold SFV rates as applied to MPC.(1)
In February 1995, MPC made a filing with FERC seeking authorization to
maintain its existing rates. In March 1995, FERC accepted the filing and allowed
the rates to become effective as of March 30, 1995, subject to refund. In
September 1995, MPC filed a settlement agreement supported by FERC and the
majority of MPC's firm shippers which would continue rates at existing levels
for a 5-year period. In December 1995, FERC approved the settlement agreement as
it relates to the supporting parties. Contested issues applicable solely to the
minority customer group not supporting the settlement will be resolved following
a hearing before FERC.
Environmental Matters
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, 1995, the Company had a reserve of
approximately $35 million for the following environmental contingencies: (i) PCB
remediation costs estimated to range between $3 million and $4 million over the
next 4 years and (ii) remediation of groundwater and soil contamination costs
estimated to range between $30 million and $43 million over a 30-year period.
Management believes the amount reserved as of December 31, 1995, is sufficient
to cover these and other small environmental assessments and remediation
activities.(1)
EPG has analyzed the CAAA and believes the impact to the Company's
operations will be primarily in the following areas: (i) potential required
reductions in the emissions of NOx in non-attainment areas, (ii) the requirement
for air emissions permitting of existing facilities, and (iii) compliance
assurance monitoring of air emissions. EPG anticipates capitalizing the
equipment costs associated with complying with CAAA and estimates that
approximately $10 million will be spent from 1996 through 2005. However, EPA
proposed compliance assurance monitoring rules, when finalized, could
potentially impose greater costs on the Company than currently estimated.
Additionally, EPG has spent approximately $33 million through 1995 for
additional remediation projects of a capital nature. For a further discussion of
specific environmental matters see Note 5 of Item 8, Financial Statements and
Supplementary Data.
Legal Proceedings
See Item 3, Legal Proceedings.
Derivative Financial Instruments
See Note 4 of Item 8, Financial Statements and Supplementary Data for
information regarding the Company's use of derivatives and risks associated
therewith.
Acquisitions
In connection with the September 1995 acquisition of Eastex, Eastex
shareholders received either $4.50 in cash or .1601 shares of EPG common stock
for each share of Eastex common stock. The purchase price of approximately $32
million, exclusive of acquisition costs, was financed by the Company through
approximately $13 million of available cash and the issuance of approximately
0.7 million shares of treasury stock at a market value of approximately $19
million. Acquisition costs of approximately $2 million have been
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the
important factors that may affect actual results.
18
23
capitalized. Total cash consideration paid, net of cash received, was
approximately $3 million. In December 1995, Eastex acquired all of the issued
and outstanding capital stock of Premier for approximately $20 million. The
acquisition was funded by the Company through internally generated funds and
short-term borrowings. The cost of each acquisition has been allocated on the
basis of the estimated fair market value of the assets acquired and the
liabilities assumed. These allocations resulted in goodwill of approximately $17
million and $19 million related to the Eastex and Premier acquisitions,
respectively, and will be amortized over 40 years using the straight-line
method. The acquisitions have each been individually accounted for as a
purchase, and the Company has utilized the "push down" method of accounting. For
a further discussion of the Eastex and Premier acquisitions, see Note 6 of Item
8, Financial Statements and Supplementary Data.
Project Investments
Samalayuca II Power Plant (Mexico)
The Company is a member of a consortium that plans to build the proposed
Samalayuca II Power Plant near Ciudad Juarez, Chihuahua, Mexico. In December
1992, an award for construction was granted to the consortium by the CFE. The
consortium will construct the plant, which is projected to cost approximately
$645 million, and lease it to CFE for a term of 20 years. The Company presently
has a 20 percent interest in the consortium and plant and will make an initial
equity investment of approximately $26 million.
CFE and the consortium are negotiating a trust agreement, which is
substantially complete. The consortium has recently received approval for
non-recourse senior debt funding of up to 80 percent of the capital requirements
from the United States Export/Import Bank and Inter-American Development Bank.
The project is expected to reach financial close and construction is expected to
begin in the first half of 1996.(1)
Aguaytia Energy Project (Peru)
In August 1995, the Company became a member of a consortium that plans to
build a $200 million integrated gas and power project near Pucallpa, in central
Peru, called the Aguaytia Energy Project. The Company presently has a 24 percent
interest in the project, and its equity investment is estimated to be $35
million. The consortium will sell electricity, propane, and natural gas to meet
the growing demand for energy in Peru. Initially, the project will be funded 65
percent with equity. Negotiations are currently underway with a major lender to
provide non-recourse senior debt financing for 35 percent of the project during
construction and operation. Additional debt funding is anticipated. In December
1995, the project received approval from the Overseas Private Investment
Corporation for full political risk insurance coverage for the project.
Construction is expected to begin in the first half of 1996, and operations are
expected to commence in late 1997.(1)
ICA Agreement
In July 1995, the Company entered into an agreement with ICA for the joint
development, construction, operation, and ownership of natural gas pipelines and
other infrastructure projects in Mexico and Latin America. Management believes
that ICA's international engineering and construction experience, combined with
the Company's energy, natural gas marketing, and operating experience enables
the two companies to offer a uniquely qualified partnership for Latin American
development.
TransColorado Pipeline Project
In the third quarter of 1995, the Company purchased a one-third interest in
TransColorado Gas Transmission Company from Public Service Company of Colorado
for approximately $4 million. The Company paid approximately $2 million in cash.
The balance of approximately $2 million is due upon
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
19
24
commencement of the pipeline project. KN Energy, Inc. and Questar Pipeline
Company also each own a one-third interest in TransColorado Gas Transmission
Company.
In November 1994, TransColorado Gas Transmission Company received FERC
authorization to build a 292 mile pipeline with a capacity of 300 MMcf/d, from
northwest Colorado to the Blanco Hub area in the San Juan Basin. The project is
estimated to cost approximately $194 million. The proposed pipeline will provide
an alternative outlet for natural gas produced in the Rocky Mountain region and
is expected to enhance the Company's overall flexibility to meet market demands.
Construction of the proposed pipeline has not yet begun.
Common Stock and Other Stockholders' Equity
For the years ended December 31, 1995, 1994, and 1993, EPG paid
approximately $45 million, $43 million, and $40 million in dividends. In January
1996, the Board declared a quarterly dividend of $0.3475 per share on EPG's
common stock, payable on April 1, 1996, to shareholders of record on March 8,
1996.
In November 1994, the Board authorized the repurchase of up to 3.5 million
shares of EPG's outstanding common stock from time to time in the open market.
This authorization is in addition to a 2 million share authorization received in
October 1992. Shares repurchased are held in EPG's treasury and are expected to
be used in conjunction with EPG stock option compensation plans and for other
corporate purposes. Pursuant to the foregoing authorizations, the Company has
purchased 4.7 million shares as of December 31, 1995. On September 20, 1995, EPG
issued approximately 0.7 million shares of treasury stock in connection with the
Eastex acquisition. See Note 8 of Item 8, Financial Statements and Supplementary
Data.
Financing Facilities
As of December 31, 1995, and 1994, approximately $203 million and $107
million, respectively, of commercial paper was outstanding. As of December 31,
1995, there was $75 million outstanding under the Company's $400 million
revolving credit facility, which is considered support for commercial paper
borrowings. As of December 31, 1994, there were no borrowings outstanding under
this facility. As of December 31, 1995, and 1994, there were no borrowings
outstanding under an additional $30 million line of credit facility established
in October 1994. On January 19, 1996, the Board increased short-term borrowing
limits from $400 million to $500 million.
Eastex's credit facility of approximately $20 million expired October 31,
1995. On September 12, 1995, EPG retired $9 million of Eastex long-term debt.
In January 1992, EPG completed a sale of substantially all of its remaining
take-or-pay buy-out and buy-down receivables. In the third quarter of 1995, EPG
prepaid the outstanding $17 million take-or-pay financing liability.
EPG filed a shelf registration statement in August 1994, pursuant to which
EPG may offer up to $400 million of unsecured debt securities, preferred stock,
and common stock from time to time as determined by market conditions. On March
10, 1995, the registration statement was declared effective by the SEC. There
were no securities issued pursuant to the shelf registration statement as of
December 31, 1995, and 1994.
20
25
EPG's available shelf registration and lines of credit as of December 31,
1995, as discussed above, are summarized as follows:
(IN THOUSANDS)
--------------
Short-term borrowings.......................... $121,800
Shelf registration............................. 400,000
--------
Available Financing Facilities............... $521,800
========
Capital Expenditures
The Company's planned capital expenditures for 1996 of $175 million are
primarily for maintenance of business, system expansion, and system enhancement.
Capital expenditures for 1995 were $166 million compared to $173 million for
1994. The decrease was due primarily to lower maintenance offset by a system
expansion in the San Juan Basin, installation of various compression projects,
including the Hart Canyon compression project, and the purchase of the Burton
Flats cryogenic processing plant and related gathering system.
On February 29, 1996, an open season for shippers interested in EPG's
proposed 180 MMcf/d expansion of the Havasu Crossover Line concluded. EPG has
sent transportation service agreements to those shippers who expressed an
interest in the expansion for the purpose of securing definitive contracts. The
expansion would involve the construction of additional compression on the Havasu
Crossover Line at an estimated cost of approximately $17 million. EPG
anticipates that, in the near future, it will be seeking FERC certificate
authority for the proposed expansion.(1)
In June 1994, EPG filed an application with FERC for a certificate of
public convenience and necessity to expand its existing mainline system in the
San Juan Basin by approximately 300 MMcf/d at a cost of about $29 million. In
August 1995, FERC authorized the expansion project, conditioned on EPG's
compliance with various environmental conditions. In addition, FERC authorized
the inclusion of the project costs in EPG's rates. EPG commenced construction in
October 1995, and the project was completed and placed into service in December
1995.
In April 1994, EPG filed an application with FERC for a certificate of
public convenience and necessity to build the North/South Transfer Project. The
proposed pipeline would allow for the transfer of 468 MMcf/d of San Juan Basin
gas to EPG's south system and would enhance EPG's overall system flexibility to
meet market demands and to move gas to markets off the east end of the system.
The project was expected to cost approximately $62 million. In January 1996, EPG
filed a letter and notice of withdrawal of its application, stating that it had
reviewed the timing and necessary activities related to the completion of the
project and had determined that the North/South Transfer Project should be
withdrawn without prejudice to EPG for future refiling.
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.
The proposed expansion, as filed, would provide an additional 300 MMcf/d of
capacity at a cost of approximately $57 million. In November 1993, FERC issued
an order that approved the proposed border crossing facility south of Clint,
Texas that 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, which motion is currently
pending. In November 1994, FERC required EPG to provide the executed long-term
contracts or binding agreements for a substantial amount of the firm capacity of
the proposed facilities by January 1995. EPG advised FERC that although there
were presently no such contracts or agreements, EPG believed the project
remained viable and that the application should therefore not be dismissed. EPG
is in the process of evaluating the project and its related capital costs.
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
21
26
In March 1993, MPC filed an application, which was amended in November 1993
and April 1994, for a certificate of public convenience and necessity to build
and operate a 475 MMcf/d expansion of its existing system at an estimated cost
of approximately $500 million. FERC issued a series of orders from 1994 to 1995
related to the proposed expansion and, in December 1995, issued a final order
which denied rehearing on certain remaining issues. In February 1996, MPC filed
a notice to decline acceptance of the certificate of public convenience and
necessity issued by FERC stating that it had determined that the proposed
expansion was economically infeasible under current market circumstances.
In February 1996, EPFS, through its wholly owned subsidiary El Paso
Intrastate Company, acquired the Linc gathering system and the Pandale gathering
system from Tejas Power Corporation for approximately $12 million. The combined
throughput of the two systems is expected to contribute 45 MMcf/d on an annual
basis to EPFS's total throughput. The Linc gathering system is located in the
Waha area of the Permian Basin and should increase EPFS's market share in that
area. The Pandale gathering system is located in the Texas counties of Crockett
and Val Verde, and should give EPFS a base from which to grow in this active
drilling area.(1)
Financing Requirements
Future funding for capital expenditures, acquisitions, long-term debt
retirements, dividends, and other expenditures will be provided by internally
generated funds, debt/equity issuances, and/or available credit facilities.
OTHER
Company Restructuring
In response to changes in the natural gas industry, increased competition,
recent and future firm capacity contract step-downs and terminations, the
Company has initiated an extensive review of its business processes. As a result
of this review, the Company has adopted a program to restructure its businesses
and reduce operating costs through work force reductions and improved work
processes.
On January 12, 1996, the Company announced a reduction of its work force.
The reduction is expected to be accomplished through a voluntary early
retirement incentive program, a voluntary severance program, and an involuntary
reduction in work force program. The Company, which had 2,393 employees at
December 31, 1995, expects to reduce its total work force by approximately 600
to 800 employees.
The Company expects that a majority of the work force reductions will occur
by the end of the first quarter of 1996. In addition, the Company is initiating
changes to the pension plan and other benefit plans by January 1997. The details
of the changes have not yet been finalized; however, it is expected that these
changes will result in lower operating charges. The Company anticipates
recording a charge between $34 million and $37 million, net of income taxes.
These restructuring efforts should position the Company to more effectively
address the changes occurring in the natural gas industry.
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 Merger, 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 Merger would own the same number of shares of Holding
Company common stock immediately after the Merger as the EPG common stock held
immediately before the Merger. The change to a holding company structure would
be tax
- ---------------
(1) The previous statement(s) may be considered forward-looking. See
page 24 for a description of the important factors that may affect
actual results.
22
27
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.
At the time of the Merger, EPG would assign all of its rights under its
shareholder rights agreement to Holding Company, and Holding Company would
assume and agree to perform EPG's obligations thereunder. The presently
outstanding rights to purchase Company preferred stock, provided for by the
shareholders rights agreement, would, upon effectiveness of the Merger, be
converted to rights to purchase, in accordance with and subject to the terms and
provisions of the shareholder rights agreement, shares of the preferred stock of
Holding Company. The designation, rights and preferences of the preferred stock
of Holding Company would be identical to the preferred stock of EPG. The Holding
Company preferred stock purchase rights would, after the Merger, be deemed to be
attached to the Holding Company common stock certificates.
Immediately prior to the effectiveness of the Merger, EPG intends, subject
to receipt of a favorable IRS ruling and SEC no-action response, to transfer and
contribute to Holding Company as a capital contribution all of the outstanding
capital stock of the principal non-regulated subsidiaries of EPG. The
subsidiaries would be transferred as part of the planned separation of the
present regulated and non-regulated businesses of EPG under the holding company
structure. Following the Merger, EPG would continue to hold all of the assets of
EPG held immediately prior to the Merger, except for the stock of the
subsidiaries transferred to the Holding Company and certain other assets, not
material in amount, held immediately prior to the Merger.
All business and operations conducted by the Company prior to the Merger
would, after the Merger, continue to be conducted by the Company as direct and
indirect subsidiaries of Holding Company, and the consolidated assets and
liabilities of Holding Company and subsidiaries immediately after the Merger
would be the same as the consolidated assets and liabilities of the Company
immediately before the Merger.
The directors of the Holding Company immediately after the Merger would be
those persons who are the directors of EPG immediately prior to the Merger. All
officers of Holding Company would consist of persons who are currently officers
of EPG. In addition, the restated certificate of incorporation and by-laws of
EPG immediately prior to the Merger and the certificate of incorporation and
by-laws of the Holding Company immediately after the Merger would be identical,
with the exception that Holding Company's name would be different than EPG.
EPG expects to complete the restructuring by early 1997, 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 Merger and
certain other securities law issues, (iii) a favorable private letter ruling
from the IRS, and (iv) consents from certain third parties. 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
additional new terms of structure may be adopted, in response to conditions
imposed by IRS and SEC in their rulings or otherwise adopted by the Board in
on-going consideration of the holding company structure.
Management believes that the holding company structure will provide the
framework that allows for and accommodates future growth from internal
operations (including the separation of regulated and non-regulated businesses),
acquisitions, and joint ventures. This structure will also broaden the
alternatives available for future financing, as well as generally provide for
greater administrative and operational flexibility.
SFAS No. 71, Accounting for the Effects of Certain Types of Regulation
EPG and MPC are subject to the regulations and accounting of FERC, and
therefore continue to follow the reporting and accounting requirements of SFAS
No. 71. The Consolidated Balance Sheets contain assets and liabilities related
to operations which have been recorded pursuant to SFAS No. 71. If these
accounting
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principles should no longer be applied, an amount would be charged to earnings
as an extraordinary item. At December 31, 1995, this amount was estimated to be
approximately $46 million, net of income taxes. While management believes that
EPG and MPC remain "regulated" as the term is used in the relevant accounting
literature, 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 EPG's and MPC's ability to seek
recovery of the underlying deferred costs in their future rate proceedings or on
their 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
will not have a material impact on the Company's financial condition or results
of operations.
SFAS No. 121, Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to be
Disposed Of
The Company anticipates adopting SFAS No. 121 in the first quarter of 1996.
As a result of the adoption, the Company will reduce property, plant, and
equipment by a charge to earnings of approximately $19 million, net of income
taxes. In addition, management expects to write-off an impaired regulatory asset
of approximately $5 million, net of income taxes, in the first quarter of 1996.
See Note 2 of Item 8, Financial Statements and Supplementary Data.
SFAS No. 123, Accounting for Stock-Based Compensation
The Company adopted SFAS No. 123 in the first quarter of 1996, and elected
to continue to apply the accounting rules contained in APB No. 25. This election
requires the Company to disclose pro forma net income and earnings per share
based on the fair value methodology in SFAS No. 123; however, there is no impact
to the Company's financial condition or results of operations.
SOP 94-6, Disclosure of Certain Significant Risks and Uncertainties
The Company adopted SOP 94-6 effective January 1, 1995. There is no impact
to the Company's financial condition or results of operations.
For a further discussion of SFAS No. 121, SFAS No. 123, and SOP 94-6 see
Note 14 of Item 8, Financial Statements and Supplementary Data.
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private
Securities Litigation Reform Act of 1995
EPG is including the following cautionary statement in this Annual Report
on Form 10-K to make applicable and take advantage of the new "safe harbor"
provisions of the Private Securities Litigation Reform Act of 1995 for any
forward-looking statement made by, or on behalf of, the Company. The factors
identified in this cautionary statement are important factors (but not
necessarily all 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. Forward-looking statements are identified with a
footnote on the page in which they appear.
Where any such forward-looking statement includes a statement of the
assumptions or basis underlying such forward-looking statement, the Company
cautions that, while it believes such assumptions or basis to be reasonable and
makes them in good faith, assumed facts or basis almost always vary from actual
results, and the differences between assumed facts or basis and actual results
can be material, depending upon the
24
29
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 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.
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:
1 -- The ability to increase transmission, gathering, processing, and
sales volumes can be subject to the impact of future weather conditions,
including those that favor hydroelectric generation; price; drilling
activity; and service competition, especially due to excess pipeline
capacity into California.
2 -- Growth strategies through acquisitions and investments in joint
ventures may face legal and regulatory delays and other unforeseeable
obstacles beyond the Company's control.
3 -- Future profitability will be effected by the Company's ability to
compete with the services offered by other energy enterprises which may be
larger, offer more services, and possess greater resources.
4 -- Cost control efforts may be effected by the timing of related
work force reductions and might be further offset by unusual and unexpected
items resulting from such events as, but not limited to, litigation
settlements, adverse rulings or judgments, and unexpected environmental
remediation costs in excess of reserves.
5 -- Rates for certain services are related to natural gas prices such
that variations in natural gas prices may result in corresponding variances
in operating revenues.
6 -- Future operating results and success of business ventures in the
United States, Mexico, and Latin America may be subject to the effects of
and changes in United States and foreign trade and monetary policies, laws
and regulations, political and governmental changes, inflation and exchange
rates, taxes, and operating conditions.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
------------------------------------
1995 1994 1993
---------- -------- --------
Operating revenues
Reservation............................................. $ 503,455 $506,122 $483,471
Transportation.......................................... 23,262 41,102 59,631
Natural gas and liquids................................. 403,428 225,857 280,839
Gathering and processing................................ 72,477 66,581 51,427
Other................................................... 35,375 30,210 33,560
---------- -------- --------
1,037,997 869,872 908,928
---------- -------- --------
Operating charges
Operation and maintenance............................... 311,639 295,182 340,818
Natural gas and liquids................................. 402,279 233,823 249,484
Depreciation, depletion, and amortization............... 72,077 65,037 54,051
Litigation special charge............................... -- 15,062 --
Taxes, other than income taxes.......................... 39,591 38,473 35,330
---------- -------- --------
825,586 647,577 679,683
---------- -------- --------
Operating income.......................................... 212,411 222,295 229,245
---------- -------- --------
Other (income) and income deductions
Interest and debt expense............................... 86,297 78,850 75,429
Allowance for funds used during construction............ (2,419) (485) (5,438)
Other, net.............................................. (4,443) (4,146) 8,428
---------- -------- --------
79,435 74,219 78,419
---------- -------- --------
Income before income taxes................................ 132,976 148,076 150,826
Income taxes.............................................. 47,613 58,463 59,153
---------- -------- --------
Net income................................................ $ 85,363 $ 89,613 $ 91,673
========== ======== ========
Earnings per common share................................. $ 2.47 $ 2.45 $ 2.46
========== ======== ========
Average common shares outstanding......................... 34,495 36,632 37,212
========== ======== ========
The accompanying Notes and Supplemental Schedules are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNT)
ASSETS
DECEMBER 31, DECEMBER 31,
1995 1994
------------ ------------
Current assets
Cash and temporary investments................................... $ 39,373 $ 27,636
Accounts and notes receivable, net............................... 214,796 131,650
Inventories...................................................... 37,108 34,666
Take-or-pay buy-outs, buy-downs, and prepayments, net............ 10,477 33,356
Other regulatory assets.......................................... 11,740 12,000
Deferred income tax benefit...................................... 22,631 41,257
Other............................................................ 32,467 18,594
----------- -----------
Total current assets..................................... 368,592 299,159
----------- -----------
Property, plant, and equipment, net................................ 1,977,624 1,861,589
Intangible assets, net............................................. 47,878 4,308
Take-or-pay buy-outs, buy-downs, and prepayments, net.............. 1,017 14,502
Other regulatory assets............................................ 51,878 59,021
Other.............................................................. 87,636 93,192
----------- -----------
2,166,033 2,032,612
----------- -----------
Total assets............................................. $ 2,534,625 $ 2,331,771
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade......................................................... $ 200,984 $ 117,575
Other......................................................... 74,690 111,781
Short-term borrowings............................................ 278,200 106,800
Take-or-pay financing liability.................................. -- 36,700
Current maturities on long-term debt............................. 7,590 6,824
Accrued interest................................................. 32,552 31,236
Accrued taxes, other than income taxes........................... 29,793 27,373
Other............................................................ 18,833 13,766
----------- -----------
Total current liabilities................................ 642,642 452,055
----------- -----------
Long-term debt, less current maturities............................ 771,892 779,097
Deferred income taxes, less current portion........................ 314,143 304,918
Deferred credits................................................... 39,514 40,325
Other.............................................................. 54,279 45,740
----------- -----------
1,179,828 1,170,080
----------- -----------
Commitments and contingent liabilities (See Note 5.)
Stockholders' equity
Common stock, par value $3 per share; authorized 100,000 shares;
issued 37,351 shares.......................................... 112,054 112,053
Additional paid-in capital....................................... 454,713 454,705
Retained earnings................................................ 240,101 202,558
Less: Treasury stock of 3,127 and 1,799 shares................... 94,713 59,680
----------- -----------
Total stockholders' equity............................... 712,155 709,636
----------- -----------
Total liabilities and stockholders' equity............... $ 2,534,625 $ 2,331,771
=========== ===========
The accompanying Notes and Supplemental Schedules are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
---------------------------------
1995 1994 1993
--------- --------- ---------
Cash flows from operating activities
Net income................................................ $ 85,363 $ 89,613 $ 91,673
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion, and amortization.............. 72,077 65,037 54,051
Deferred income taxes.................................. 29,939 49,394 8,550
Net take-or-pay recoveries............................. 36,364 31,932 60,799
Net costs recovered (recoverable) through insurance.... (1,736) 22,969 (22,578)
Other working capital changes
Accounts and notes receivable........................ (11,433) 862 34,877
Inventories.......................................... 1,240 (2,527) 11,530
Other current assets................................. (10,714) 4,684 10,209
Accrual for regulatory issues........................ -- (34,903) 1,210
Accounts payable..................................... (9,871) 33,322 (38,644)
Accrued taxes, other than income taxes............... 2,322 4,132 5,291
Other current liabilities............................ 2,349 (4,037) 3,609
Other..................................................... 7,211 (7,276) 14,975
--------- --------- ---------
Net cash provided by operating activities............ 203,111 253,202 235,552
--------- --------- ---------
Cash flows from investing activities
Capital expenditures...................................... (166,323) (173,252) (164,333)
Proceeds from disposal of property........................ 3,951 7,299 1,674
Net cash flow impact of acquisitions...................... (23,303) -- (35,695)
Other..................................................... (30,134) (23,381) (7,553)
--------- --------- ---------
Net cash used in investing activities................ (215,809) (189,334) (205,907)
--------- --------- ---------
Cash flows from financing activities
Net commercial paper borrowings........................... 96,400 105,500 1,300
Revolving credit borrowings............................... 75,000 -- --
Long-term debt retirements................................ (15,543) (16,174) (2,871)
Repayment of volumetric take-or-pay receivable............ (36,700) (43,808) (35,313)
Acquisition of treasury stock............................. (56,528) (43,994) (18,001)
Dividends paid............................................ (44,922) (43,491) (39,935)
Other..................................................... 6,728 5,735 16,537
--------- --------- ---------
Net cash provided by (used in) financing
activities........................................ 24,435 (36,232) (78,283)
--------- --------- ---------
Increase (decrease) in cash and temporary investments....... 11,737 27,636 (48,638)
Cash and temporary investments
Beginning of period....................................... 27,636 -- 48,638
--------- --------- ---------
End of period............................................. $ 39,373 $ 27,636 $ --
========= ========= =========
The accompanying Notes and Supplemental Schedules are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNTS)
COMMON STOCK ADDITIONAL TREASURY STOCK TOTAL
----------------- PAID-IN RETAINED --------------------- STOCKHOLDERS'
SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT EQUITY
------ -------- -------- -------- ---------- -------- -------------
January 1, 1993.................. 37,304 $111,913 $454,480 $108,025 (184) $ (5,426) $ 668,992
Net income..................... 91,673 91,673
Issuance of common stock, net
of related costs............ 46 138 1,016 1,154
Common stock dividend
($1.10 per share)........... (40,904) (40,904)
Acquisition of treasury
stock....................... (509) (18,001) (18,001)
Issuance of treasury stock..... (1,288) 207 5,922 4,634
------ -------- -------- -------- ------ -------- ---------
December 31, 1993................ 37,350 112,051 455,496 157,506 (486) (17,505) 707,548
Net income..................... 89,613 89,613
Issuance of common stock, net
of related costs............ 1 2 24 26
Common stock dividend
($1.21 per share)........... (44,179) (44,179)
Acquisition of treasury
stock....................... (1,363) (43,994) (43,994)
Issuance of treasury stock..... (382) 50 1,819 1,437
Other.......................... (815) (815)
------ -------- -------- -------- ------ -------- ---------
December 31, 1994................ 37,351 112,053 454,705 202,558 (1,799) (59,680) 709,636
Net income..................... 85,363 85,363
Issuance of common stock, net
of related costs............ 1 7 8
Common stock dividend
($1.32 per share)........... (45,390) (45,390)
Acquisition of treasury
stock....................... (2,020) (56,528) (56,528)
Issuance of treasury stock for
acquisition of Eastex....... (2,128) 656 20,977 18,849
Issuance of treasury stock..... (300) 36 518 218
Other.......................... 1 (2) (1)
------ -------- -------- -------- ------ -------- ---------
December 31, 1995................ 37,351 $112,054 $454,713 $240,101 (3,127) $(94,713) $ 712,155
====== ======== ======== ======== ======= ======== =========
The accompanying Notes and Supplemental Schedules are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of the Company.
All significant intercompany transactions are accounted for at market prices and
have been eliminated in consolidation. The financial statements for previous
periods include certain reclassifications that were made to conform to the
current presentation. Such reclassifications have no impact on reported income
or stockholders' equity.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
On June 1, 1993, the Company acquired from a wholly owned subsidiary of
Enron Corp., that subsidiary's 50 percent interest in MPC, a general
partnership. This acquisition gave the Company 100 percent ownership of MPC. The
operating results of MPC are included in the Company's consolidated results of
operations for the twelve months ended December 31, 1995, and 1994, and the
months of May 1993 through December 1993. The Company's previously owned 50
percent equity interest in MPC is included in other-net in the Consolidated
Statements of Income.
Effective September 1, 1995, Eastex was merged with and into El Paso
Acquisition Company, a wholly owned subsidiary of EPG. The name of El Paso
Acquisition Company was changed to Eastex at the time of the merger. On December
7, 1995, Eastex purchased all of the issued and outstanding capital stock of
Premier. The Eastex operating results for the months of September through
December 1995 (including Premier for the month of December) are included in the
Company's consolidated results of operations for the year ended December 31,
1995.
Accounting for Regulated Operations
EPG and MPC are subject to the regulations and accounting procedures of
FERC, and therefore continue to follow the reporting and accounting requirements
of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.
Accounting methods for companies subject to cost-of-service regulation may
differ from those used by non-regulated companies. However, when the accounting
method prescribed by the regulatory authority is used for rate-making, such
accounting conforms to the generally accepted accounting principle of matching
costs against the revenues to which they apply.
Transactions which EPG has recorded differently than a non-regulated entity
include the following: (i) take-or-pay payments recoverable from customers,
based upon transportation volumes, have been recorded as an asset, net of
allowance; (ii) losses on reacquired debt have been recorded in other assets and
are being amortized over the life of the original or replacement debt; (iii)
revenue related to the implementation of SFAS No. 109 has been recorded as a
deferred credit and is being amortized into income; (iv) an adjustment to
reflect the increase in the federal income tax rate has been recorded in other
regulatory assets to be recovered in future rates; (v) OPEB costs that differ
from the amounts funded are recorded either as a regulatory asset or liability
to be included in future rates; (vi) postemployment benefit costs have been
recorded in other regulatory assets to be recovered in future rates; (vii) a
portion of EPG's investment in its underground storage facility has been
recorded as an asset and is being recovered in accordance with the settlement
agreement; (viii) the cost of equity funds used during construction has been
capitalized; and (ix) certain environmental costs have been recorded as
adjustments to accumulated depreciation.
Transactions which MPC has recorded differently than a non-regulated entity
include the following: (i) the cost of equity funds used during construction has
been capitalized, (ii) excess amounts due to
30
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straight-line depreciation rates have been recorded as other regulatory assets
to be recovered in future rates, and (iii) deferred taxes on the equity portion
of allowance for funds used during construction have been recorded in other
regulatory assets to be recovered in future rates.
While management believes that EPG and MPC remain "regulated" as the term
is used in the relevant accounting literature, 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. If these accounting principles should no longer be applied, an
amount would be charged to earnings as an extraordinary item. At December 31,
1995, this amount was estimated to be approximately $46 million, net of income
taxes. Any potential charge would be non-cash and would have no direct effect on
EPG's and MPC's ability to seek recovery of the underlying deferred costs in
their future rate proceedings or on their ability to collect the rates set
thereby.
In September 1995, FERC authorized EPG to abandon certificates applicable
to certain gathering and processing facilities, subject to certain conditions.
This order was reaffirmed in November 1995. These facilities were transferred to
EPFS effective January 1, 1996. 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 will not have a significant impact on the Company's financial condition
or results of operations.
Cash and Temporary Investments
Short-term investments purchased with an original maturity of three months
or less are considered cash equivalents.
Accumulated Provision for Uncollectible Accounts Receivable
The Company has established a provision for losses on trade accounts
receivable which may become uncollectible. Collectibility of trade receivables
is reviewed regularly, and the allowance for bad debts is adjusted as necessary
under the specific identification method. The balances of this provision at
December 31, 1995, and 1994, were $2.6 million and $6.2 million, respectively.
Gas Imbalances
The Company currently accounts for gas imbalances due to or due from
shippers and operators. Gas imbalances are valued at the appropriate index
price.
The Company has established a provision for gas imbalances which may become
uncollectible. Collectibility of gas imbalances is reviewed regularly, and the
provision is adjusted as necessary under the specific identification method. The
balances of this provision at December 31, 1995, and 1994, were $7.4 million and
$8.8 million, respectively.
Inventories
Materials and supplies and gas in storage are valued at the lower of cost
or market with cost determined using the average cost method.
Take-or-Pay Settlements
Assets resulting from the resolution of take-or-pay obligations include
recoupable take-or-pay prepayments and take-or-pay buy-out and buy-down
receivables. Recoupable prepayments result when EPG pays for, but does not
physically receive, gas and retains the right to take such gas in the future,
generally over 5 years. Take-or-pay buy-outs and buy-downs represent costs paid
to natural gas producers for the termination or modification of gas purchase
contracts. In exchange for EPG's agreement to absorb 25 percent of its
take-or-pay buy-out and buy-down costs, FERC regulations provide for the direct
billing of 25 percent of such costs to EPG's customers. In addition, such
regulations allow EPG to recover the remaining 50 percent of its
31
36
buy-out and buy-down costs through a surcharge added to its transportation
rates. The collection period for the surcharge extends through March 1996.
Property, Plant, and Equipment
Included in the Company's property, plant, and equipment is construction
work in progress of approximately $74 million and $78 million at December 31,
1995, and 1994, respectively. An allowance for both debt and equity funds used
during construction is included in the cost of the Company's property, plant,
and equipment.
EPG's properties are depreciated using the composite method. The
straight-line depreciation rate for transmission facilities was 1.6 percent in
1995, 1994, and 1993. The depreciation rate for gathering facilities was 3.5
percent for 1995, 1994, and 1993.
MPC's depreciation rates reflect a levelized cost-of-service approach and a
25-year depreciable life. MPC's depreciation rate for its plant during the first
15 years increases gradually from 1.48 percent in 1992 to 8.76 percent in 2007.
The depreciation rates are designed to recover approximately 80 percent of MPC's
plant balance by March 1, 2007. The depreciation rate related to years 16
through 25 will be determined in future rate proceedings.
Additional acquisition cost assigned to utility plant represents EPG's
portion of the excess of allocated acquisition cost over historical cost that
resulted from the 1983 acquisition of EPG's former parent, TEPCO, by BR's former
parent, Burlington Northern Inc. These costs are being amortized on a
straight-line basis over the estimated remaining life of the properties.
Costs of properties that are not operating units, as defined by FERC, which
are retired, sold, or abandoned are charged or credited, net of salvage, to
accumulated depreciation and amortization. Gains or losses on sales of operating
units are credited or charged to income.
Intangible Assets
Goodwill resulting from the acquisitions of Eastex and Premier is being
amortized over a 40-year period using the straight-line method. Other intangible
assets are valued at cost and are being amortized over a period ranging between
5 years and 25 years using the straight-line or composite method.
The Company periodically reviews the value of its goodwill to determine if
an impairment has occurred. The Company measures the potential impairment of
recorded goodwill by the undiscounted value of expected future operating cash
flows in relation to its net capital investment in the subsidiary. Based on its
review, the Company does not believe that an impairment of its goodwill has
occurred.
Environmental Costs
Environmental expenditures that relate to current operations are expensed
or capitalized as appropriate. Expenditures that relate to existing conditions
caused by past operations and that do not contribute to current or future
revenue generation are expensed. Reserves for estimated costs are recorded when
environmental remedial efforts are probable and the costs can be reasonably
estimated. The most current information available, including similar past
experiences, available technology, regulations in effect, the timing of
remediation, and cost-sharing arrangements are used in determining the reserves.
The environmental reserves are based on management's estimate of the most likely
cost to be incurred and are reviewed periodically and adjusted as additional or
new information becomes available. Reserves for expenditures expected to be made
within 1 year are classified as current, and the remainder are classified as
non-current in the Consolidated Balance Sheets.
Financial Instruments With Off-Balance-Sheet Risk
The Company is a party to financial instruments with off-balance-sheet risk
in the normal course of business to reduce its exposure to fluctuations in
interest rates and the price of natural gas. These financial instruments include
interest rate swaps, price swap agreements, futures, and options.
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37
Gains or losses on futures and options contracts are deferred until the
hedged commodity transaction occurs. The difference paid or received under the
interest rate swap agreements is charged or credited to interest expense. Gains
or losses on price swaps, futures, and options are recognized and reported as a
component of the related transaction. Any cash flow recognition resulting from
holding these financial instruments are treated in the same manner as the
underlying transaction.
Income Taxes
Income taxes are based on income reported for tax return purposes along
with a provision for deferred income taxes. Deferred income taxes are provided
to reflect the tax consequences in future years of differences between the
financial statement and tax bases of assets and liabilities at each year end.
Tax credits are accounted for under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
Pursuant to a tax sharing agreement between EPG and BR covering periods
prior to July 1992, EPG is responsible for its tax liabilities and those of its
subsidiaries. EPG is required to pay BR its allocable portion of the
consolidated federal tax liability and combined state income tax liability for
such periods.
Treasury Stock
Treasury stock is accounted for using the cost method and is shown as a
reduction to stockholders' equity in the Consolidated Balance Sheets. Treasury
stock sold or issued is valued on a first-in first-out basis. Included in
treasury stock at December 31, 1995, and 1994, were 680,000 shares and 430,000
shares, respectively, that were reserved to secure benefits under certain of the
Company's benefit plans.
Earnings Per Share
Earnings per share of common stock is based on the weighted average number
of shares of common stock outstanding during the year. The weighted average
shares of common stock outstanding for 1995, 1994, and 1993 were 34,495,422,
36,632,236, and 37,212,192, respectively. Stock options are the only common
stock equivalents issued by the Company and are currently not dilutive.
2. EMPLOYEE BENEFITS
Pensions
The Company maintains a defined benefit pension plan covering all employees
of the Company, except employees of Eastex and its subsidiaries and leased
employees. In general, benefits are based on years of credited service and final
5-year average compensation, and have maximum limitations as defined in the
pension plan.
The Company's funding policy is to make annual contributions to the pension
plan. These contributions are limited to amounts currently deductible for tax
purposes. The amounts are calculated using the projected unit credit method, to
provide the pension plan with assets sufficient to meet the benefits to be paid
to pension plan participants. The objective under this method is to fund each
participant's benefits under the pension plan as they accrue, taking into
consideration future salary increases.
The following table reflects the components of net periodic pension cost
for the years ended December 31:
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
Service cost -- benefits earned during the period.... $ 8,470 $ 9,345 $ 7,568
Interest cost on projected benefit obligation........ 41,076 39,458 38,786
Actual (return) loss on plan assets.................. (85,952) 4,721 (43,850)
Net amortization and deferral........................ 49,143 (39,669) 10,724
-------- -------- --------
Net periodic pension cost............................ $ 12,737 $ 13,855 $ 13,228
======== ======== ========
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The following table sets forth the qualified pension plan's funded status
and amounts recognized in the Company's Consolidated Balance Sheets at December
31:
1995 1994
-------- --------
(IN THOUSANDS)
Actuarial present value of benefit obligations
Vested benefits............................................ $508,676 $430,499
Nonvested benefits......................................... 691 818
-------- --------
Accumulated benefit obligation............................... $509,367 $431,317
======== ========
Projected benefit obligation for service rendered to date.... $587,248 $489,121
Plan assets at fair value, primarily listed stocks and
government securities...................................... 473,472 407,620
-------- --------
Projected benefit obligation in excess of plan assets........ $113,776 $ 81,501
======== ========
Unrecognized net loss........................................ $ 75,828 $ 36,686
Unrecognized net transition obligation....................... 16,601 19,305
Recognized pension liability................................. 21,347 25,510
Minimum liability adjustment included in recognized pension
liability.................................................. -- --
-------- --------
$113,776 $ 81,501
======== ========
The accumulated vested benefit obligation is the actuarial present value of
the vested benefits to which the employee is currently entitled, but it is based
on the employee's expected date of termination.
The following table reflects the actuarial assumptions used in the
valuation of the projected benefit obligation at December 31:
1995 1994
----- -----
Weighted average discount rate.................................. 7.25% 8.75%
Rate of increase in future compensation levels.................. 5.00% 5.00%
Weighted average expected long-term rate of return on plan
assets....................................................... 9.25% 9.25%
Retirement Savings Plan
The Company maintains a defined contribution plan covering all employees of
the Company, except employees of Eastex and its subsidiaries. During 1995, 1994,
and 1993, the Company made matching contributions equal to a participant's basic
contributions of up to 6 percent where the participant has fewer than 10 years
of employment with the Company, or up to 8 percent where the participant has 10
or more years of employment with the Company. Amounts expensed under the plan
were approximately $8 million for each of the years ended December 31, 1995,
1994, and 1993.
Postretirement Benefits, Other than Pensions
The Financial Accounting Standards Board issued SFAS No. 106, Employers'
Accounting for Post Retirement Benefits Other Than Pensions, which requires
companies to account for OPEB (principally retiree medical costs) on an accrual
basis versus the pay-as-you-go basis traditionally followed by most United
States companies. The Company adopted SFAS No. 106 effective January 1, 1993.
The Company provides a non-contributory defined benefit postretirement
medical plan that covers employees who retired on or before March 1, 1986, and
limited postretirement life insurance for employees who retire after January 1,
1985. As such, the Company's obligation to accrue for OPEB is primarily limited
to the fixed population of retirees who retired on or before March 1, 1986. The
medical plan is funded to the extent employer contributions are recoverable
through rates.
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EPG began recovering through its rates the OPEB costs included in the
January 1993 settlement agreement. To the extent actual OPEB costs differ from
the amounts funded, a regulatory asset or liability is recorded.
The following table reflects the components of net periodic postretirement
benefit cost for the years ended December 31:
1995 1994 1993
------- ------- -------
(IN THOUSANDS)
Interest cost on accumulated postretirement benefit
obligation............................................ $ 6,767 $ 6,983 $ 9,377
Actual (return) loss on plan assets..................... (5,041) 472 (254)
Net amortization and deferral........................... 10,436 6,585 9,062
------- ------- -------
Net periodic postretirement benefit cost................ $12,162 $14,040 $18,185
======= ======= =======
The following table sets forth the postretirement plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheets at December 31:
1995 1994
-------- --------
(IN THOUSANDS)
Accumulated postretirement benefit obligation................... $ 90,795 $ 86,656
Plan assets at fair value, primarily U.S. stocks and U.S.
bonds......................................................... 30,102 16,758
-------- --------
Accumulated postretirement benefit obligation in excess of plan
assets........................................................ $ 60,693 $ 69,898
======== ========
Unrecognized net gain........................................... $(22,809) $(26,441)
Unrecognized transition obligation.............................. 88,179 96,987
Prepaid postretirement benefit cost............................. (4,677) (648)
-------- --------
$ 60,693 $ 69,898
======== ========
A 9.0 percent annual rate of increase in the per capita costs of covered
health care benefits was assumed for 1996, gradually decreasing to 6.0 percent
by the year 1999. Increasing the assumed health care cost trend rates by one
percentage point in each year would increase the accumulated postretirement
benefit obligation at December 31, 1995, by approximately $9 million and
increase the interest cost component of net periodic postretirement benefit cost
for 1995 by approximately $1 million. A discount rate of 7.25 percent and 8.75
percent was used to determine the accumulated postretirement benefit obligation
at December 31, 1995, and 1994, respectively. The weighted average expected
long-term rate of return for 1995 was 7.6 percent.
Postemployment Benefits Other Than Pension
The Financial Accounting Standards Board issued SFAS No. 112, Employers'
Accounting for Postemployment Benefits, which requires companies to account for
benefits to former or inactive employees after employment but before retirement
(referred to in SFAS No. 112 as "postemployment benefits"). SFAS No. 112 is
effective for the fiscal years beginning after December 15, 1993. These
postemployment benefits include every form of benefit provided to former or
inactive employees, their beneficiaries and covered dependents. Benefits
include, but are not limited to, salary continuation, supplemental unemployment
benefits, severance benefits, disability-related benefits (including workers'
compensation), job training and counseling, and continuation of benefits such as
health care benefits and life insurance coverage. Effective January 1, 1994, the
Company adopted SFAS No. 112. The Company has recorded a liability for
postemployment benefit costs of approximately $8 million, in addition to a
regulatory asset for the same amount, to reflect the initial adoption of SFAS
No. 112. In accordance with the offer of settlement filed with FERC in March
1996, management expects to write-off the regulatory asset established at the
adoption of SFAS No. 112. The regulatory asset of $5 million, net of income
taxes, will be written off in the first quarter of 1996. For a further
discussion, see Note 14, Recent Pronouncements.
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3. LONG-TERM DEBT AND OTHER FINANCING
Long-term debt outstanding at December 31, 1995, and 1994, consisted of the
following:
1995 1994
-------- --------
(IN THOUSANDS)
Long-term debt
EPG
6.90% Notes, due January 1997............................. $100,000 $100,000
9.45% Notes, due September 1999........................... 47,452 47,447
7 3/4% Notes, due January 2002............................ 214,678 214,624
8 5/8% Debentures, due March 2012......................... 16,832 16,811
8 5/8% Debentures, due January 2022....................... 258,479 258,420
Other..................................................... 26 35
MPC
Project financing loan, due March 2007, average interest
rates of 8.8% and 8.0%.................................. 141,768 148,584
Eastex
Promissory note, due April 1, 1998, interest rate of
floating prime rate plus 1%............................. 247 --
-------- --------
779,482 785,921
Less current maturities................................... 7,590 6,824
-------- --------
Total long-term debt................................. $771,892 $779,097
======== ========
The following are aggregate maturities of long-term debt for the next 5
years and in total thereafter:
(IN THOUSANDS)
1996................................................................ $ 7,590
1997................................................................ 108,379
1998................................................................ 18,165
1999................................................................ 65,380
2000................................................................ 11,105
Thereafter.......................................................... 568,863
--------
Total long-term debt, including current maturities........ $779,482
========
EPG must comply with various restrictive covenants contained in its debt
agreements which include, among others, maintaining a consolidated debt and
guaranties to capitalization ratio no greater than 70 percent. In addition, EPG
subsidiaries on a consolidated basis (as defined in the agreements) may not
incur debt obligations which would exceed $75 million in the aggregate. As of
December 31, 1995, EPG's consolidated debt and guaranties to capitalization
ratio was 56 percent and debt obligations of EPG subsidiaries did not exceed $75
million on a consolidated basis.
In September 1991, MPC entered into a credit agreement with a group of
banks which provided a 15-year project financing loan to MPC of up to $180
million. Total outstanding loan balances under the credit agreement were $142
million and $149 million at December 31, 1995, and 1994, respectively. The loan
is repayable in semiannual installments through March 2007. Interest on the loan
is payable quarterly.
Borrowings under the credit agreement are collateralized by a priority
interest in the Company's partnership interests and certain other distributed
and undistributed partnership property. The credit agreement also contains
covenants relating to, among other things, partnership distributions and
additional indebtedness.
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Financing Transactions
Short-term borrowings are principally commercial paper with weighted
average interest rates of 6.0 percent and 4.6 percent at December 31, 1995, and
1994, respectively. As of December 31, 1995, and 1994, approximately $203
million and $107 million, respectively, of commercial paper was outstanding. In
February 1992, EPG established a $300 million revolving credit facility with a
group of banks which would have expired in March 1996. This facility was
replaced in August 1994 when EPG established with a group of banks a revolving
credit facility of $400 million that expires August 1999. This facility was
established primarily as a liquidity facility for the Company's commercial paper
program. As of December 31, 1995, there was $75 million outstanding under this
facility. There were no borrowings outstanding under this facility as of
December 31, 1994. In October 1994, EPG established an additional $30 million
line of credit facility. As of December 31, 1995, and 1994, there were no
borrowings outstanding under this line of credit facility. On January 19, 1996,
the Board increased short-term borrowing limits from $400 million to $500
million. Eastex had available a credit facility of approximately $20 million
which expired October 31, 1995. On September 12, 1995, EPG retired Eastex
long-term debt in the amount of $9 million.
EPG filed a shelf registration statement in August 1994, pursuant to which
EPG may offer up to $400 million of unsecured debt securities, preferred stock,
and common stock from time to time as determined by market conditions. On March
10, 1995, the registration statement was declared effective by the SEC. There
were no securities issued pursuant to the shelf registration statement as of
December 31, 1995, and 1994.
4. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is presented in accordance with the requirements of SFAS No. 107.
The estimated fair value amounts have been determined by the Company using
available market information and valuation methodologies.
As of December 31, 1995, and 1994, the carrying amounts of certain
financial instruments employed by the Company, including cash, cash equivalents,
short-term borrowings and investments, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments. The fair value of the long-term debt has been estimated based on
quoted market prices for the same or similar issues. The fair value of the
project financing is representative of the carrying amount due to the short-term
nature of the interest rates. The fair value of all derivative financial
instruments is the amount at which they could be settled, based on quoted market
prices or estimates obtained from dealers.
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The following table reflects the carrying amount and estimated fair value
of the Company's financial instruments at December 31:
DECEMBER 31,
------------------------------------------------
1995 1994
---------------------- ----------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN THOUSANDS)
Balance sheet financial instruments:
Long-term debt................................... $637,714 $ 710,460 $637,337 $ 621,400
Project financing................................ 141,768 141,768 148,584 148,584
Other financial instruments:
Non-Trading
Interest rate swap agreements................. -- 15,497 -- 2,144
Futures contracts............................. -- 1,050 -- 84
Option contracts.............................. -- (12,494) -- --
Swap agreements............................... -- 22,545 -- 1,190
Trading
Futures contracts............................. -- (6,200) -- --
Option contracts.............................. -- 6,891 -- --
Swap contracts................................ -- 1,454 -- --
-------- --------- -------- ---------
Total.................................... $779,482 $ 880,971 $785,921 $ 773,402
======== ========= ======== =========
Derivative Financial Instruments
In prior years, the Company used derivative instruments to principally
manage well-defined interest rate price risks and had limited involvement in
financial derivative instruments to manage commodity price risks. Subsequent to
the acquisition of Eastex in September 1995, the Company has broadened its
utilization of natural gas futures, options and swap contracts to hedge higher
levels of volumetric fixed price purchase and sale commitments. In the ordinary
course and conduct of its business, MSG utilizes futures and option contracts
traded on the NYMEX and OTC options and price and basis swaps with major gas
merchants and financial institutions to hedge its price risk exposure related to
inventories and fixed price commitments to purchase and sell natural gas. It is
MSG's policy to seek to maintain a balanced portfolio of supply and demand
contracts, utilizing the NYMEX and OTC financial markets to hedge against price
volatility which may effect those obligations. In addition to its hedging
activities, MSG also engages in selective trading of these financial
instruments.
Non-Trading
1. Interest Rate Swap Agreements
MPC
MPC has entered into interest rate swap agreements which effectively
converted $114.3 million of floating-rate debt to fixed-rate debt (see Note 3,
Long-Term Debt and Other Financing). MPC makes payments to counterparties at
fixed rates and in return receives payments at floating rates. Substantially all
of the remaining loan principal had interest rates ranging from 6.8 percent to
7.3 percent during 1995. The two swap agreements were entered into in March 1992
and have remaining terms of approximately 4 years and 6 years, respectively.
EPNC
In February 1995, EPNC entered into a 7.75-year lease agreement (see Note
5, Commitments and Contingencies). To moderate the exposure to interest rates,
EPNC entered into an interest rate swap arrangement effective July 31, 1995,
whereby approximately 50 percent of the current lease financing was converted
from a London Interbank Offered Rate (LIBOR) based floating rate to a 5.9
percent fixed rate.
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The effective dates and notional amounts subject to the swap arrangement
are as follows:
(IN THOUSANDS)
--------------
July 31, 1995 -- October 31, 1995................................ $ 12,500
October 31, 1995 -- April 30, 1996............................... $ 25,000
April 30, 1996 -- December 31, 1997.............................. $ 35,000
The primary risks associated with interest rate swaps are the exposure to
movements in interest rates and the ability of the counterparties to meet the
terms of the contracts. Based on review and assessment of counterparty risk,
neither MPC nor EPNC anticipates non-performance by the other parties.
2. Futures contracts
Natural gas futures contracts are traded on the NYMEX, with each contract
equivalent to 10,000 MMbtu. MSG purchases and sells futures contracts to
partially reduce the effects of price volatility characteristics of the cash or
spot market of natural gas. Realized and unrealized changes in the market value
of futures contracts are deferred until the hedged transaction is recognized. At
December 31, 1995, MSG had deferred gains from realized and unrealized positions
of approximately $6.2 million, which will be offset by losses from MSG's
obligations to purchase and sell natural gas in future periods. At December 31,
1994, EPGM had a deferred loss of approximately $1.2 million. These deferred
gains (losses) were included in the Consolidated Balance Sheets at December 31,
1995, and 1994. At December 31, 1995, MSG had 869 net contracts open (1,540 long
contracts and 671 short contracts), representing aggregate notional volumes of
8.7 Bcf (15.4 Bcf related to long contracts and 6.7 Bcf related to short
contracts) expiring through January 1997. At December 31, 1995, the aggregate
notional value of the net open futures contracts was $16.1 million ($29.5
million related to long contracts and $13.4 million related to short contracts).
At December 31, 1994, EPGM held 25 futures contracts, representing an aggregate
notional volume of 0.2 Bcf and a notional value of $0.5 million.
3. Option contracts
Natural gas option contracts provide the holder the right, but not the
obligation, to buy or sell natural gas at a predetermined price during a
specific period. MSG contemporaneously purchases and sells option contracts to
hedge certain price risks associated with contracts whereby MSG has provided to
its counterparty a pre-determined floor (minimum) and/or ceiling (maximum) price
under the contract. MSG receives premiums from the counterparty for options
contracts sold and pays premiums to the counterparty for option contracts
purchased. MSG had net premiums deferred of $2.9 million included in the
Consolidated Balance Sheets at December 31, 1995. These premiums will be
amortized over the remaining term of the contracts, which correspond with the
recognition of the underlying hedged commitment. As of December 31, 1995, MSG
held 3,390 net option contracts (180 long contracts and 3,570 short contracts),
representing net notional volumes of 33.9 Bcf, ranging from terms of 1 to 10
months. At December 31, 1994, EPGM had no option contracts open.
4. Price and basis swap contracts
MSG utilizes swap contracts to hedge inherent price risks resulting from
(i) the varying price characteristics of the Company's monthly physical and
financial portfolios of purchase and sales transactions and (ii) locational
pricing differences between various published price indices and the NYMEX
futures contracts which may have been utilized as a hedge component. These swap
agreements include (i) transactions in which one party agrees to pay a fixed
price while the other party agrees to pay a price based on a published index
(referred to as price swaps) and (ii) transactions in which the parties agree to
pay based on different indices (referred to as basis swaps). At December 31,
1995, MSG held price swap agreements, ranging in terms from 1 month to 4 years,
representing net notional volumes of 18.6 Bcf. Under these price swap
agreements, MSG will pay a fixed price and receive a variable price for notional
quantities of 34.4 Bcf and pay a variable and receive a fixed price for notional
quantities of 15.8 Bcf. At December 31, 1995, MSG
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44
held basis swap agreements ranging in terms from 1 to 32 months, representing
net notional volumes of approximately 33.7 Bcf. At December 31, 1994, EPGM had
price swap agreements with broker-dealers to exchange monthly payments on
notional quantities amounting to 17.0 Bcf. During 1994, EPGM realized a pretax
loss of approximately $1.4 million pertaining to price swap agreements. At
December 31, 1994, EPGM had no basis swaps. At December 31, 1995, MSG had
deferred gains (losses) from realized and unrealized price and basis swap
positions of approximately $22.5 million. These gains (losses) will be offset by
gains (losses) from MSG's obligations to purchase and sell natural gas in future
periods. As of December 31, 1994, EPGM had deferred gains (losses) of
approximately $1.2 million. These deferred gains (losses) were included in the
Consolidated Balance Sheets at December 31, 1995, and 1994.
Trading
In late 1995, MSG also utilized financial instruments for purposes other
than hedging its physical obligations. In the conduct of these trading
activities, MSG primarily bought and sold option contracts and utilized futures
contracts and price swap agreements to manage its exposure to market risks. At
December 31, 1995, MSG held option futures, and price swap contracts with net
notional quantities of approximately 19.8 Bcf, 13.8 Bcf, and 8.5 Bcf,
respectively. At December 31, 1995, the mark-to-market value of the trading
activity portfolio was approximately $2.9 million and is included in the
Consolidated Balance Sheets and Statements of Income. As a result of the
proximity of the trading activity to year end, the average fair value of the
financial instruments related to the trading activity and the gains arising from
the trading activities during the reporting period approximate their fair value
at December 31, 1995.
Credit and Price Risk Management
The Company's credit risk relates to the risk of loss as a result of
non-performance by its counterparties. The Company periodically reviews and
assesses counterparty risk to limit any material impact to its financial
position or results of operations; consequently, the Company does not anticipate
non-performance by the other parties. The Company sets credit limits prior to
entering into transactions and did not obtain collateral or other security to
support financial instruments subject to credit risk during 1995. MPC's
objective in entering into the interest rate swap agreements was to avoid the
interest rate risk associated with the floating rate debt. MSG's objective in
entering into futures, options, and swap agreements is to primarily hedge
against adverse changes in the price of natural gas. MSG's credit risk is
specifically related to NYMEX futures and option contracts and is limited to the
in the money value of its contracts and is minimized through the daily
settlement of its cash deposit accounts, credit standings of the Company's
brokers, and the NYMEX. The primary credit risks related to OTC option and price
swap agreements is non-performance by its counterparties and is limited to the
in the money value of the contracts. While the notional amounts reflect the
extent of involvement in the futures, option, and swap contracts, the amounts
potentially at risk, in the event of non-performance by the other parties, are
substantially smaller.
A designated committee oversees the credit and price risk management
activities of the Company to ensure that specific credit and price risk
management strategies have been developed, reviewed, and implemented that comply
with the stated objectives approved by management.
5. COMMITMENTS AND CONTINGENCIES
Rates and Regulatory Matters
El Paso Natural Gas Company
General Rate Filings and Other -- In July 1992, EPG filed for FERC approval
of new rates to recover increased costs and return on rate base associated with
EPG's expansion and modernization projects. These rates became effective on
February 1, 1993, subject to refund. EPG made its compliance filing in December
1992, in accordance with the Restructuring Rules. In January 1993, EPG, certain
of its customers, and FERC staff reached a settlement agreement which led to the
resolution of the above mentioned rate and restructuring proceedings. The
settlement agreement was effective October 1, 1993. Under the settlement
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45
agreement, EPG refunded a total of approximately $56 million, inclusive of
interest, in the fourth quarter of 1993. EPG had provided for these rate refunds
as revenues were collected.
The settlement agreement provided, in part, for the accelerated recovery of
a substantial portion of EPG's investment in its underground storage facility.
The amount to be recovered was approximately $57 million plus interest which
began accruing February 1, 1993, at the FERC allowed rate, which approximates
the prime rate. In March 1994, EPG received a final FERC letter order approving
recovery of the $57 million of underground storage facility costs. Such costs
are being recovered through December 31, 1996, by a demand charge mechanism. The
amount recovered through December 31, 1995, was $45 million. The outstanding
balances at December 31, 1995, and 1994, were $12 million and $24 million,
respectively, of which $12 million is reflected in the current portion of other
regulatory assets for both periods and $12 million is included in other
regulatory assets in the Consolidated Balance Sheets at December 31, 1994.
In June 1995, EPG made a filing with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996, subject to refund.
In March 1996, EPG filed a comprehensive offer of settlement which, if approved
by FERC, would resolve issues related to its pending rate case and issues
surrounding certain contract reductions and expirations which occur between
January 1, 1996, and December 31, 1997. For a further discussion of the March
1996 offer of settlement see Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations.
Producer Settlement and Cost Recovery -- Since 1987, EPG has made, or has
committed to make, buy-out and buy-down payments totaling $1.5 billion to
resolve past and future take-or-pay exposure, to terminate and reform gas
purchase contracts, to amend pricing and take provisions of gas purchase
contracts, and to settle related litigation. These payments resolved virtually
all the outstanding producer claims asserted against EPG and terminated or
prospectively reformed substantially all of EPG's remaining gas purchase
contracts, with the result that EPG no longer has any material take-or-pay
exposure. In certain cases, EPG resolved claims by making recoupable
prepayments. At December 31, 1995, and 1994, the recoupable prepayment balances
were $3 million and $6 million, respectively.
EPG has filed to recover $1.1 billion of its buy-out and buy-down costs
under FERC cost recovery procedures. The collection period for such costs
extends through March 1996. Through December 31, 1995, EPG had recovered
substantially all of the $1.1 billion. EPG has established a reserve, based on
throughput projections, for that portion of the receivables balance which is
unlikely to be collected over the period through March 1996. The balances of
this reserve were $1 million and $9 million at December 31, 1995, and 1994,
respectively.
Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. In October 1992,
FERC issued an order resolving all but one of the outstanding issues regarding
EPG's take-or-pay proceedings. The issue unresolved by FERC involved the claim
by several customers that EPG sought to recover an excessive amount for the
value of certain production properties which were transferred to a producer as
part of a 1989 take-or-pay settlement. Following a hearing on this issue, in
June 1994, FERC affirmed a decision of an Administrative Law Judge which found
that the valuation proposed by EPG was excessive and required EPG to refund to
its customers the costs found to be ineligible for take-or-pay recovery. In
accordance with FERC decision, EPG refunded $34 million, inclusive of interest,
to its customers in September 1994. In December 1994, EPG filed a petition with
the Court of Appeals for review of FERC decision, which petition is currently
pending. In addition, certain of EPG's customers sought review of certain
aspects of the October 1992 order in the Court of Appeals. In January 1996, the
Court of Appeals remanded the order to FERC with a direction to clarify the
distinction between take-or-pay buydown or buyout costs which were ineligible
for recovery and those which were imprudently incurred and, therefore not
recoverable. FERC has not yet taken action on the Court of Appeals remand.
In January 1992, EPG completed a sale of substantially all of its remaining
take-or-pay buy-out and buy-down receivables. The receivables sold in this
transaction included $104 million which was recovered through direct bill and
$221 million to be recovered through a volumetric surcharge. The volumetric
surcharge portion of the sale has been accounted for as a financing transaction
because EPG is subject to certain
41
46
recourse provisions related to such receivables. Amounts collected related to
the take-or-pay receivables sold were remitted to the purchasers of the
receivables. In the third quarter of 1995, EPG prepaid the outstanding $17
million take-or-pay financing liability.
Mojave Pipeline Company
General Rate Filings and Other -- MPC filed a service and rate design
restructuring plan in November 1992 which was essentially approved by FERC in
March 1993. Several of MPC's customers have filed petitions with the Court of
Appeals for review of the March 1993 order and certain other FERC orders. These
petitions are currently pending before the Court of Appeals. The primary issues
on appeal pertain to FERC's requirement that MPC's rates for firm transportation
service be based upon SFV rate design rather than MFV rate design. Management
believes the Court of Appeals will uphold SFV rates as applied to MPC.
In February 1995, MPC made a filing with FERC seeking authorization to
maintain its existing rates. In March 1995, FERC accepted the filing and allowed
the rates to become effective as of March 30, 1995, subject to refund. In
September 1995, MPC filed a settlement agreement supported by FERC and the
majority of MPC's firm shippers which would continue rates at existing levels
for a 5-year period. In December 1995, FERC approved the settlement agreement as
it relates to the supporting parties. Contested issues applicable solely to the
minority customer group not supporting the settlement will be resolved following
a hearing before FERC.
Environmental Matters
As of December 31, 1995, EPG had a reserve of approximately $35 million for
the following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of PCB contamination at certain of
its facilities. The majority of the required PCB remediation has been
completed. For the year ended December 31, 1995, EPG has incurred
approximately $3 million in PCB remediation costs. Future PCB remediation
costs are estimated to range between $3 million and $4 million over the
next 4 years.
2 -- In June 1993, EPG executed an Administrative Order on Consent with EPA
to conduct a RI/FS for a site located in Statesville, North Carolina that
has been identified for cleanup. EPG and the other PRP have entered into an
agreement to jointly fund the RI/FS for the site. Total remediation costs
are estimated to be between $16 million and $29 million over a 30-year
period. EPG and the other PRP are engaged in negotiations over the
appropriate allocation of the remediation costs.
3 -- In November 1993, in accordance with an EPA order, EPG and Atlantic
Richfield Company submitted work plans for remediation of the Prewitt
Refinery site in McKinley County, New Mexico. EPG and Atlantic Richfield
Company have a cost sharing agreement to each pay one-half of any
remediation costs at this site. EPG's share of future remediation costs is
estimated to be approximately $8 million over a 29-year period. Remediation
began in May 1995 and for the year ended December 31, 1995, EPG has
incurred approximately $2 million in remediation costs.
4 -- In December 1993, EPA issued EPG a Notice of Potential Liability for
the Colorado School of Mines Research Institute site in Golden, Colorado
ordering EPG and eleven other PRPs to clean up the site. EPA has determined
that the volume of hazardous substances sent to the site by EPG represents
less than 2.5 percent of the total volumes sent by all PRPs. Based on this
percentage, EPG's share of the potential remediation costs is estimated to
be less than $0.4 million. Remediation of the site is expected to be
completed during 1996.
5 -- EPG and another PRP have been notified about potential groundwater and
soil contamination at various sites in southeastern Utah. EPG and the other
PRP have been conducting environmental assessments at certain of these
sites and are engaged in negotiations over the appropriate allocation of
the remediation costs. Based upon currently available information, EPG
estimates its costs for remediation will be approximately $5 million over a
5-year period.
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6 -- In August 1992, EPG received a notice from the current owner of a site
in Etowah, Tennessee requesting compensation for remediation expenses
associated with the site. EPG negotiated a settlement agreement effective
August 10, 1995. In accordance with the agreement, EPG paid approximately
$0.6 million in the third quarter of 1995.
7 -- EPG and other PRPs entered into an agreement to conduct a RI/FS for a
site located in Fountain Inn, South Carolina. The RI/FS was completed in
October 1994, and EPA issued a Record of Decision in September 1995, under
which the proposed remediation and EPA oversight costs are estimated to be
$1.6 million. The allocation of these costs between EPG and the other PRPs
is currently being negotiated. EPG's share of the costs is estimated to be
approximately $0.8 million over a 5-year period.
Management believes the amount reserved as of December 31, 1995, is
sufficient to cover these and other small environmental assessments and
remediation activities.
The State of Tennessee has asserted a claim that EPG is a liable party
under state environmental laws for cleanup costs associated with a site in
Elizabethton, Tennessee. The State of Tennessee and EPA are in the preliminary
stages of investigating the nature and extent of contamination, as well as
identifying other PRPs. Since investigation is in the initial stages, EPG is
unable to estimate its potential share of any remediation costs.
EPG also has potential expenditures, of a capital nature, for the following
environmental projects:
1 -- EPG has analyzed the CAAA, and believes that the impact to the
Company's operations will be primarily in the following areas: (i)
potential required reductions in the emissions of NOx in non-attainment
areas, (ii) the requirement for air emissions permitting of existing
facilities, and (iii) compliance assurance monitoring of air emissions. EPG
anticipates capitalizing the equipment costs associated with complying with
CAAA and estimates that approximately $10 million will be spent from 1996
through 2005. When finalized, EPA's proposed compliance assurance
monitoring rules could potentially impose greater costs to the Company.
2 -- EPG conducted remediation of mercury contamination at various mercury
meter sites located within the gathering system since May 1990. As of
December 1995, EPG has remediated approximately 9,000 sites in the San Juan
Basin. The project was completed in December 1995 at a total project cost
of approximately $21 million. Since March 1994, EPG has identified
approximately 2,325 earthen siphon/dehydration pits in the San Juan Basin
for remediation and closure as required by environmental regulations. As of
December 31, 1995, approximately 2,190 pits have been remediated at a total
project cost of $12 million. These mercury and pit closure costs have been
recorded as adjustments to accumulated depreciation, as permitted by
regulatory accounting principles.
The remaining 135 earthen siphon/dehydration pits which have not been
remediated at December 31, 1995, were transferred to EPFS effective January 1,
1996. Based upon currently available information, EPFS estimates its costs for
remediation will be approximately $3.1 million over a 5-year period. EPFS has
established adequate reserves to cover these remediation activities.
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
As such information becomes available or developments occur, related accrual
amounts will be adjusted accordingly.
Legal Proceedings
See Item 3, Legal Proceedings.
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Operating Leases
Company Office Space -- Minimum annual rental commitments at December 31,
1995, are as follows:
YEAR ENDING DECEMBER 31, OPERATING LEASES
------------------------ ----------------
(IN THOUSANDS)
1996.......................................................... $ 10,175
1997.......................................................... 10,543
1998.......................................................... 10,964
1999.......................................................... 11,411
2000.......................................................... 11,912
Thereafter.................................................... 82,957
--------
Total............................................... $137,962
========
Rental expense for operating leases for 1995, 1994, and 1993 was $9
million, $9 million, and $8 million, respectively.
EPG has a lease agreement for approximately 391,207 square feet of space
which is currently used as the Company headquarters and its gas control center
in El Paso, Texas. The lease expires in May 2007, and grants EPG two 10-year
options to extend the term of the lease.
Chaco -- In February 1995, EPNC entered into a 7.75 year lease for an NGL
extraction plant which is being constructed in the San Juan Basin. The lease is
an unconditional "triple net" lease with the trustee of a special purpose trust.
The trust obtained financing for construction of the plant from a consortium of
financial institutions. The total amount financed via the operating lease will
not exceed $80 million, and the annual lease obligation will be a function of
the amount financed, a variable interest rate, and commitment and other fees.
EPNC has an option at the end of the lease term, and has an obligation upon the
occurrence of certain events, to purchase the plant for a price sufficient to
pay the entire amount financed, interest, and certain expenses. If EPNC does not
purchase the plant at the end of the lease term, it has an obligation to pay a
residual guaranty amount equal to approximately 87 percent of the amount
financed, plus interest. EPG unconditionally guaranteed all obligations of EPNC
under the lease. Construction of the plant began in April 1995. The first 400
MMcf/d of capacity at the plant is scheduled to be in service during the first
quarter of 1996, with the remaining 200 MMcf/d of capacity expected to be
available in the second quarter of 1996.
The estimated minimum rental commitments at December 31, 1995, assuming an
amount financed of $75 million and an interest rate of 6.0 percent, are as
follows:
YEAR ENDING DECEMBER 31, OPERATING LEASE
- ------------------------ ---------------
(IN THOUSANDS)
1996......................................................... $ 4,000
1997......................................................... 4,500
1998......................................................... 4,500
1999......................................................... 4,500
2000......................................................... 4,500
Thereafter................................................... 8,250
-------
Total.............................................. $30,250
=======
Management is not aware of other commitments or contingent liabilities
which would have a materially adverse effect on the Company's financial
condition or results of operations.
6. ACQUISITIONS
Eastex Energy Inc.
Effective September 1, 1995, Eastex was merged with and into El Paso
Acquisition Company, a wholly owned subsidiary of EPG. At the time of the
merger, the name of El Paso Acquisition Company was changed to Eastex.
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49
Pursuant to the merger, Eastex shareholders received either $4.50 in cash
or .1601 shares of EPG common stock for each share of Eastex common stock. The
purchase price of approximately $32 million, exclusive of acquisition costs, was
financed by the Company through approximately $13 million of available cash and
the issuance of approximately 0.7 million shares of treasury stock at a market
value of approximately $19 million. Acquisition costs of approximately $2
million have been capitalized. Total cash consideration paid, net of cash
received, was approximately $3 million. In December 1995, Eastex acquired all of
the issued and outstanding capital stock of Premier for approximately $20
million. The acquisition was funded by the Company through internally generated
funds and short-term borrowings. The cost of each acquisition has been allocated
on the basis of the estimated fair market value of the assets acquired and the
liabilities assumed. These allocations resulted in goodwill of approximately $17
million and $19 million related to the Eastex and Premier acquisitions,
respectively, and will be amortized over 40 years using the straight-line
method. Eastex had previous goodwill of approximately $5 million. The
acquisitions have each been individually accounted for as a purchase and the
Company has utilized the "push down" method of accounting.
Assets acquired, liabilities assumed, and consideration paid for each
acquisition are as follows:
EASTEX PREMIER
-------- -------
(IN THOUSANDS)
Fair value of assets acquired, including goodwill........ $121,689 $20,412
Cash acquired............................................ (12,992) --
Liabilities assumed...................................... (86,957) --
Issuance of treasury stock at market value............... (18,849) --
-------- -------
Net cash consideration paid.................... $ 2,891 $20,412
======== =======
The following consolidated net assets for Eastex are included in the
Company's December 31, 1995, Consolidated Balance Sheets:
(IN THOUSANDS)
Cash.............................................................. $ 20,210
Accounts receivable............................................... 116,443
Inventory......................................................... 6,754
Property, plant, and equipment, net............................... 5,977
Intangible assets, net............................................ 42,148
Other assets...................................................... 12,800
Accounts payable
Trade........................................................... (107,474)
Other........................................................... (774)
Other liabilities................................................. (5,276)
---------
Total net assets........................................ $ 90,808
=========
The consolidated operating results for Eastex for the months of September
1995 through December 1995 (including Premier for the month of December) are
included in the Company's consolidated results of operations for the year ended
December 31, 1995.
Mojave Pipeline Company
On June 1, 1993, the Company acquired from a wholly owned subsidiary of
Enron Corp., that subsidiary's 50 percent interest in MPC for approximately $40
million in cash, representing the approximate book value of the investment. The
acquisition, which was funded by internally generated cash flow, gave the
Company 100 percent ownership of MPC. The acquisition was accounted for using
the purchase method.
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In conjunction with the acquisition, the following liabilities were
assumed:
(IN THOUSANDS)
Fair value of assets acquired...................................... $145,643
Cash paid.......................................................... 39,396
--------
Liabilities assumed................................................ $106,247
========
The operating results of MPC are included in the Company's consolidated
results of operations for 1995, 1994, and May 1993 through December 1993. The
Company's previously owned 50 percent equity interest in MPC is included in
other-net in the Consolidated Statements of Income.
7. INCOME TAXES
The following table reflects the components of income tax expense for the
periods ended December 31:
1995 1994 1993
------- ------- -------
(IN THOUSANDS)
Current
Federal........................................... $13,170 $14,678 $42,112
State............................................. 4,505 (5,609) 8,491
------- ------- -------
17,675 9,069 50,603
------- ------- -------
Deferred
Federal........................................... 30,699 35,062 7,506
Change in enacted tax rate........................ -- -- 503
State............................................. (761) 14,332 541
------- ------- -------
29,938 49,394 8,550
------- ------- -------
Total tax expense......................... $47,613 $58,463 $59,153
======= ======= =======
The following table reflects the components of deferred tax expense for the
periods ended December 31:
1995 1994 1993
------- ------- --------
(IN THOUSANDS)
Depreciation, depletion, and amortization.......... $34,612 $33,363 $ 7,355
Financial accruals and reserves.................... (3,835) 28,176 (13,001)
Alternative minimum tax............................ (607) (15,134) 2,103
Gas cost settlements and recovery.................. 31 3,904 17,633
Change in enacted tax rate......................... -- -- 503
Other.............................................. (262) (915) (6,043)
------- -------- --------
Total deferred tax expense............... $29,939 $49,394 $ 8,550
======= ======== ========
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The following table reflects the components of the net deferred tax
liabilities at December 31:
1995 1994
-------- --------
(IN THOUSANDS)
Deferred tax liabilities
Property, plant, and equipment............................... $290,211 $275,214
Regulatory and other assets.................................. 85,309 62,168
-------- --------
Total deferred tax liability......................... 375,520 337,382
-------- --------
Deferred tax assets
Take-or-pay buy-outs, buy-downs, and prepayments............. 3,542 2,509
Accrual for regulatory issues................................ -- --
Other liabilities............................................ 63,213 55,740
Other........................................................ 17,253 15,472
-------- --------
Total deferred tax asset............................. 84,008 73,721
-------- --------
Net deferred tax liability..................................... $291,512 $263,661
======== ========
Tax expense of the Company differs from the amount computed by applying the
statutory federal income tax rate to income before taxes. The following table
outlines the reasons for the differences for the periods ended December 31:
1995 1994 1993
------- ------- -------
(IN THOUSANDS)
Tax expense at the statutory federal rate of 35% for
1995, 1994 and 1993................................. $46,541 $51,827 $52,789
Increase (decrease)
State income tax, net of federal income tax
benefit.......................................... 2,434 5,670 5,871
Change in enacted tax rate.......................... -- -- 503
Other............................................... (1,362) 966 (10)
------- ------- -------
Income tax expense.................................... $47,613 $58,463 $59,153
======= ======= =======
Effective tax rate.................................... 36% 39% 39%
======= ======= =======
As of December 31, 1995, approximately $17 million of alternative minimum
tax credits were available to offset future regular tax liabilities. These
alternative minimum tax credit carryovers have no expiration date.
Deferred credits, in the Consolidated Balance Sheets, include excess
deferrals resulting from the reduction of the statutory federal tax rate from 46
to 34 percent on July 1, 1987. Regulatory assets in the Consolidated Balance
Sheets include expected future recoveries resulting from the increase of the
statutory federal rate from 34 to 35 percent on January 1, 1993. Such amounts
have been included in EPG's offer of settlement filed with FERC in March 1996.
8. CAPITAL STOCK
Stock Options
Under EPG's employee stock option plans, options may be granted to officers
and key employees at fair market value on the date of grant, exercisable in
whole or part by the optionee after completion of 1 to 5 years of continuous
employment from the grant date. Options are also granted to non-employee members
of the Board at fair market value on the date of grant and are exercisable
immediately. Under the terms of these plans, EPG may grant SARs to certain
holders of stock options. SARs are subject to the same terms and conditions as
the related stock options. The stock option holder who has been granted tandem
SARs can elect to exercise either an option or a SAR. SARs entitle an option
holder to receive a payment equal to the difference between the option price and
the fair market value of the common stock of EPG at the date of exercise of the
SAR. To the extent a SAR is exercised, the related option is canceled, and to
the extent an option is exercised, the related SAR is canceled.
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Activity in EPG's stock option plans for 1993, 1994, and 1995 was as
follows:
EXERCISE
PRICE PER
OPTIONS SARS SHARE
--------- -------- -----------------
Balance, January 1, 1993................... 1,063,261 105,203 $13.51 to $25.69
Granted.................................. 575,000 -- 30.81 to 38.19
Exercised................................ 247,143 35,049 13.51 to 22.91
Canceled................................. 41,382 -- 19.00 to 30.81
--------- --------
Balance, December 31, 1993................. 1,349,736 70,154 $13.51 to $38.19
Granted.................................. 663,100 -- 36.88 to 39.56
Exercised................................ 50,162 22,000 13.51 to 30.81
Canceled................................. 29,983 -- 19.00 to 36.88
--------- --------
Balance, December 31, 1994................. 1,932,691 48,154 $18.14 to $39.56
Granted.................................. 709,000 -- 28.88 to 30.88
Converted in connection with Eastex
acquisition........................... 40,025 -- 15.62
Exercised................................ 38,761 -- 18.14 to 22.91
Canceled................................. 39,000 -- 29.94
--------- --------
Balance, December 31, 1995................. 2,603,955 48,154 $15.62 to $39.56
========= ========
At December 31, 1995, 1,938,953 stock options and 48,154 SARs were
exercisable at prices ranging from $15.62 to $39.56 per share.
Stock options shown as canceled in the table above may be a result of the
tandem SAR being exercised. SARs shown in the table above will be canceled when
the underlying stock options are exercised.
From April 1993 through December 1993, EPG issued 43,394 shares of common
stock in connection with EPG's employee stock option plans.
In January 1996, a grant of 1,461,500 stock options at an exercise price
per share of $31.375 was made. The options become exercisable after a period of
1 to 5 years.
The maximum number of shares for which stock options may be granted under
EPG's current stock option plans is approximately 7 million shares of common
stock, to be issued from shares held in EPG's treasury, or out of authorized but
unissued shares of EPG's common stock, or partly out of each, as determined by
the Board.
Restricted Stock
In January 1996, a grant of 133,868 restricted shares of EPG's common stock
was granted to certain officers pursuant to EPG's 1995 Incentive Compensation
Plan. These shares vest 4 years from the date of grant and have a market value
of approximately $4 million at grant date. In addition, in January 1996, a grant
of 795,000 restricted shares of EPG's common stock was granted to certain
officers pursuant to EPG's 1995 Omnibus Compensation Plan. The majority of these
shares vest only upon the attainment of certain performance measures and lapse
of time (ranging from 1 to 5 years), and have a market value of approximately
$25 million at grant date.
A total of 300, 800, and 2,300 restricted shares of EPG's common stock were
granted to certain employees during 1995, 1994, and 1993, respectively. The
market value of such shares awarded was approximately $8,250, $26,000, and
$76,000 in 1995, 1994, and 1993, respectively.
Treasury Stock
Shares repurchased are held in EPG's treasury and are expected to be used
in connection with EPG employee stock option plans and for other corporate
purposes. In October 1992, the Board authorized the
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53
repurchase of up to 2 million shares of EPG's outstanding shares of common stock
from time to time in the open market. During 1992, EPG acquired 812,773 shares
of its common stock for an aggregate value of $24 million and issued, in
connection with EPG's employee stock option plans, 628,258 shares of common
stock out of treasury stock for an aggregate value of $11 million. The 184,515
remaining shares were issued through April 1993, in connection with employee
stock option plans, for an aggregate value of $5 million.
During 1993, EPG acquired 509,095 shares of its common stock for an
aggregate value of $18 million and subsequently issued, in connection with
employee stock option plans, 22,734 shares of its common stock out of treasury
stock for an aggregate value of $0.5 million. As of December 31, 1993, EPG had
486,361 shares of treasury stock.
In November 1994, the Board authorized the repurchase of an additional 3.5
million shares of EPG's outstanding common stock from time to time in the open
market. During 1995 and 1994, EPG acquired 2,020,000 and 1,362,937 shares of its
common stock for an aggregate value of $57 million and $44 million,
respectively. In 1995 and 1994, 36,000 and 50,162 shares of EPG's common stock
were issued out of treasury stock in connection with employee stock option plans
for an aggregate value of $0.5 million and $1.8 million, respectively. In
addition, 680,000 shares of treasury stock have been used to secure benefits
under certain of the Company's benefit plans. These shares are subject to
certain restrictions. In September 1995, EPG issued approximately 656,000 shares
of treasury stock in connection with the Eastex acquisition. As of December 31,
1995, and 1994, EPG held 3,127,000 and 1,799,136 shares of treasury stock,
respectively.
Other
EPG has 25,000,000 shares of authorized preferred stock, par value $0.01
per share, none of which have been issued.
EPG filed a shelf registration statement in August 1994, pursuant to which
EPG may offer up to $400 million of unsecured debt securities, preferred stock,
and common stock from time to time as determined by market conditions. On March
10, 1995, the registration statement was declared effective by the SEC. There
were no securities issued pursuant to the shelf registration statement as of
December 31, 1995, and 1994.
9. INVENTORIES
Inventories consisted of the following at December 31:
1995 1994
---------- ----------
(IN THOUSANDS)
Materials and supplies...................................... $ 30,354 $ 34,666
Gas in storage.............................................. 6,754 --
---------- ----------
$ 37,108 $ 34,666
========== ==========
10. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
1995 1994
---------- ----------
(IN THOUSANDS)
Property, plant, and equipment, at cost..................... $3,042,516 $2,968,220
Less accumulated depreciation and depletion................. 1,158,486 1,205,637
---------- ----------
1,884,030 1,762,583
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 93,594 99,006
---------- ----------
Total property, plant, and equipment, net......... $1,977,624 $1,861,589
========== ==========
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54
11. INTANGIBLE ASSETS
Intangible assets consisted of the following at December 31:
1995 1994
---------- ----------
(IN THOUSANDS)
Goodwill.................................................... $ 42,261 $ --
Other intangibles........................................... 14,890 11,148
-------
57,151 11,148
Less accumulated amortization............................... 9,273 6,840
-------
Total intangible assets, net........................... $ 47,878 $ 4,308
=======
12. NATURE OF OPERATIONS AND SIGNIFICANT CUSTOMERS
The Company is engaged in the transportation, gathering and processing, and
marketing of natural gas. For the year ended December 31, 1995, the Company's
operating revenues were predominately derived from the transportation of natural
gas. California is the Company's principal market for the transportation of
natural gas.
The Company had gross revenues equal to, or in excess of, 10 percent of
consolidated operating revenues from the following customers for the years ended
December 31:
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
Southern California Gas Company.................... $176,460 $190,989 $238,885
Pacific Gas & Electric Company..................... 128,155 154,674 168,246
Southwest Gas Corporation.......................... --(a) --(a) 95,188
- ---------------
(a) Less than 10 percent of consolidated operating revenues.
13. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
Interest........................................... $ 76,707 $ 70,906 $ 66,773
Income taxes, net of refunds....................... 9,575 31,231 38,993
See Note 6, Acquisitions, for a discussion of the non-cash investing
transaction related to the acquisition of Eastex.
14. RECENT PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board issued SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of. SFAS No. 121 requires that long-lived assets and
certain identifiable intangibles to be held and used by an entity be reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Certain long-lived assets
and certain identifiable intangibles to be disposed of must be reported at the
lower of carrying amount or fair value less cost to sell. SFAS No. 121 also
requires that a rate-regulated enterprise recognize an impairment for the amount
of costs that a regulator excludes from the enterprise's rate base. SFAS No. 121
must be adopted no later than the fiscal year beginning after December 15, 1995.
The Company anticipates adopting SFAS No. 121 in the first quarter of 1996. As a
result of the adoption, the Company will reduce property, plant, and equipment
by a charge to earnings of approximately $19 million, net of income taxes. In
addition, in accordance with the offer of settlement filed with FERC in March
1996, management expects to write-off an impaired regulatory asset which was
50
55
established at the adoption of SFAS No. 112. The regulatory asset of $5 million,
net of income taxes, will be written off in the first quarter of 1996.
In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock-Based Compensation. SFAS No. 123 encourages entities
to adopt a fair value based method of accounting for all employee stock
compensation, as well as transactions in which an entity issues its equity
instruments to acquire goods or services from nonemployees. Those transactions
must be accounted for based on the fair value of the consideration received or
the fair value of the equity instruments issued, whichever is more reasonably
determinable. SFAS No. 123 allows an entity to continue measuring compensation
cost for a plan using the accounting principles prescribed by APB Opinion No.
25, Accounting for Stock Issued to Employees. In that case, however, companies
must also include pro forma disclosures of net income and earnings per share, as
if the fair value based method of accounting defined in SFAS No. 123 had been
applied. SFAS No. 123 is effective for fiscal years beginning after December 15,
1995. The Company adopted SFAS No. 123 in the first quarter of 1996, and elected
to continue to apply the accounting rules contained in APB No. 25.
The American Institute of Certified Public Accountants issued SOP 94-6,
Disclosure of Certain Significant Risks and Uncertainties which requires
reporting entities to include in their financial statements disclosures about
the nature of their operations, and the use of estimates in the preparation of
financial statements. In addition, if specific disclosure criteria are met, it
requires entities to include in their financial statements disclosures about
certain significant estimates and current vulnerability due to certain
concentrations. The provisions of SOP 94-6 are effective for financial
statements issued for fiscal years ending after December 15, 1995. The Company
adopted SOP 94-6 effective January 1, 1995.
15. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.
QUARTERS ENDED
------------------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ -------- --------
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNTS)
1995
Operating revenues...................... $ 408,525 $240,191 $185,150 $204,131
Operating income........................ 50,651 52,690 52,857 56,213
Net income.............................. 22,904 20,289 20,200 21,970
Earnings per common share............... 0.67 0.60 0.58 0.62
1994
Operating revenues...................... $ 227,698 $209,424 $210,805 $221,945
Operating income........................ 58,881 56,019 59,598 47,797
Net income.............................. 23,391 21,096 24,011 21,115
Earnings per common share............... 0.65 0.58 0.65 0.57
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REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
El Paso Natural Gas Company
We have audited the consolidated financial statements and the financial
statement schedule of El Paso Natural Gas Company listed in Item 14(a) of this
Form 10-K. These financial statements and the financial statement schedule are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of El Paso Natural
Gas Company as of December 31, 1995 and 1994, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement schedule
referred to above, when considered in relation to the basic financial statements
taken as a whole, presents fairly, in all material respects, the information
required to be included therein.
COOPERS & LYBRAND L.L.P.
El Paso, Texas
March 15, 1996
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SCHEDULE II
EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1995, 1994, AND 1993
(IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------- ---------- -------------------- ---------- ----------
CHARGED
BALANCE AT TO COSTS CHARGED BALANCE
BEGINNING AND TO OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
- -------------------------------------------- ---------- --------- -------- ---------- ----------
1995
Allowance for bad debts................... $ 6,155 $ 1,819 $ 440 $ 5,776(a) $ 2,638
Allowance for gas imbalances.............. 8,840 -- 1,502 2,911(c) 7,431
Allowance for take-or-pay receivables..... 9,326 -- -- 8,326 1,000
1994
Allowance for bad debts................... $ 3,868 $ 2,029 $ 734 $ 476 $ 6,155
Allowance for gas imbalances.............. 5,597 -- 3,243 -- 8,840
Allowance for take-or-pay receivables..... 19,387 -- -- 10,061 9,326
1993
Allowance for bad debts................... $ 5,084 $ -- $ 145 $ 1,361(a) $ 3,868
Allowance for gas imbalances.............. 12,097 -- -- 6,500(b) 5,597
Allowance for take-or-pay receivables..... -- 19,387 -- -- 19,387
(a) Primarily accounts charged off.
(b) Primarily accounts recovered.
(c) Primarily due to price adjustments.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information appearing under the caption "Proposal No. 1 -- Election of
Directors" in the Company's proxy statement for the 1996 Annual Meeting of
Stockholders is incorporated herein by reference. Information regarding
executive officers of the Company is presented in Items 1 and 2 of this Form
10-K under the caption "Executive Officers of the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in the
1996 proxy statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information appearing under the caption "Security Ownership of Beneficial
Owners and Management" in the 1996 proxy statement is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. Financial statements.
The following consolidated financial statements of the Company are included
in Part II, Item 8 of this report:
PAGE
----
Consolidated statements of income..................................... 26
Consolidated balance sheets........................................... 27
Consolidated statements of cash flows................................. 28
Consolidated statements of stockholders' equity....................... 29
Notes to consolidated financial statements............................ 30
Report of independent accountants..................................... 52
2. Financial statement schedules and supplementary information required to
be submitted.
Schedule II - Valuation and qualifying accounts....................... 53
Schedules other than that listed above are omitted because they are
not applicable
3. Exhibit list.......................................................... 56
(B) REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the quarter
ended December 31, 1995.
55
60
EL PASO NATURAL GAS COMPANY
EXHIBIT LIST
DECEMBER 31, 1995
3(i) -- Restated Certificate of Incorporation of EPG dated January 22, 1992.
(Form 10-K, No. 1-2700, filed January 29, 1992); Certificate of
Designation, Preferences and Rights of Series A Junior Participating
Preferred Stock of EPG, dated July 7, 1992, (Form 10-K, No. 1-2700,
filed February 3, 1993).
3(ii) -- By-laws of EPG, as amended September 1, 1994. (Form 10-K, No. 1-2700,
filed January 26, 1995).
4.B.1 -- Indenture, dated as of March 1, 1987, between EPG and Citibank, N.A.,
Trustee, with respect to EPG's 8 5/8% Debentures due 2012 (Form S-3,
No. 33-34284, filed April 20, 1990); Supplemental Indenture, dated
December 24, 1991, (Form 10-K, No. 1-2700, filed January 29, 1992).
4.B.2 -- Indenture, dated as of August 1, 1987, between EPG and Citibank,
N.A., Trustee, with respect to EPG's 9.45% Notes due 1999 (Form S-3,
No. 33-34284, filed April 20, 1990); Supplemental Indenture, dated
December 24, 1991, (Form 10-K, No. 1-2700, filed January 29, 1992).
4.B.3 -- Indenture, dated as of January 1, 1992, between EPG and Citibank,
N.A., Trustee, with respect to EPG's 6.90% Notes due 1997, 7 3/4%
Notes due 2002 and 8 5/8% Debentures due 2022 (Form 10-K, No. 1-2700,
filed January 29, 1992).
4.C -- Shareholder Rights Plan (Form 10-Q, No. 1-2700, filed November 12,
1992).
10.A -- Mojave Pipeline General Partnership Agreement by and among El Paso
Mojave Pipeline Co., HNG Mojave, Inc., and Pacific Interstate Mojave
Company, dated as of March 26, 1985, (Form 10-Q, No. 1-2700, filed
May 15, 1985); Amendment No. 1 to General Partnership Agreement dated
as of September 29, 1986, (Form 10-Q, No. 1-2700, filed May 13,
1988); Amendment No. 2 to General Partnership Agreement dated as of
September 30, 1991, (Form 10-Q, No. 1-2700, filed November 14, 1991).
10.B -- Lease, dated May 27, 1982, between EPG and First Capital Kayser
Center (Form 10-Q, No. 1-2700, filed November 14, 1991).
10.C -- Transportation Service Agreement as Amended and Restated, effective
November 1, 1993, between EPG and Pacific Gas and Electric Company.
(Form 10-K, No. 1-2700, filed January 26, 1995).
10.D -- Transportation Service Agreement as Amended and Restated, effective
July 16, 1993, between EPG and Southern California Gas Company. (Form
10-K, No. 1-2700, filed January 26, 1995).
10.E -- Transportation Service Agreement, dated August 9, 1991, and effective
September 1, 1991, between EPG and Southwest Gas Corporation for
service to Arizona; Transportation Service Agreement, dated August 9,
1991, and effective September 1, 1991, between EPG and Southwest Gas
Corporation for service to Nevada (Form 10-Q, No. 1-2700, filed
November 14, 1991); Amendatory Agreement and replacement of Exhibit B
to Transportation Service Agreement dated August 9, 1991, and
effective May 8, 1992, between EPG and Southwest Gas Corporation for
service to Nevada. (Form 10-K, No. 1-2700, filed February 3, 1993).
Exhibit B to the Transportation Service Agreement dated August 9,
1991, and effective March 1, 1994, between EPG and Southwest Gas
Corporation for service to Arizona. (Form 10-K, No. 1-2700, filed
January 26, 1995).
56
61
10.F -- Credit Agreement among Mojave Pipeline Company and Deutsche Bank AG,
New York Branch, and Swiss Bank Corporation, New York Branch,
individually and as Agents, and the Banks named therein, dated as of
September 30, 1991, and the following documents related thereto:
Sponsor Performance Agreement among EPG and Deutsche Bank AG, New
York Branch, as Collateral Agent and Deutsche Bank AG, New York
Branch and Swiss Bank Corporation, New York Branch, as Agents, dated
as of September 30, 1991; Partner Performance Agreement among El Paso
Mojave Pipeline Co. and Deutsche Bank AG, New York Branch, as
Collateral Agent and Deutsche Bank AG, New York Branch and Swiss Bank
Corporation, New York Branch, as Agents, dated as of September 30,
1991; Pledge Agreement made by El Paso Mojave Pipeline Co. with and
to Deutsche Bank AG, New York Branch (as Collateral Agent) for the
Secured Creditors, dated as of September 30, 1991; $90,000,000 Note
dated September 30, 1991, executed by Mojave Pipeline Company and
payable to Deutsche Bank AG, New York Branch; $90,000,000 Note dated
September 30, 1991, executed by Mojave Pipeline Company and payable
to Swiss Bank Corporation, New York Branch (Form 10-Q, No. 1-2700,
filed November 14, 1991); Syndication and replacement of Notes with a
$52,750,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Swiss Bank Corporation, New York
Branch; a $40,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Deutsche Bank AG, New York
Branch; a $30,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Banque Indosuez; a $20,000,000
Note dated September 30, 1991, executed by Mojave Pipeline Company
and payable to the Sumitomo Bank, Limited, Houston Agency; a
$20,000,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to the Bank of Nova Scotia; a
$17,250,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Credit Lyonnais Cayman Islands Branch
(Form 10-K, No. 1-2700, filed January 29, 1992). First Amendment to
Credit Agreement dated as effective December 23, 1992, among Mojave
Pipeline Company and Deutsche Bank AG, New York Branch and Swiss Bank
Corporation, New York Branch; Amendment to Sponsor and Partner
Performance Agreements entered into effective as of December 23,
1992; Syndication and replacement of Note for $52,750,000 payable to
Swiss Bank Corporation, New York Branch and Note for $17,250,000
payable to Credit Lyonnais Cayman Islands Branch with a $40,000,000
Note dated September 30, 1991, executed by Mojave Pipeline Company
and payable to Swiss Bank Corporation, New York Branch; and a
$30,000,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Credit Lyonnais Cayman Islands
Branch, Second Amendment to Credit Agreement dated as effective June
1, 1993, among Mojave Pipeline Company and Deutsche Bank AG, New York
Branch and Swiss Bank Corporation, New York Branch; Amended and
Restated Sponsor Performance Agreement dated as effective June 1,
1993, among El Paso Natural Gas Company and Deutsche Bank AG, New
York Branch and Swiss Bank Corporation, New York Branch; Amendment
and Ratification of Partner Documents dated as effective June 1,
1993, among EPNG Mojave, Inc. and El Paso Mojave Pipeline Co. and
Deutsche Bank AG, New York Branch and Swiss Bank Corporation, New
York Branch (Form 10-Q, No. 1-2700, filed August 16, 1993).
Replacement of $30,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Banque Indosuez with a
$30,000,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Bank of Scotland. (Form 10-Q, No.
1-2700, filed May 13, 1994).
10.G -- Master Separation Agreement and documents related thereto dated
January 15, 1992, by and among Burlington Resources Inc., EPG and
Meridian Oil Holding Inc., including Exhibits (Form 10-K, No. 1-2700,
filed January 29, 1992).
10.H -- Revolving Credit and Competitive Advance Facility Agreement dated as
of August 10, 1994 between EPG, Chemical Bank and certain other banks
(Form 10-Q, No. 1-2700, filed November 14, 1994).
+10.I -- Omnibus Compensation Plan dated as of January 1, 1992, (Amendment No.
1 to Form S-2, No. 33-45369, filed February 27, 1992).
57
62
+10.J -- 1995 Incentive Compensation Plan effective as of January 13, 1995
(Form S-8, No. 33-57553, filed February 2, 1995); Amendment No. 1 to
EPG's 1995 Incentive Compensation Plan, effective as of July 1, 1995
(Form 10-Q, No. 1-2700, filed July 21, 1995).
*+10.J.1 -- Amendment No. 2 to the 1995 Incentive Compensation Plan effective
January 1, 1996.
+10.K -- 1995 Compensation Plan for Non-Employee Directors effective as of
January 13, 1995 (Form S-8, No. 33-57553, filed February 2, 1995).
+10.L -- Stock Option Plan for Non-Employee Directors dated as of January 1,
1992, (Amendment No. 1 to Form S-2, No. 33-45369, filed February 27,
1992).
+10.M -- 1995 Omnibus Compensation Plan effective as of January 13, 1995 (Form
S-8, No. 33-57553, filed February 2, 1995); Amendment No. 1 to EPG's
1995 Omnibus Compensation Plan, effective as of July 21, 1995 (Form
10-Q, No. 1-2700, filed July 21, 1995).
+10.N -- Supplemental Benefits Plan, Amended and Restated Effective as of
January 13, 1995 (Form 10-K, No. 1-2700, filed January 26, 1995).
+10.O -- Senior Executive Survivor Benefit Plan effective January 1, 1992,
(Amendment No. 1 to Form S-2, No. 33-45369, filed February 27, 1992).
+10.P -- Deferred Compensation Plan, Amended and Restated Effective as of
January 13, 1995 (Form 10-K, No. 1-2700, filed January 26, 1995).
+10.Q -- Retirement Income Plan for Non-Employee Directors, Amended and
Restated Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
+10.R -- Key Executive Severance Protection Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700, filed
January 26, 1995).
+10.S -- Director Charitable Award Plan, Amended and Restated Effective as of
January 13, 1995 (Form 10-K, No. 1-2700, filed January 26, 1995).
*+10.S.1 -- Amendment No. 1 to the Director Charitable Award Plan effective as of
January 22, 1996.
10.T -- Receivables Purchase and Sale Agreement dated as of January 14, 1992,
between EPG, CIESCO L.P., Corporate Asset Funding Company, Inc. and
Citicorp North America, Inc. (Form 10-K, No. 1-2700, filed February
3, 1993).
+10.U -- Employment Agreement dated July 31, 1992, between EPG and William A.
Wise (Form 10-K, No. 1-2700, filed February 3, 1993).
*+10.U.1 -- Amendment to Employment Agreement dated January 29, 1996 between EPG
and William A. Wise.
*10.V -- Amended and Restated Limited Liability Company Agreement of Aguaytia
Energy, LLC entered into November 30, 1995, by and among The Maple
Gas Corporation del Peru Ltd, The Maple Gas Corporation, P.I.D.C.
Aguaytia, L.L.C., EPED Aguaytia Company, IGC Aguaytia Partners,
L.L.C., Scudder Latin American Power I-P L.D.C., and PMDC Aguaytia,
Ltd.
+10.W -- Letter Agreement dated February 22, 1991, between EPG and Britton
White, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
+10.X -- Letter Agreement dated January 13, 1995, between EPG and William A.
Wise (Form 10-K, No. 1-2700, filed January 26, 1995).
58
63
10.Y -- Participation and Credit Agreement dated as of February 9, 1995,
among EPG, El Paso New Chaco Company, State Street Bank and Trust
Company, Chemical Bank, as Agent, the Note Holders Signatories and
the Certificate Holders Signatories (without exhibits and schedules,
except for the schedule of defined terms), and the following
documents related thereto: Lease Agreement dated as of February 9,
1995, between State Street Bank and Trust Company and El Paso New
Chaco Company, Support Agreement between El Paso New Chaco Company
and State Street Bank and Trust Company dated as of February 9, 1995;
Guaranty Agreement by EPG in favor of Chemical Bank, as Agent, and
Each of the Participants as of February 9, 1995; Sponsor Agreement by
EPG in favor of State Street Bank and Trust Company, as of February
9, 1995; Mortgage, Assignment, Security Agreement and Financing
Statement, executed February 7, 1995, between State Street Bank and
Trust Company (Mortgagor) and Chemical Bank (Mortgagee); Security
Agreement among State Street Bank and Trust Company and Chemical
Bank, as Agent, dated February 9, 1995 (Form 10-Q, No. 1-2700, filed
April 28, 1995).
*+10.Z -- Letter dated February 4, 1992 between EPG and Michael C. Holland.
*11 -- Computation of Earnings per Common Share.
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*21 -- Subsidiaries of the Registrant.
*23 -- Consent of Experts.
*27 -- Financial Data Schedule.
Each exhibit identified on this Exhibit List is filed as a part of this
report. Exhibits not incorporated by reference to a prior filing are designated
by an asterisk; all exhibits not so designated are incorporated herein by
reference to a prior filing as indicated. Exhibits designated with a "+"
constitute a management contract or compensatory plan or arrangement required to
be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
59
64
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
EL PASO NATURAL GAS COMPANY
Registrant
By /s/ WILLIAM A. WISE
William A. Wise
Chairman of the Board,
President, and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of El Paso
Natural Gas Company and in the capacities and on the date indicated:
SIGNATURE TITLE DATE
- ----------------------------------------------- ------------------------- ---------------
/s/ WILLIAM A. WISE Chairman of the Board, March 15, 1996
(William A. Wise) President, Chief
Executive Officer, and
Director
/s/ H. BRENT AUSTIN Executive Vice President March 15, 1996
(H. Brent Austin) and Chief Financial
Officer
/s/ THOMAS E. RICKS Vice President, March 15, 1996
(Thomas E. Ricks) Controller, and Chief
Accounting Officer
/s/ BYRON ALLUMBAUGH Director March 15, 1996
(Byron Allumbaugh)
/s/ EUGENIO GARZA LAGUERA Director March 15, 1996
(Eugenio Garza Laguera)
/s/ JAMES F. GIBBONS Director March 15, 1996
(James F. Gibbons)
/s/ BEN F. LOVE Director March 15, 1996
(Ben F. Love)
/s/ KENNETH L. SMALLEY Director March 15, 1996
(Kenneth L. Smalley)
/s/ MALCOLM WALLOP Director March 15, 1996
(Malcolm Wallop)
60
65
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ---------- ------------------------------------------------------------------------
3(i) -- Restated Certificate of Incorporation of EPG dated January 22, 1992.
(Form 10-K, No. 1-2700, filed January 29, 1992); Certificate of
Designation, Preferences and Rights of Series A Junior Participating
Preferred Stock of EPG, dated July 7, 1992, (Form 10-K, No. 1-2700,
filed February 3, 1993).
3(ii) -- By-laws of EPG, as amended September 1, 1994. (Form 10-K, No. 1-2700,
filed January 26, 1995).
4.B.1 -- Indenture, dated as of March 1, 1987, between EPG and Citibank, N.A.,
Trustee, with respect to EPG's 8 5/8% Debentures due 2012 (Form S-3,
No. 33-34284, filed April 20, 1990); Supplemental Indenture, dated
December 24, 1991, (Form 10-K, No. 1-2700, filed January 29, 1992).
4.B.2 -- Indenture, dated as of August 1, 1987, between EPG and Citibank,
N.A., Trustee, with respect to EPG's 9.45% Notes due 1999 (Form S-3,
No. 33-34284, filed April 20, 1990); Supplemental Indenture, dated
December 24, 1991, (Form 10-K, No. 1-2700, filed January 29, 1992).
4.B.3 -- Indenture, dated as of January 1, 1992, between EPG and Citibank,
N.A., Trustee, with respect to EPG's 6.90% Notes due 1997, 7 3/4%
Notes due 2002 and 8 5/8% Debentures due 2022 (Form 10-K, No. 1-2700,
filed January 29, 1992).
4.C -- Shareholder Rights Plan (Form 10-Q, No. 1-2700, filed November 12,
1992).
10.A -- Mojave Pipeline General Partnership Agreement by and among El Paso
Mojave Pipeline Co., HNG Mojave, Inc., and Pacific Interstate Mojave
Company, dated as of March 26, 1985, (Form 10-Q, No. 1-2700, filed
May 15, 1985); Amendment No. 1 to General Partnership Agreement dated
as of September 29, 1986, (Form 10-Q, No. 1-2700, filed May 13,
1988); Amendment No. 2 to General Partnership Agreement dated as of
September 30, 1991, (Form 10-Q, No. 1-2700, filed November 14, 1991).
10.B -- Lease, dated May 27, 1982, between EPG and First Capital Kayser
Center (Form 10-Q, No. 1-2700, filed November 14, 1991).
10.C -- Transportation Service Agreement as Amended and Restated, effective
November 1, 1993, between EPG and Pacific Gas and Electric Company.
(Form 10-K, No. 1-2700, filed January 26, 1995).
10.D -- Transportation Service Agreement as Amended and Restated, effective
July 16, 1993, between EPG and Southern California Gas Company. (Form
10-K, No. 1-2700, filed January 26, 1995).
10.E -- Transportation Service Agreement, dated August 9, 1991, and effective
September 1, 1991, between EPG and Southwest Gas Corporation for
service to Arizona; Transportation Service Agreement, dated August 9,
1991, and effective September 1, 1991, between EPG and Southwest Gas
Corporation for service to Nevada (Form 10-Q, No. 1-2700, filed
November 14, 1991); Amendatory Agreement and replacement of Exhibit B
to Transportation Service Agreement dated August 9, 1991, and
effective May 8, 1992, between EPG and Southwest Gas Corporation for
service to Nevada. (Form 10-K, No. 1-2700, filed February 3, 1993).
Exhibit B to the Transportation Service Agreement dated August 9,
1991, and effective March 1, 1994, between EPG and Southwest Gas
Corporation for service to Arizona. (Form 10-K, No. 1-2700, filed
January 26, 1995).
66
EXHIBIT
NUMBER DESCRIPTION
- ---------- ------------------------------------------------------------------------
10.F -- Credit Agreement among Mojave Pipeline Company and Deutsche Bank AG,
New York Branch, and Swiss Bank Corporation, New York Branch,
individually and as Agents, and the Banks named therein, dated as of
September 30, 1991, and the following documents related thereto:
Sponsor Performance Agreement among EPG and Deutsche Bank AG, New
York Branch, as Collateral Agent and Deutsche Bank AG, New York
Branch and Swiss Bank Corporation, New York Branch, as Agents, dated
as of September 30, 1991; Partner Performance Agreement among El Paso
Mojave Pipeline Co. and Deutsche Bank AG, New York Branch, as
Collateral Agent and Deutsche Bank AG, New York Branch and Swiss Bank
Corporation, New York Branch, as Agents, dated as of September 30,
1991; Pledge Agreement made by El Paso Mojave Pipeline Co. with and
to Deutsche Bank AG, New York Branch (as Collateral Agent) for the
Secured Creditors, dated as of September 30, 1991; $90,000,000 Note
dated September 30, 1991, executed by Mojave Pipeline Company and
payable to Deutsche Bank AG, New York Branch; $90,000,000 Note dated
September 30, 1991, executed by Mojave Pipeline Company and payable
to Swiss Bank Corporation, New York Branch (Form 10-Q, No. 1-2700,
filed November 14, 1991); Syndication and replacement of Notes with a
$52,750,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Swiss Bank Corporation, New York
Branch; a $40,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Deutsche Bank AG, New York
Branch; a $30,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Banque Indosuez; a $20,000,000
Note dated September 30, 1991, executed by Mojave Pipeline Company
and payable to the Sumitomo Bank, Limited, Houston Agency; a
$20,000,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to the Bank of Nova Scotia; a
$17,250,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Credit Lyonnais Cayman Islands Branch
(Form 10-K, No. 1-2700, filed January 29, 1992). First Amendment to
Credit Agreement dated as effective December 23, 1992, among Mojave
Pipeline Company and Deutsche Bank AG, New York Branch and Swiss Bank
Corporation, New York Branch; Amendment to Sponsor and Partner
Performance Agreements entered into effective as of December 23,
1992; Syndication and replacement of Note for $52,750,000 payable to
Swiss Bank Corporation, New York Branch and Note for $17,250,000
payable to Credit Lyonnais Cayman Islands Branch with a $40,000,000
Note dated September 30, 1991, executed by Mojave Pipeline Company
and payable to Swiss Bank Corporation, New York Branch; and a
$30,000,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Credit Lyonnais Cayman Islands
Branch, Second Amendment to Credit Agreement dated as effective June
1, 1993, among Mojave Pipeline Company and Deutsche Bank AG, New York
Branch and Swiss Bank Corporation, New York Branch; Amended and
Restated Sponsor Performance Agreement dated as effective June 1,
1993, among El Paso Natural Gas Company and Deutsche Bank AG, New
York Branch and Swiss Bank Corporation, New York Branch; Amendment
and Ratification of Partner Documents dated as effective June 1,
1993, among EPNG Mojave, Inc. and El Paso Mojave Pipeline Co. and
Deutsche Bank AG, New York Branch and Swiss Bank Corporation, New
York Branch (Form 10-Q, No. 1-2700, filed August 16, 1993).
Replacement of $30,000,000 Note dated September 30, 1991, executed by
Mojave Pipeline Company and payable to Banque Indosuez with a
$30,000,000 Note dated September 30, 1991, executed by Mojave
Pipeline Company and payable to Bank of Scotland. (Form 10-Q, No.
1-2700, filed May 13, 1994).
67
EXHIBIT
NUMBER DESCRIPTION
- ---------- ------------------------------------------------------------------------
10.G -- Master Separation Agreement and documents related thereto dated
January 15, 1992, by and among Burlington Resources Inc., EPG and
Meridian Oil Holding Inc., including Exhibits (Form 10-K, No. 1-2700,
filed January 29, 1992).
10.H -- Revolving Credit and Competitive Advance Facility Agreement dated as
of August 10, 1994 between EPG, Chemical Bank and certain other banks
(Form 10-Q, No. 1-2700, filed November 14, 1994).
+10.I -- Omnibus Compensation Plan dated as of January 1, 1992, (Amendment No.
1 to Form S-2, No. 33-45369, filed February 27, 1992).
+10.J -- 1995 Incentive Compensation Plan effective as of January 13, 1995
(Form S-8, No. 33-57553, filed February 2, 1995); Amendment No. 1 to
EPG's 1995 Incentive Compensation Plan, effective as of July 1, 1995
(Form 10-Q, No. 1-2700, filed July 21, 1995).
*+10.J.1 -- Amendment No. 2 to the 1995 Incentive Compensation Plan effective
January 1, 1996.
+10.K -- 1995 Compensation Plan for Non-Employee Directors effective as of
January 13, 1995 (Form S-8, No. 33-57553, filed February 2, 1995).
+10.L -- Stock Option Plan for Non-Employee Directors dated as of January 1,
1992, (Amendment No. 1 to Form S-2, No. 33-45369, filed February 27,
1992).
+10.M -- 1995 Omnibus Compensation Plan effective as of January 13, 1995 (Form
S-8, No. 33-57553, filed February 2, 1995); Amendment No. 1 to EPG's
1995 Omnibus Compensation Plan, effective as of July 21, 1995 (Form
10-Q, No. 1-2700, filed July 21, 1995).
+10.N -- Supplemental Benefits Plan, Amended and Restated Effective as of
January 13, 1995 (Form 10-K, No. 1-2700, filed January 26, 1995).
+10.O -- Senior Executive Survivor Benefit Plan effective January 1, 1992,
(Amendment No. 1 to Form S-2, No. 33-45369, filed February 27, 1992).
+10.P -- Deferred Compensation Plan, Amended and Restated Effective as of
January 13, 1995 (Form 10-K, No. 1-2700, filed January 26, 1995).
+10.Q -- Retirement Income Plan for Non-Employee Directors, Amended and
Restated Effective as of January 13, 1995 (Form 10-K, No. 1-2700,
filed January 26, 1995).
+10.R -- Key Executive Severance Protection Plan, Amended and Restated
Effective as of January 13, 1995 (Form 10-K, No. 1-2700, filed
January 26, 1995).
+10.S -- Director Charitable Award Plan, Amended and Restated Effective as of
January 13, 1995 (Form 10-K, No. 1-2700, filed January 26, 1995).
*+10.S.1 -- Amendment No. 1 to the Director Charitable Award Plan effective as of
January 22, 1996.
10.T -- Receivables Purchase and Sale Agreement dated as of January 14, 1992,
between EPG, CIESCO L.P., Corporate Asset Funding Company, Inc. and
Citicorp North America, Inc. (Form 10-K, No. 1-2700, filed February
3, 1993).
+10.U -- Employment Agreement dated July 31, 1992, between EPG and William A.
Wise (Form 10-K, No. 1-2700, filed February 3, 1993).
*+10.U.1 -- Amendment to Employment Agreement dated January 29, 1996 between EPG
and William A. Wise.
68
EXHIBIT
NUMBER DESCRIPTION
- ---------- ------------------------------------------------------------------------
*10.V -- Amended and Restated Limited Liability Company Agreement of Aguaytia
Energy, LLC entered into November 30, 1995, by and among The Maple
Gas Corporation del Peru Ltd, The Maple Gas Corporation, P.I.D.C.
Aguaytia, L.L.C., EPED Aguaytia Company, IGC Aguaytia Partners,
L.L.C., Scudder Latin American Power I-P L.D.C., and PMDC Aguaytia,
Ltd.
+10.W -- Letter Agreement dated February 22, 1991, between EPG and Britton
White, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
+10.X -- Letter Agreement dated January 13, 1995, between EPG and William A.
Wise (Form 10-K, No. 1-2700, filed January 26, 1995).
10.Y -- Participation and Credit Agreement dated as of February 9, 1995,
among EPG, El Paso New Chaco Company, State Street Bank and Trust
Company, Chemical Bank, as Agent, the Note Holders Signatories and
the Certificate Holders Signatories (without exhibits and schedules,
except for the schedule of defined terms), and the following
documents related thereto: Lease Agreement dated as of February 9,
1995, between State Street Bank and Trust Company and El Paso New
Chaco Company, Support Agreement between El Paso New Chaco Company
and State Street Bank and Trust Company dated as of February 9, 1995;
Guaranty Agreement by EPG in favor of Chemical Bank, as Agent, and
Each of the Participants as of February 9, 1995; Sponsor Agreement by
EPG in favor of State Street Bank and Trust Company, as of February
9, 1995; Mortgage, Assignment, Security Agreement and Financing
Statement, executed February 7, 1995, between State Street Bank and
Trust Company (Mortgagor) and Chemical Bank (Mortgagee); Security
Agreement among State Street Bank and Trust Company and Chemical
Bank, as Agent, dated February 9, 1995 (Form 10-Q, No. 1-2700, filed
April 28, 1995).
*+10.Z -- Letter dated February 4, 1992 between EPG and Michael C. Holland.
*11 -- Computation of Earnings per Common Share.
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*21 -- Subsidiaries of the Registrant.
*23 -- Consent of Experts.
*27 -- Financial Data Schedule.
Each exhibit identified on this Exhibit List is filed as a part of this
report. Exhibits not incorporated by reference to a prior filing are designated
by an asterisk; all exhibits not so designated are incorporated herein by
reference to a prior filing as indicated. Exhibits designated with a "+"
constitute a management contract or compensatory plan or arrangement required to
be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.