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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, 1994
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 74-0608280
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
ONE PAUL KAYSER CENTER
100 NORTH STANTON STREET, EL PASO, TEXAS 79901
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (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
6.90% NOTES DUE 1997
9.45% NOTES DUE 1999
7 3/4% NOTES DUE 2002
8 5/8% DEBENTURES DUE 2012
8 5/8% DEBENTURES DUE 2022
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. /X/
STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT.
Aggregate market value of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of January 12,
1995, computed by reference to the closing sale price of the registrant's common
stock on the New York Stock Exchange on such date: $1,066,063,169.
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 January
12, 1995: 35,387,989.
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
1995 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
- -------- ------- ----
PART I
1. and 2. Business and Properties.................................................... 1
3. Legal Proceedings.......................................................... 9
4. Submission of Matters to a Vote of Security Holders........................ 10
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters...... 11
6. Selected Financial Data.................................................... 12
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 13
8. Financial Statements and Supplementary Data................................ 23
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure............................................................... 48
PART III
10. Directors and Executive Officers of the Registrant......................... 48
11. Executive Compensation..................................................... 48
12. Security Ownership of Certain Beneficial Owners and Management............. 48
13. Certain Relationships and Related Transactions............................. 48
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............ 49
Signatures................................................................. 53
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Introduction
El Paso Natural Gas Company, 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. As used herein, "Company" refers to El Paso Natural
Gas Company and its subsidiaries, and "EPG" refers to El Paso Natural Gas
Company, unless the context otherwise requires.
At December 31, 1991, EPG was a wholly owned subsidiary of Burlington
Resources Inc. ("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 (the "Offering"). 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.
El Paso Gas Marketing Company ("EPGM") was incorporated in October 1992 as
a wholly owned subsidiary of EPG. EPGM commenced operations on November 1, 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.
El Paso Field Services Company ("EPFS") was incorporated in June 1993 as a
wholly owned subsidiary of EPG. EPFS was formed for the purpose of owning,
operating, acquiring, and/or constructing natural gas gathering, processing, and
other related field services activities.
On June 1, 1993, the Company acquired from a wholly owned subsidiary of
Enron Corp., that subsidiary's 50 percent interest in Mojave Pipeline Company
("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. MPC was formed 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.
Components of Consolidated Operating Revenues
The following table sets forth the components of the Company's consolidated
operating revenues:
YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Reservation........................................ $506,122 $483,471 $346,027
Transportation..................................... 41,102 59,631 141,789
Gas and liquid sales............................... 225,857 280,839 237,965
Gathering and processing........................... 66,581 51,427 41,759
All other.......................................... 30,210 33,560 35,272
-------- -------- --------
Total.................................... $869,872 $908,928 $802,812
======== ======== ========
In 1994, natural gas deliveries to Southern California Gas Company
("SoCal") and Pacific Gas & Electric Company ("PG&E") accounted for 22 percent
and 18 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.
EL PASO NATURAL GAS COMPANY
Operating Environment
EPG's pipeline facilities, services, and rates are regulated by the Federal
Energy Regulatory Commission ("FERC") in accordance with the Natural Gas Act of
1938 ("NGA") and the Natural Gas Policy Act of
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1978 ("NGPA"). Prior to the mid-1980s, EPG was engaged primarily in the business
of purchasing gas from producers at the wellhead and reselling such gas to local
distribution companies. Since 1984, the natural gas transmission industry has
undergone a major transformation in response to sweeping changes in market
conditions and regulatory policies. These developments have resulted in: (i) the
emergence of a nationwide spot market for natural gas and increasing competition
in natural gas markets; (ii) a restructuring of the contractual relationships
between pipelines and their traditional customers resulting in an increasing
displacement of sales service by transportation service; and (iii) the
renegotiation of gas purchase contracts between pipelines and producers to
reduce purchase obligations, reform pricing provisions, and settle take-or-pay
claims.
Beginning in April 1992, FERC issued a series of orders (the "Restructuring
Rules") directing a number of significant changes to the structure of the
services provided by interstate natural gas pipelines. The Restructuring Rules
are intended principally to assure "comparability" (i.e., that pipeline and
non-pipeline gas merchants are 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. Under the Restructuring Rules' 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 rate design, return on equity and
related taxes were excluded from reservation charges but were recovered along
with variable costs through volumetric rates, which were rates paid for actual
volumes transported on the pipeline. Generally, under the Restructuring Rules'
rate design, volumetric rates are considerably lower than under the previously
required rate design, and pipeline earnings are less sensitive to variations in
actual throughput.
EPG is directly connected to three of the nation's most prolific gas
producing areas -- the San Juan, Permian, and Anadarko Basins. During 1994, EPG
delivered 1.3 trillion cubic feet ("Tcf") of natural gas, accounting for
approximately 6 percent of estimated total 1994 United States consumption.
EPG's system consists of approximately 17,000 miles of pipeline with 78
mainline compressor stations having an aggregate installed horsepower of
approximately 1.0 million. The system's present natural gas delivery capacity to
California and East-of-California markets, as discussed below, is approximately
4.6 billion cubic feet per day ("Bcf/d").
EPG's present capacity to deliver natural gas to California, the second
largest natural gas market in the United States, is approximately 3.3 Bcf/d.
EPG's system currently provides 48 percent of the total interstate pipeline
capacity serving the State. In 1994, EPG delivered approximately 40 percent of
all the natural gas consumed in California.
Demand for natural gas in the California market is projected to be less
than capacity for some time to come. EPG maintains a strong competitive position
in the market by virtue of the fact that its pipeline is, and is expected to
remain, the lowest-cost transporter of natural gas to California and the
principal means of moving gas from the San Juan Basin to the California border.
EPG's pipeline capacity to California is currently fully subscribed under
long-term contracts which provide for the payment of fixed reservation charges.
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's East-of-California market also
includes deliveries to the cities of Ciudad Juarez, Cananea, and Hermosillo in
northern Mexico, and the Samalayuca Power Plant outside of Ciudad Juarez. EPG's
delivery capacity to these East-of-California markets is approximately 1.3
Bcf/d.
Since the late 1980s, in response to changing market demands, EPG has been
delivering substantial quantities of gas from the San Juan Basin to
interconnecting pipelines for ultimate redelivery to off-system markets on the
Gulf Coast and in the Midwest. This alternate routing has been effectuated by
exchanges ("back-hauls") between EPG and an interconnecting pipeline. Volumes of
gas, which the interconnecting pipeline is otherwise scheduled to deliver to EPG
for redelivery in EPG's traditional markets, are traded for like volumes of San
Juan 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
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San Juan Basin and Permian Basin bi-directional, total delivery capacity to
off-system markets east of EPG's system can be as high as 1.1 Bcf/d depending on
the level of demand elsewhere on EPG's system. Although their 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.
Set forth below is a breakdown of EPG's natural gas deliveries by market
area for the periods indicated (volumes shown are in million cubic feet per day
("MMcf/d")):
YEAR ENDED DECEMBER 31,
-------------------------
1994 1993 1992
----- ----- -----
California.................................................. 2,257 2,288 2,551
East-of-California.......................................... 630 599 596
Off-system.................................................. 747 691 560
----- ----- -----
Total throughput.................................. 3,634 3,578 3,707
===== ===== =====
Rate Matters
In July 1991, EPG filed for FERC approval of new system rates and placed
the proposed new rates into effect on January 1, 1992, subject to refund. In
July 1992, EPG again filed for new system 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. In the July
1992 filing, EPG's rate base increased from $752 million to approximately $1.2
billion. 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 filed in January 1993 to
supersede EPG's December 1992 compliance filing. As required by the FERC order,
EPG filed revised rates in September 1993, which implemented the settlement
agreement effective October 1, 1993.
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 $56.7 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 $56.7 million of underground storage facility costs. Such costs
are being recovered through December 31, 1996, by a demand charge mechanism.
Producer Settlement and Cost Recovery
Since 1987, EPG has incurred approximately $1.5 billion in buy-out and
buy-down costs 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. 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, 1994, EPG had recovered approximately $1.0 billion. EPG has
established a reserve based on current throughput projections, for that portion
of the receivables balance which is unlikely to be collected over the period
through March 1996. The balance of this reserve was $9 million at December 31,
1994.
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 approved an order, subject to rehearing, resolving all but one of the
outstanding issues regarding EPG's take-or-pay proceedings. However, certain of
EPG's customers have sought review of the eligibility of certain costs for which
EPG has received FERC approval for recovery. The remaining 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. In June
1994, FERC affirmed a 1993
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decision of an Administrative Law Judge ("ALJ") 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 July 1994, EPG filed
for rehearing of the June 1994 order. In accordance with the FERC decision, EPG
refunded $34 million, inclusive of interest, to its customers in September 1994.
In November 1994, FERC issued an order which denied EPG's request for rehearing.
EPG has filed a petition with the United States Court of Appeals for the
District of Columbia Circuit ("Court of Appeals") for the review of the June
1994 order.
In January 1992, EPG completed a sale of substantially all of its remaining
take-or-pay buy-out and buy-down receivables. See Item 7 -- Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Financial Condition and Liquidity -- Producer Settlement and Cost
Recovery.
Gathering and Processing Facilities
In January 1994, EPG filed an application with FERC seeking an order which
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.
EPG intends, effective January 1, 1996, to transfer the facilities which
are subject to the January 1994 application together with its nonjurisdictional
gathering and processing facilities to EPFS. Such facilities are used for
gathering and other nonjurisdictional functions and are an inherent part of
EPG's current gathering operations. The facilities to be transferred consist of
approximately 6,700 miles of various sized pipelines, compressors with an
aggregate installed horsepower of 40,600, and various treating and processing
plants.
Several producers and other shippers filed protests and requests for a
formal hearing of the January 1994 application. The primary issues raised in the
protests focus on the extent of competition in EPG's producing basins and the
proper functionalization of its facilities. In response to the producer and
shipper protests, EPG made a filing in March 1994 asserting that the protests
raise issues already settled under EPG's settlement agreement.
In May 1994, FERC issued a series of orders which clarified its policy
regarding the regulation of gathering facilities. Under the policy announced in
these orders, FERC will have no authority to regulate the rates, terms, and
conditions that apply to service through gathering facilities owned by an
affiliate of a pipeline, except where the gatherer acts in concert with its
pipeline affiliate to frustrate FERC's effective regulation over interstate
transportation services. Although FERC has stated it will evaluate applications
to deregulate gathering and processing facilities on a case by case basis,
management believes EPG's January 1994 application will be approved.
Gas Supply
During 1994, approximately 219 wells first delivered gas into EPG's system.
The total gas well availability physically connected to EPG's gathering systems
was approximately 1.5 Bcf/d at year-end 1994. During 1994, EPG received an
average of 2.7 Bcf/d from physical points interconnected with other pipelines or
from receipt points pursuant to transportation and exchange agreements. EPG's
maximum mainline system inlet capacity is 4.7 Bcf/d.
System Expansions
In April 1992, EPG completed the addition of 400 MMcf/d of mainline
capacity from the San Juan Basin to the California border. This addition is
committed pursuant to firm long-term contracts with fixed reservation charges.
EPG also completed a system modification making an existing pipeline segment
linking the San Juan Basin and Permian Basin bi-directional to allow for the
eastward movement of up to 435 MMcf/d, of which 255 MMcf/d is committed pursuant
to firm contracts through June 1995. The total cost of the expansion and
modification projects was approximately $250 million.
In July 1992, EPG filed an application with FERC, which was amended in
November 1992, to expand the delivery capacity of its system in the vicinity of
Yuma, Arizona and, through an extension of its system south to San Luis Rio
Colorado, Sonora, Mexico, to serve northern Mexican markets. The proposed
expansion would have provided shippers the opportunity to deliver natural gas to
Mexican markets in northern
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Baja California via new pipeline capacity of 348 MMcf/d. In June 1994, EPG
withdrew the July 1992 application, citing delays in the conversion to natural
gas and expansion of the existing Benito Juarez Power Plant in Rosarito, Baja
California Norte, Mexico. In withdrawing the pending application, EPG emphasized
that it is not abandoning the project. At such time as the Comision Federal de
Electricidad ("CFE"), the Mexican government-owned utility, proceeds with its
plans for the Benito Juarez Power Plant, EPG may refile its application.
EPG 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 CFE. In August 1994, EPG
increased its prospective ownership interest in the Samalayuca II Power Plant
from 10 percent to 20 percent. CFE and the consortium signed a trust agreement
in August 1994. Additional annexes to the trust agreement are currently being
negotiated with CFE. The trust agreement, together with the annexes, will form
the basis for seeking international financing for the Samalayuca II Power Plant
project.
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
and to an existing power plant in the same location. The proposed expansion
would provide an additional 300 MMcf/d of capacity at a cost of approximately
$57 million. In November 1993, FERC issued an order which approved the proposed
border crossing facility south of Clint, Texas that would connect EPG's
facilities with facilities in Mexico. FERC deferred action on the remainder of
the March 1993 filing until EPG demonstrates that it has executed long-term
contracts or binding precedent agreements for a substantial amount of the firm
capacity of the proposed facilities. FERC required the executed contracts or
agreements by January 1995. EPG has advised FERC that it does not have the
contracts or agreements at this time. EPG has requested that FERC not dismiss
the March 1993 application. Management believes that Mexico wants and needs this
natural gas project and the process of obtaining contracts is ongoing. In
December 1993, PG&E, SoCal, and the California Public Utilities Commission
("CPUC") jointly filed a motion with FERC seeking clarification or rehearing of
the November 1993 FERC order on the Samalayuca II Power Plant project discussed
above.
In April 1994, EPG filed an application with FERC for a certificate of
public convenience and necessity to build a 98 mile pipeline to parallel and
loop its existing Havasu Crossover Line. 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. The project is
expected to cost approximately $62 million. At the request of several of EPG's
customers, FERC held a technical conference in August 1994 with respect to the
April 1994 application. The application is currently pending before FERC.
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 $26 million. The
proposed expansion would accommodate increased volumes and provide markets with
enhanced access to San Juan Basin gas supplies. FERC held a technical conference
in August 1994 with respect to the June 1994 application. The application is
currently pending before FERC.
Master Separation Agreement
In contemplation of the separation of EPG from all other BR-controlled
entities, EPG, BR, and Meridian Oil Holding Inc. ("Meridian"), a wholly owned
subsidiary of BR, engaged in a comprehensive review of business and contractual
relationships necessary and appropriate for the efficient and effective business
operations and long-term planning of both EPG and Meridian. These business
relationships are addressed in detail in a Master Separation Agreement (the
"Separation Agreement"), dated January 15, 1992, and related operative
agreements provided for therein.
The Separation Agreement and related operative agreements provide for
specific and detailed operating agreements, transportation service agreements,
natural gas liquids marketing agreements, and gas supply arrangements between
EPG and Meridian, including Meridian's affiliates, which are appropriate to
facilitate stand-alone operations by the companies. The Separation Agreement
also provides to Meridian certain defined preferential purchase rights,
extending for a period of five years, with respect to EPG's San Juan Basin
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gathering system which is of significant importance to the business activities
of both EPG and Meridian. In addition, the Separation Agreement specifically
addresses matters relating to the allocation of pension fund assets and
liabilities, tax sharing and allocation, right-of-way access and usage, and
indemnification rights and obligations, among other things. The contractual and
business arrangements, insofar as they relate to FERC jurisdictional service
provided by EPG to Meridian, are representative of arrangements with respect to
FERC jurisdictional services which EPG can offer to non-affiliated companies
situated similarly to Meridian. In instances where Meridian may have a right to
acquire certain assets from EPG under the Separation Agreement, including any
acquisition of the San Juan Basin gathering system, Meridian would pay EPG the
fair market value for such assets. The foregoing discussion is only a summary of
certain provisions of the Separation Agreement and the related operative
agreements provided for therein and is qualified in its entirety by reference to
the Separation Agreement and such operative agreements.
Competition
Currently, EPG faces significant competition from other companies which
transport natural gas to the California market. Competition generally occurs on
the basis of price, quality, and reliability of service.
The total present interstate pipeline capacity for delivering natural gas
to the California border is approximately 6.9 Bcf/d. In addition to EPG, three
other major interstate pipelines presently deliver natural gas to California.
Transwestern Pipeline Company ("Transwestern") has the capacity to deliver
approximately 1.1 Bcf/d from Permian, Anadarko, and San Juan Basin supply
sources. Kern River Gas Transmission ("Kern River") has the capacity to deliver
approximately 700 MMcf/d from Rocky Mountain supply sources. In 1992, Kern River
held an open season to determine interest in expanding capacity to California;
however, they have asked FERC to postpone action on their pending certificate
application which would have expanded their system capacity by 452 MMcf/d.
Pacific Gas Transmission Company ("PGT") has the capacity to deliver about 1.8
Bcf/d of Canadian gas after completion of a 755 MMcf/d expansion in November
1993. This expansion consumed 500 MMcf/d of additional market that both
Transwestern and EPG would have competed to serve. However, the impact of the
PGT expansion to EPG in 1994 was offset by an increase in demand, which resulted
from a decrease in the availability of hydroelectric power.
EPG's largest single contract for interstate capacity to California is its
1,450 MMcf/d contract with SoCal, which has a primary term ending August 31,
2006. In 1992, SoCal relinquished 300 MMcf/d pursuant to this contract (out of
an original contract demand quantity of 1,750 MMcf/d), all of which was
subsequently subscribed by new firm shippers under long-term contracts. Pursuant
to its contract, SoCal has notified EPG of its intent to exercise its second
option provided in the contract to relinquish an additional 300 MMcf/d of
capacity on January 1, 1996. From and after the January 1, 1996 relinquishment,
SoCal's contract demand quantity will remain at the 1,150 MMcf/d level for the
balance of the term. PG&E has a contract for 1,140 MMcf/d of firm capacity
rights on EPG's system. This contract has a primary term ending December 31,
1997. The amount of firm capacity rights, if any, that PG&E will maintain on
EPG's system after the expiration of the current contract cannot be determined
at this time. EPG will seek to offset future reductions in existing firm
capacity commitments through new contracts with various natural gas users in
California which are now served indirectly through SoCal and PG&E, as well as
through the development of additional East-of-California and northern Mexico
markets. In seeking new customers in California for such capacity, EPG expects
to face significant competition from the other pipelines serving that state.
EPG also faces varying degrees of competition from the use of alternative
energy sources, such as electricity, coal, and oil. However, competitive
pressure from alternative energy sources is less prevalent in EPG's market area
due to strict environmental regulations in California.
MOJAVE PIPELINE COMPANY
Operating Environment
MPC's pipeline facilities, services, and rates are regulated by FERC in
accordance with the NGA and the NGPA.
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In 1990, FERC issued orders authorizing MPC to construct and operate its
pipeline facilities, which commenced operations in March 1992. MPC's system
consists of approximately 400 miles of pipeline with one mainline compressor
station. The system's present natural gas delivery capacity is 400 MMcf/d. MPC's
only business is natural gas transportation.
Set forth below are MPC's natural gas deliveries for the periods indicated:
YEAR ENDED DECEMBER 31,
-----------------------
1994 1993 1992
--- --- ---
(MMCF/D)
Total MPC throughput....................................... 247 231 197
Mojave Pipeline Operating Company ("MPOC"), a wholly owned subsidiary of
MPC, is a Texas corporation. MPOC serves as MPC's agent in the management of
MPC's pipeline facilities and the design and construction of future MPC pipeline
expansions.
Rate Matters
MPC filed a service and rate design restructuring plan in November 1992 in
compliance with FERC's industry-wide Restructuring Rules. In March 1993, FERC
issued an order essentially approving MPC's compliance filing, subject to
changes, which were made in an amended restructuring plan in March 1993.
Several of MPC's customers filed protests and requests for rehearing of the
March 1993 FERC order. The rehearing requests were denied, and FERC approved the
amended restructuring plan in July 1993 with an effective date of August 1,
1993. In October 1993, FERC issued an order which denied requests for rehearing
of the July 1993 order. Several of MPC's customers have filed petitions with the
Court of Appeals for review of the March 1993, July 1993, and October 1993
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 Straight Fixed Variable ("SFV") rate design
rather than Modified Fixed Variable ("MFV") rate design. The application of SFV
rates requires MPC's existing firm shippers to pay a higher proportion of their
total transportation rate in the reservation component of the rate. Such
shippers have contended that FERC's application of SFV rate design to MPC
unlawfully abrogates the rate provisions of MPC's service agreements and
constitutes an unlawful rate increase. Management believes the Court of Appeals
will uphold SFV rates as applied to MPC.
Gas Supply
During 1994, MPC received an average of approximately 250 MMcf/d at
physical points of interconnection with other pipelines pursuant to
transportation agreements. MPC's designed mainline system inlet capacity is 400
MMcf/d.
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 at an estimated cost
of approximately $500 million.
In December 1993, FERC held a public conference to examine the question
raised by CPUC and PG&E regarding MPC's proposed expansion. The primary issue
was whether FERC or CPUC should have jurisdiction over the expansion. In
February 1994, FERC issued an order determining that it has exclusive
jurisdiction over MPC and its proposed expansion. In March 1994, CPUC, PG&E, and
other parties filed for rehearing or clarification of FERC's February 1994
order. The petitions for rehearing and/or clarification are pending action by
FERC. In November 1994, FERC unanimously approved an order granting MPC a
preliminary determination, subject to possible later modification, issuing the
requested certificate of public convenience and necessity for the proposed
expansion. FERC requested certain further information from the parties to
determine whether PG&E, which is currently the principal gas supplier in the
region to be served by
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the expansion project, is entitled to any compensation from MPC and/or EPG as a
result of MPC's bypass of PG&E gas service. MPC and EPG have provided FERC with
the requested information. The preliminary determination did not address the
jurisdictional issues pending before FERC on rehearing of the February 1994
order. In December 1994, MPC and other parties filed requests for rehearing of
the preliminary determination asking for reconsideration of rate and other
modifications ordered by FERC. If FERC does not make significant changes to the
preliminary determination, MPC will not go forward with the expansion. MPC
expects to receive a final FERC certificate in the second quarter of 1995.
EL PASO GAS MARKETING COMPANY
EPGM buys and sells natural gas under both short-term and long-term
transactions, capitalizing on the strength of EPG's traditional market areas, as
well as the new markets developing in the southwestern United States and
northern Mexico.
As EPG's agent, EPGM is responsible for managing EPG's gas sales
arrangements with West Coast and Southwestern utilities and municipalities. EPGM
is also responsible for managing EPG's remaining long-term gas purchase
agreements which decline to a level of 25 MMcf/d in 1995 and will continue to
decline in subsequent years.
OTHER MATTERS
Environmental
EPG is subject to extensive federal, state, and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require EPG to remove or remedy the effect on the environment of the
disposal or release of specified substances at ongoing and former operating
sites. EPG currently has environmental contingencies for the cleanup of
hazardous wastes found contaminating soil and ground and surface water. As of
December 31, 1994, EPG had a reserve of approximately $40 million to cover these
remediation activities. EPG believes the Clean Air Act Amendments of 1990
("CAAA") will impact the Company's operations in the following areas: (i)
potential required reductions in the emissions of nitrogen oxides ("NOx") in
non-attainment areas; (ii) the requirement for air emissions permitting of
existing facilities; and (iii) enhanced monitoring of air emissions. EPG
anticipates capitalizing the equipment costs associated with complying with CAAA
and estimates that approximately $30 million will be spent from 1995 through
2005. However, the United States Environmental Protection Agency's ("EPA's")
proposed enhanced monitoring rules, when finalized, could potentially impose
greater costs to the Company. Additionally, EPG estimates it will spend
approximately $14 million through 1995 for additional remediation projects of a
capital nature. Details regarding specific environmental contingencies are
presented in Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Financial Condition and
Liquidity -- Environmental and in Note 4 of Notes to Consolidated Financial
Statements.
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, and a natural gas liquid extraction plant 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.
Employees
The Company had 2,403 and 2,460 full-time employees on December 31, 1994,
and 1993, respectively.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPG as of January 12, 1995, were as follows:
OFFICER
NAME OFFICE SINCE AGE
- ----------------------- ---------------------------------------- -------- ----
William A. Wise Chairman of the Board, President, and 1983 49
Chief Executive Officer
Luino Dell'Osso, Jr. Vice Chairman of the Board and Chief 1990 55
Operating Officer
Richard Owen Baish Executive Vice President 1987 48
H. Brent Austin Senior Vice President and Chief 1992 40
Financial Officer
Michael C. Holland Senior Vice President 1982 53
Joel Richards III Senior Vice President 1990 48
John W. Somerhalder II Senior Vice President 1990 39
Larry R. Tarver Senior Vice President 1988 51
Britton White, Jr. Senior Vice President and General 1991 51
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.
Mr. Dell'Osso has been Vice Chairman of the Board of EPG since September
1994 and Chief Operating Officer since November 1990. He was Executive Vice
President from November 1990 to August 1994. He was Senior Vice President and
Chief Financial Officer of BR from April 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. Austin has been Senior Vice President and Chief Financial Officer of
EPG since April 1992. 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. Holland has been Senior Vice President of EPG since January 1991. He
was a Vice President from June 1982 to December 1990. Mr. Holland has also been
President and Chief Executive Officer of MPOC since October 1989.
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. 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.
ITEM 3. LEGAL PROCEEDINGS
In El Paso Natural Gas Company and Meridian Oil Gathering Inc. v. Amoco
Production Company, filed in Delaware Chancery Court ("the Court") on May 8,
1991, Amoco Production Company ("Amoco") alleged breaches by EPG and a then
affiliated company, Meridian Oil Gathering Inc. ("MOGI"), of certain gas
purchase, gathering, and transportation agreements pertaining to natural gas
produced by Amoco in the
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San Juan Basin. Amoco alleged breach of "favored nations" contractual provisions
regarding services to be performed by EPG, including those relating to
transportation capacity and rates. Amoco sought a court order requiring specific
performance by EPG and MOGI with respect to future transportation services and
an award of monetary damages of an undetermined amount for alleged past breaches
of contract. On March 4, 1992, the Court issued a Memorandum Opinion which,
among other things, denied Amoco's motion for partial summary judgment and
concluded that the Amoco contracts at issue do not contain the general "favored
nations" rights claimed by Amoco. The Court further concluded that EPG's and
MOGI's motions for summary judgment, seeking dismissal of Amoco's counterclaim
against MOGI, should be granted. Conoco Inc. ("Conoco") asserted claims similar
to Amoco's original claims, involving lesser quantities of gas, in a separate
Delaware Chancery Court proceeding filed on December 30, 1991, Conoco Inc. v. El
Paso Natural Gas Company. In August 1992, the Amoco and Conoco cases were
consolidated, MOGI was dismissed as a party, and Amoco and Conoco filed amended
pleadings to restate their claims in light of the court's March 4, 1992 ruling.
EPG and Conoco concluded a settlement agreement which resulted in dismissal of
the Conoco claims. Trial of the Amoco claims concluded on July 15, 1993, and
post-trial briefing and oral arguments concluded in early November 1993. On
March 29, 1994, the Court rendered a decision in favor of Amoco. As a result of
the Court's decision, EPG will be required to refund to Amoco approximately $15
million, plus accrued interest. In connection with the Amoco decision, EPG
recorded a litigation special charge of approximately $19 million in the first
quarter of 1994. After additional briefing, the Court issued its opinion
respecting certain contested damages issues on December 16, 1994. EPG intends to
appeal the final order, which will be entered as soon as the parties reach
agreement as to its form.
TransAmerican Natural Gas Corporation ("TransAmerican") has 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. The complaint,
as amended, seeks unspecified actual and exemplary damages. EPG is actively
defending the matter and has initiated collateral proceedings challenging both
the validity of TransAmerican's claims and the jurisdiction of the forum in
which they were filed. No discovery has been commenced pending resolution of
these threshold issues. Based on information available at this time, management
believes that the claims made by TransAmerican 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 United States Department of Justice ("Justice Department") terminated
an investigation of EPG's natural gas meter sales and installation practices in
the San Juan Basin on January 6, 1995. EPG and the Justice Department agreed to
a consent decree which was filed in the United States District Court for the
District of Columbia on January 12, 1995. The consent decree stipulates that EPG
may not require a well operator to purchase meter facilities or meter
installation equipment as a condition of access to its gathering system in the
San Juan Basin, and requires EPG to inform well operators that they have the
legal right to provide their own meter installation services. The consent decree
further provides that any meter installation undertaken by third parties must be
done in accordance with environmental and safety standards specified by EPG.
Moreover, EPG has the right to inspect such installations to ensure that they
conform to standards that apply uniformly on EPG's gathering system. Records of
EPG's inspection activities will be maintained to document compliance with EPG's
standards and procedures. Based on its participation in the Justice Department
investigation, management concluded that there was no evidence that EPG's meter
installation practices violated any applicable law, and no fines or monetary
penalties were imposed on EPG. The consent decree, which may be entered as a
binding, final judgment following a required sixty-day public comment period,
requires no material change in EPG's existing business practices.
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 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 1994, no matters were submitted to a vote of
security holders.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
All outstanding common stock of EPG was owned by BR until March 1992. In
March 1992, EPG completed the Offering. In June 1992, BR distributed its 31.4
million shares of EPG common stock, which represented approximately 85 percent
of EPG's outstanding common stock, to BR shareholders. As a result, BR no longer
retains an ownership interest in EPG.
EPG's common stock is traded on the New York Stock Exchange. As of January
12, 1995, the approximate number of holders of record of common stock was
22,046. 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)
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
1993
First Quarter.............................. $38.000 $30.250 $0.2750
Second Quarter............................. $40.250 $35.250 $0.2750
Third Quarter.............................. $40.375 $36.125 $0.2750
Fourth Quarter............................. $39.500 $33.750 $0.2750
In January 1995, EPG's Board of Directors ("the Board") declared a
quarterly dividend of $0.33 per share on EPG's common stock, payable on April 3,
1995 to shareholders of record on March 10, 1995.
EPG has made available a Continuous Odd-Lot Stock Sales Program ("Program")
in which shareholders of EPG owning beneficially fewer than 100 shares of EPG's
common stock ("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 a Dividend Reinvestment and Common Stock Purchase
Plan ("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,
-------------------------------------------------------------
1994 1993(E) 1992 1991 1990
--------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
For the Year:
Operating revenues............. $ 869,872 $ 908,928 $ 802,812 $ 735,196 $ 851,750
Depreciation and
amortization................ 65,037 54,051 73,229 61,300 67,098
Litigation special charge(a)... 15,062 -- -- -- --
Operating income............... 222,295 229,245 184,910 184,919 190,012
Income from continuing
operations before income
taxes....................... 148,076 150,826 123,289 140,500 128,481
Income taxes................... 58,463 59,153 46,963 51,956 44,847
Income from continuing
operations.................. 89,613 91,673 76,326 88,544 83,634
Earnings per common share --
continuing operations....... 2.45 2.46 2.12 2.82 2.66
Average common shares
outstanding................. 36,632 37,212 36,049 31,422 31,422
Cash dividends declared per
common share(b)............. 1.21 1.10 .75 -- --
At Year End:
Total assets(c)................ 2,331,771 2,269,663 2,050,729 2,301,932 3,817,896
Payable to BR, including
current portion............. -- -- -- 624,804 --
Long-term debt(d).............. 779,097 795,783 637,074 249,942 848,633
Stockholders' equity(c)........ 709,636 707,548 668,992 814,878 1,828,261
- ------------
(a) Litigation special charge related to the Amoco decision (See Item 3 -- Legal
Proceedings).
(b) Represents dividends declared subsequent to the Offering.
(c) In May 1991, EPG declared and paid a dividend of $175 million to its then
parent company, The El Paso Company ("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 Offering in 1992.
(d) Excludes current maturities.
(e) MPC was consolidated for May 1993 through December 1993.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Cash provided by operating activities was $253 million for 1994 compared
with $236 million for 1993. The increase from the previous year was primarily
due to net insurance claims received, 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.
Cash provided by operating activities was $236 million for 1993 compared
with $334 million for 1992. The decrease from the previous year was primarily
due to proceeds received in 1992 from the sale of the direct bill portion of the
take-or-pay receivables, lower take-or-pay collections in 1993, rate refund
payments resulting from the settlement agreement, and costs incurred to repair
flood damaged pipelines (see Other of this section), partially offset by
decreased tax payments in 1993.
Acquisitions
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.
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 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 Statement of Income.
The following pro forma summary presents the consolidated results of
operations of the Company as if the acquisition had occurred as of January 1,
1993 or January 1, 1992. These pro forma results have been prepared for
comparative purposes only and do not purport to be indicative of what may have
resulted had the acquisition occurred as of those dates or of results which may
occur in the future.
YEAR ENDED DECEMBER
31,
---------------------
1993 1992
-------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
Operating revenue.............................................. $922,593 $834,181
Net income..................................................... 93,102 78,603
Earnings per common share...................................... 2.50 2.18
EPG is currently in negotiations to effect a merger with Hadson
Corporation. The terms of the deal have not been finalized and are subject to
the approval of the Board.
Rates and Regulatory Matters
In July 1991, EPG filed for FERC approval of new system rates and placed
the proposed new rates into effect on January 1, 1992, subject to refund. In
July 1992, EPG again filed for new system 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. In the July
1992 filing, EPG's rate base
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increased from $752 million to approximately $1.2 billion. 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 filed in January 1993 to
supersede EPG's December 1992 compliance filing. As required by the FERC order,
EPG filed revised rates in September 1993, which implemented the settlement
agreement effective October 1, 1993. Under the settlement 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 $56.7 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 $56.7 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, 1994 was $32 million. The outstanding
balances at December 31, 1994, and 1993 were $24 million and $37 million,
respectively, of which $12 million is reflected in the current portion of other
regulatory assets for both periods and $12 million and $25 million,
respectively, are included in other regulatory assets in the Consolidated
Balance Sheet. The settlement agreement also established new depreciation rates
for certain of EPG's facilities effective January 1, 1992.
As specified in the settlement agreement, EPG is obligated to file a rate
change to be effective not later than January 1, 1996.
In January 1994, EPG filed an application with FERC seeking an order which
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.
EPG intends, effective January 1, 1996, to transfer the facilities which
are subject to the January 1994 application together with its nonjurisdictional
gathering and processing facilities to EPFS. Such facilities are used for
gathering and other nonjurisdictional functions and are an inherent part of
EPG's current gathering operations. The facilities to be transferred consist of
approximately 6,700 miles of various sized pipelines, compressors with an
aggregate installed horsepower of 40,600, and various treating and processing
plants.
Several producers and other shippers filed protests and requests for a
formal hearing of the January 1994 application. The primary issues raised in the
protests focus on the extent of competition in EPG's producing basins and the
proper functionalization of its facilities. In response to the producer and
shipper protests, EPG made a filing in March 1994 asserting that the protests
raise issues already settled under EPG's settlement agreement.
In May 1994, FERC issued a series of orders which clarified its policy
regarding the regulation of gathering facilities. Under the policy announced in
these orders, FERC will have no authority to regulate the rates, terms, and
conditions that apply to service through gathering facilities owned by an
affiliate of a pipeline, except where the gatherer acts in concert with its
pipeline affiliate to frustrate FERC's effective regulation over interstate
transportation services. Although FERC has stated it will evaluate applications
to deregulate gathering and processing facilities on a case by case basis,
management believes EPG's January 1994 application will be approved.
MPC filed a service and rate design restructuring plan in November 1992 in
compliance with FERC's industry-wide Restructuring Rules. In March 1993, FERC
issued an order essentially approving MPC's compliance filing, subject to
changes, which were made in an amended restructuring plan in March 1993.
Several of MPC's customers filed protests and requests for rehearing of the
March 1993 FERC order. The rehearing requests were denied, and FERC approved the
amended restructuring plan in July 1993 with an effective date of August 1,
1993. In October 1993, FERC issued an order which denied requests for rehearing
of the July 1993 order. Several of MPC's customers have filed petitions with the
Court of Appeals for review of the March 1993, July 1993, and October 1993
orders. These petitions are currently pending before the
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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. The application of SFV rates requires MPC's
existing firm shippers to pay a higher proportion of their total transportation
rate in the reservation component of the rate. Such shippers have contended that
FERC's application of SFV rate design to MPC unlawfully abrogates the rate
provisions of MPC's service agreements and constitutes an unlawful rate
increase. Management believes the Court of Appeals will uphold SFV rates as
applied to MPC.
MPC is required to file a rate change three years after its in-service date
of March 1, 1992. MPC expects to make a filing early in 1995.
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, 1994, and 1993, the recoupable
prepayment balances were $6 million and $9 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, 1994, EPG had recovered
approximately $1.0 billion. EPG has established a reserve, based on current
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 $9 million and $19 million at December 31, 1994, and 1993,
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 approved an order, subject to rehearing, resolving all but one of the
outstanding issues regarding EPG's take-or-pay proceedings. However, certain of
EPG's customers have sought review of the eligibility of certain costs for which
EPG has received FERC approval for recovery. The remaining 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. In June
1994, FERC affirmed a 1993 decision of an ALJ 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 July 1994, EPG filed
for rehearing of the June 1994 order. In accordance with the FERC decision, EPG
refunded $34 million, inclusive of interest, to its customers in September 1994.
In November 1994, FERC issued an order which denied EPG's request for rehearing.
EPG has filed a petition with the Court of Appeals for the review of the June
1994 order.
In January 1992, EPG completed a sale of substantially all of its remaining
take-or-pay buy-out and buy-down receivables. The sale totaled $325 million,
including $305 million of cash received at closing, which was used to repay $300
million of a payable to BR. The receivables sold in this transaction included
$104 million which was recovered through direct bill and $221 million to be
recovered through volumetric surcharge. The volumetric surcharge portion of the
sale has been accounted for as a financing transaction because EPG is subject to
certain recourse provisions related to such receivables. At December 31, 1994,
and 1993, $47 million and $87 million, respectively, of the volumetric surcharge
portion of the receivables sold remained outstanding. Amounts collected related
to the take-or-pay receivables sold are remitted to the purchasers of the
receivables.
Financing and Restructuring Transactions
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
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by market conditions. As of December 31, 1994, EPG had not requested that the
registration statement be declared effective by the Securities and Exchange
Commission.
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 which expires in five years. As of December 31,
1994, and 1993, there were no borrowings outstanding under these facilities.
Approximately $107 million and $1 million of commercial paper were outstanding
as of December 31, 1994, and 1993, respectively.
During 1992, EPG completed several transactions in preparation for its
separation from BR and to establish an appropriate capital structure for its
post-separation operations. EPG had a Commitment Agreement with BR under which
it could borrow up to $300 million and Loan Agreements for borrowings up to $500
million. The proceeds from the sale of the take-or-pay receivables, previously
discussed herein, were used to repay the borrowings under the Commitment
Agreement. In January 1992, EPG purchased notes and debentures totaling $134
million. Funds were provided by proceeds from borrowings under the Loan
Agreements. In addition, all of the outstanding 9 5/8% debentures were called
for redemption at 106.84 percent of their principal amount. In January 1992, EPG
received net proceeds of $569 million from the issuance of new debt securities.
The proceeds were used for repayment of borrowings under the Loan Agreements,
redemption of debentures, and payment of general corporate costs.
The Commitment Agreement and the Loan Agreements with BR were terminated
prior to the completion of the Offering.
In January and February 1992, EPG declared and paid dividends totaling $274
million to BR. These dividends were paid from the balance owed to EPG under an
intercorporate cash management arrangement. In March 1992, EPG completed the
Offering. The proceeds from the Offering, net of related costs, totaled
approximately $96 million. In June 1992, BR distributed its 31.4 million shares
of EPG's common stock to BR shareholders, which represented approximately 85
percent of EPG's outstanding stock. As a result, BR no longer retains an
ownership interest in EPG.
The Company, through a subsidiary, plans to enter into a 7.75 year lease.
The lease will be an unconditional "triple net" lease with the trustee of a
special purpose trust. The trust will obtain 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 and a variable interest rate. The
Company will have an option at the end of the lease term, and will have an
obligation upon the occurrence of certain events, to purchase the plant for a
price sufficient to pay the entire amount financed and accrued interest. If the
Company does not purchase the plant at the end of the lease term, it will have
an obligation to pay a residual guaranty amount equal to approximately 87
percent of the amount financed. Construction of the plant is expected to be
completed in early 1996.
Competition
Currently, EPG faces significant competition from other companies which
transport natural gas to the California market. Competition generally occurs on
the basis of price, quality, and reliability of service.
The total present interstate pipeline capacity for delivering natural gas
to the California border is approximately 6.9 Bcf/d. In addition to EPG, three
other major interstate pipelines presently deliver natural gas to California.
Transwestern has the capacity to deliver approximately 1.1 Bcf/d from Permian,
Anadarko, and San Juan Basin supply sources. Kern River has the capacity to
deliver approximately 700 MMcf/d from Rocky Mountain supply sources. In 1992,
Kern River held an open season to determine interest in expanding capacity to
California; however, they have asked FERC to postpone action on their pending
certificate application which would have expanded their system capacity by 452
MMcf/d. PGT has the capacity to deliver about 1.8 Bcf/d of Canadian gas after
completion of a 755 MMcf/d expansion in November 1993. This expansion consumed
500 MMcf/d of additional market that both Transwestern and EPG would have
competed to serve. However, the impact of the PGT expansion to EPG in 1994 was
offset by an increase in demand, which resulted from a decrease in the
availability of hydroelectric power.
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EPG's largest single contract for interstate capacity to California is its
1,450 MMcf/d contract with SoCal, which has a primary term ending August 31,
2006. In 1992, SoCal relinquished 300 MMcf/d pursuant to this contract (out of
an original contract demand quantity of 1,750 MMcf/d), all of which was
subsequently subscribed by new firm shippers under long-term contracts. Pursuant
to its contract, SoCal has notified EPG of its intent to exercise its second
option to relinquish an additional 300 MMcf/d of capacity on January 1, 1996.
From and after the January 1, 1996 relinquishment, SoCal's contract demand
quantity will remain at the 1,150 MMcf/d level for the balance of the term. PG&E
has a contract for 1,140 MMcf/d of firm capacity rights on EPG's system. This
contract has a primary term ending December 31, 1997. The amount of firm
capacity rights, if any, that PG&E will maintain on EPG's system after the
expiration of the current contract cannot be determined at this time. EPG will
seek to offset future reductions in existing firm capacity commitments through
new contracts with various natural gas users in California which are now served
indirectly through SoCal and PG&E, as well as through the development of
additional East-of-California and northern Mexico markets. In seeking new
customers in California for such capacity, EPG expects to face significant
competition from the other pipelines serving that state.
EPG also faces varying degrees of competition from the use of alternative
energy sources, such as electricity, coal, and oil. However, competitive
pressure from alternative energy sources is less prevalent in EPG's market area
due to strict environmental regulations in California.
Environmental
As of December 31, 1994, EPG had a reserve of approximately $40 million for
the following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of polychlorinated biphenyl
("PCB") contamination at certain of its facilities. The majority of the
required PCB remediation has been completed. Future PCB remediation costs
are estimated to range between $7 million and $11 million over the next 5
years.
2 -- EPG executed an Administrative Order on Consent with EPA in June 1993
to conduct a Remedial Investigation/Feasibility Study ("RI/FS") for a
Burlington Industries, Inc. ("BI") site located in Statesville, North
Carolina, that has been identified for cleanup. BI and EPG have entered
into an agreement to jointly fund the RI/FS for the site. EPG's share of
the potential remediation costs is estimated to be between $17 million and
$29 million over a 30 year period.
3 -- In November 1993, in accordance with an EPA order, EPG and Atlantic
Richfield Company ("ARCO") submitted work plans for remediation of the
subsurface at the Prewitt Refinery in McKinley County, New Mexico. EPG and
ARCO have a cost sharing agreement to each pay one-half of any remediation
costs at this site. EPG's share of the remediation costs is estimated to be
between $12 million and $20 million over a 30 year period.
4 -- In December 1993, EPA issued EPG a Notice of Liability for the
Colorado School of Mines Research Institute ("CSMRI") site in Golden,
Colorado. EPA has determined that the volume of hazardous substances sent
to the site by EPG represent less than 2.5 percent of the total volumes
sent by all the potentially responsible parties ("PRPs"). Based on this
percentage, EPG's share of the potential remediation costs is estimated to
be less than $500,000.
5 -- EPG and Texaco Exploration and Production Inc. ("Texaco") have been
conducting environmental assessments of groundwater and soil contamination
at various sites in southeastern Utah. Based upon currently available
information, EPG estimates costs for remediation will be approximately $4
million. However, costs could be higher once the environmental assessment
has been completed. EPG and Texaco are engaged in negotiations over the
appropriate allocation of the remediation costs.
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. These costs are estimated to be approximately
$1.7 million. EPG and the other PRP are engaged in negotiations over the
appropriate allocation of the alleged costs.
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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 for the site in November
1994. The proposed remediation and EPA oversight costs are estimated to be
$800,000. 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
between $300,000 and $500,000 over a 5 year period.
8 -- EPG has entered into a de minimis administrative order on consent with
EPA for EPG's share of the environmental remediation costs associated with
a site in Odessa, Texas. In accordance with the order, EPG paid total costs
of approximately $32,000 in the fourth quarter of 1994.
Management believes the amount reserved as of December 31, 1994, 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 and EPA are in the preliminary stages of
investigating the nature and extent of contamination, as well as identifying
other PRPs. Since testing 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 CAAA, and believes that these rules will impact the
Company's operations 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) enhanced monitoring of air emissions. EPG anticipates capitalizing
the equipment costs associated with complying with CAAA and estimates that
approximately $30 million will be spent from 1995 through 2005. However,
EPA's proposed enhanced monitoring rules, when finalized, could potentially
impose greater costs to the Company.
2 -- EPG has been conducting remediation of mercury contamination at
certain facilities and is replacing mercury containing meters with other
measurement devices. The project is expected to be completed in 1995 at a
cost of approximately $8 million. EPG will close and retire about 1,500
earthen siphon/dehydration pits in the San Juan Basin as required by
certain environmental regulations. The project is expected to be completed
in 1995 at a cost of approximately $6 million. The mercury remediation and
pit closure costs, which are associated with the retirement of equipment,
will be recorded as adjustments to accumulated depreciation, as permitted
by regulatory accounting.
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 or developments occur, related accrual amounts will be
adjusted accordingly.
Common Stock Transactions Subsequent to the Offering
For the years ended December 31, 1994, 1993, and 1992 EPG paid
approximately $43 million, $40 million, and $19 million in dividends,
respectively. In January 1995, the Board declared a quarterly dividend of $0.33
per share on EPG's common stock, payable on April 3, 1995 to shareholders of
record on March 10, 1995.
In October 1992, the Board authorized the repurchase of up to two million
shares of EPG's outstanding common stock from time to time in the open market.
Shares repurchased are held in EPG's treasury and are expected to be used in
connection with EPG employee stock option plans to minimize dilution to existing
shareholders. During 1992, EPG acquired 812,773 shares of its common stock for
an aggregate value of $24 million and reissued, in connection with 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 reissued
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 reissued, 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
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treasury stock. In addition, from April 1993 through December 1993, EPG issued
43,394 shares of common stock in connection with employee stock option plans.
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. 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. During 1994, EPG acquired 1,362,937 shares of its common stock for an
aggregate value of $44 million and subsequently reissued, in connection with
employee stock option plans, 50,162 shares of its common stock out of treasury
stock for an aggregate value of $1.8 million. As of December 31, 1994, EPG had
1,799,136 shares of treasury stock.
A total of 800, 2,300, and 132,700 restricted shares of EPG's common stock
were granted to certain employees during 1994, 1993, and 1992, respectively. The
market value at grant date of such shares awarded was approximately $26,000,
$76,000, and $2.8 million in 1994, 1993, and 1992, respectively.
Capital Expenditures
The Company's planned capital expenditures for 1995 of approximately $225
million are primarily for maintenance of business, system expansion, and system
enhancement. These expenditures are expected to be financed through internally
generated funds and short-term and long-term borrowings. Capital expenditures
for 1994 were $173 million compared to $164 million for 1993. The increase was
due primarily to 1994 system enhancements.
In July 1992, EPG filed an application with FERC, which was amended in
November 1992, to expand the delivery capacity of its system in the vicinity of
Yuma, Arizona and, through an extension of its system south to San Luis Rio
Colorado, Sonora, Mexico, to serve northern Mexican markets. The proposed
expansion would have provided shippers the opportunity to deliver natural gas to
Mexican markets in northern Baja California via new pipeline capacity of 348
MMcf/d. The project cost was estimated to be approximately $71 million. In June
1994, EPG withdrew the July 1992 application, citing delays in the conversion to
natural gas and expansion of the existing Benito Juarez Power Plant in Rosarito,
Baja California Norte, Mexico. In withdrawing the pending application, EPG
emphasized that it is not abandoning the project. At such time as CFE proceeds
with its plans for the Benito Juarez Power Plant, EPG may refile its
application.
EPG 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 CFE. In August 1994, EPG
increased its prospective ownership interest in the Samalayuca II Power Plant
from 10 percent to 20 percent. CFE and the consortium signed a trust agreement
in August 1994. Additional annexes to the trust agreement are currently being
negotiated with CFE. The trust agreement, together with the annexes, will form
the basis for seeking international financing for the Samalayuca II Power Plant
project.
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
and to an existing power plant in the same location. The proposed expansion
would provide an additional 300 MMcf/d of capacity at a cost of approximately
$57 million. In November 1993, FERC issued an order which approved the proposed
border crossing facility south of Clint, Texas that would connect EPG's
facilities with facilities in Mexico. FERC deferred action on the remainder of
the March 1993 filing until EPG demonstrates that it has executed long-term
contracts or binding precedent agreements for a substantial amount of the firm
capacity of the proposed facilities. FERC required the executed contracts or
agreements by January 1995. EPG has advised FERC that it does not have the
contracts or agreements at this time. EPG has requested that FERC not dismiss
the March 1993 application. Management believes that Mexico wants and needs this
natural gas project and the process of obtaining contracts is ongoing. In
December 1993, PG&E, CPUC, and SoCal jointly filed a motion with FERC seeking
clarification or rehearing of the November 1993 FERC order on the Samalayuca II
Power Plant project discussed above.
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In April 1994, EPG filed an application with FERC for a certificate of
public convenience and necessity to build a 98 mile pipeline to parallel and
loop its existing Havasu Crossover Line. 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. The project is
expected to cost approximately $62 million. At the request of several of EPG's
customers, FERC held a technical conference in August 1994 with respect to the
April 1994 application. The application is currently pending before FERC.
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 $26 million. At
December 31, 1994, EPG had a commitment to purchase approximately $9 million of
pipe in connection with the proposed expansion. The proposed expansion would
accommodate increased volumes and provide markets with enhanced access to San
Juan Basin gas supplies. FERC held a technical conference in August 1994 with
respect to the June 1994 application. The application is currently pending
before FERC.
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.
In December 1993, FERC held a public conference to examine the question
raised by CPUC and PG&E regarding MPC's proposed expansion. The primary issue
was whether FERC or CPUC should have jurisdiction over the expansion. In
February 1994, FERC issued an order determining that it has exclusive
jurisdiction over MPC and its proposed expansion. In March 1994, CPUC, PG&E, and
other parties filed for rehearing or clarification of FERC's February 1994
order. The petitions for rehearing and/or clarification are pending action by
FERC. In November 1994, FERC unanimously approved an order granting MPC a
preliminary determination, subject to possible later modification, issuing the
requested certificate of public convenience and necessity for the proposed
expansion. FERC requested certain further information from the parties to
determine whether PG&E, which is currently the principal gas supplier in the
region to be served by the expansion project, is entitled to any compensation
from MPC and/or EPG as a result of MPC's bypass of PG&E gas service. MPC and EPG
have provided FERC with the requested information. The preliminary determination
did not address the jurisdictional issues pending before FERC on rehearing of
the February 1994 order. In December 1994, MPC and other parties filed requests
for rehearing of the preliminary determination asking for reconsideration of
rate and other modifications ordered by FERC. If FERC does not make significant
changes to the preliminary determination, MPC will not go forward with the
expansion. MPC expects to receive a final FERC certificate in the second quarter
of 1995.
The capital projects discussed above are expected to be financed through
internally generated funds and short-term and long-term borrowings.
Other
In January 1993, EPG experienced flood damage to its pipeline system in the
Gila, Arizona area due to heavy rain. During 1994, EPG received approximately
$22 million of insurance reimbursements, which represent substantially all costs
incurred related to the flood damage.
In June 1994, EPG and Meridian Oil Production Inc. ("MOPI") entered into an
agreement concerning production from MOPI's conventional gas wells located on
1.5 million acres in the San Juan Basin. Under the terms of the agreement,
MOPI's gas is committed to flow exclusively through EPG's gathering and
processing facilities from May 1994 through February 2000. The agreement
provides for new rates for gathering and processing of natural gas liquids
effective January 1, 1994 through February 29, 2000.
RESULTS OF OPERATIONS
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
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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 sales 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 Amoco
decision. 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 ("AFUDC") was $5 million lower
for the year ended December 31, 1994, than for the same period of 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 clean-up expenses. The
increase in other income was partially offset by interest expense related to the
special charge for litigation in connection with the Amoco decision 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. Thoughput 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.
Year Ended December 31, 1993, Compared to Year Ended December 31, 1992
Operating revenues for the year ended December 31, 1993, were $106 million
higher than for the same period of 1992. New system rates and a new rate design
placed into effect February 1, 1993, resulted in a $41 million increase in
revenues which was comprised of an increase in reservation revenues of $111
million offset by a decrease in transportation revenues of $70 million. The
consolidation of MPC contributed $27 million to the increase. Higher rates and
volumes for gathering and processing increased revenues by $3 million and $7
million, respectively. Higher sales rates increased revenues by $34 million;
however, lower sales volumes offset that increase by $5 million. In addition,
the sale of gas in storage contributed $18 million to the increase in revenues;
this increase is offset in operating charges. Offsetting the increase in
operating revenues was a decrease of $13 million due to lower transportation
volumes, a decrease in return on take-or-pay receivables of $4 million, and a
decrease in liquid revenues of $2 million.
Operating charges were $62 million higher for the year ended December 31,
1993, compared to the same period for 1992. Higher average cost of gas
contributed $39 million to the increase. In addition, the sale of gas in storage
contributed $18 million to the increase in operating charges; this increase is
offset in operating revenues. Higher operation and maintenance costs of $26
million were due primarily to an accrual for estimated take-or-pay
undercollections, the consolidation of MPC, and increases in employee benefit
costs and outside contractors fees, primarily related to environmental clean-up.
This increase is partially offset by
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lower stock related benefit costs. An increase of $3 million in other taxes is
primarily due to the consolidation of MPC and an increase in ad valorem taxes.
The increase in operating charges was partially offset by lower depreciation
rates after giving effect to the rate settlement. Additionally, lower gas sales
volumes resulted in a decrease in operating charges of $4 million.
Interest and debt expense for the year ended December 31, 1993, was $7
million higher than for the same period of 1992 due primarily to the
consolidation of MPC.
AFUDC was $2 million lower for the year ended December 31, 1993, than for
the same period in 1992 due to a decrease in expansion project expenditures
during 1993.
Other-net was $6 million higher for the year ended December 31, 1993,
compared to the same period for 1992. Contributing to the higher expense was a
$6 million increase related to environmental accruals; a $4 million reduction in
direct bill interest income; and a $4 million reduction in partnership earnings
due to the consolidation of MPC. The increase was offset by lower interest
expense of $4 million on tax adjustments and $3 million of interest income
related to the recovery of EPG's investment in its underground storage facility.
EPG's throughput for 1993 was 1,306 Bcf compared to 1,357 Bcf in 1992. This
decrease is due to lower deliveries to the utility electric generation market
resulting from the availability of excess hydroelectric power in the California
markets. The lower deliveries to California were partially offset by higher
throughput to off-system markets.
OTHER
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 106 which requires companies to account for
other postretirement employee benefits ("OPEBs") (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 OPEBs 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.
EPG began recovering through its rates the OPEB costs included in the
settlement agreement. To the extent actual OPEB costs differ from the amounts
funded, a regulatory asset or liability is recorded. Management expects to seek
inclusion of such amounts in its rates.
The Financial Accounting Standards Board issued SFAS No. 112 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 to reflect the initial adoption of SFAS No. 112.
Management expects to seek recovery of the $8 million through rates and has
recorded a regulatory asset equal to that amount.
Deferred credits, in the Consolidated Balance Sheet, 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
Sheet include expected future recoveries resulting from the increase of the
statutory federal rate from 34 to 35 percent on January 1, 1993. Management
expects to seek recovery of such amounts through its rates.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
Operating revenues
Reservation.............................................. $506,122 $483,471 $346,027
Transportation........................................... 41,102 59,631 141,789
Gas and liquid sales..................................... 225,857 280,839 237,965
Gathering and processing................................. 66,581 51,427 41,759
Other.................................................... 30,210 33,560 35,272
-------- -------- --------
869,872 908,928 802,812
-------- -------- --------
Operating charges
Operation and maintenance................................ 295,182 340,818 314,782
Natural gas and liquids.................................. 233,823 249,484 197,759
Depreciation and amortization............................ 65,037 54,051 73,229
Litigation special charge................................ 15,062 -- --
Taxes, other than income taxes........................... 38,473 35,330 32,132
-------- -------- --------
647,577 679,683 617,902
-------- -------- --------
Operating income........................................... 222,295 229,245 184,910
-------- -------- --------
Other (income) and income deductions
Interest and debt expense................................ 78,850 75,429 68,075
Allowance for funds used during construction............. (485) (5,438) (7,096)
Interest income from BR.................................. -- -- (1,602)
Other -- net............................................. (4,146) 8,428 2,244
-------- -------- --------
74,219 78,419 61,621
-------- -------- --------
Income before income taxes................................. 148,076 150,826 123,289
Income taxes............................................... 58,463 59,153 46,963
-------- -------- --------
Net income................................................. $ 89,613 $ 91,673 $ 76,326
======== ======== ========
Earnings per common share.................................. $ 2.45 $ 2.46 $ 2.12
======== ======== ========
Average common shares outstanding.......................... 36,632 37,212 36,049
======== ======== ========
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 SHEET
(IN THOUSANDS, EXCEPT PER SHARE AMOUNT)
ASSETS
DECEMBER 31, DECEMBER 31,
1994 1993
------------ ------------
Current assets
Cash and temporary investments................................... $ 27,636 $ --
Accounts and notes receivable, net............................... 131,650 133,437
Materials and supplies inventory................................. 34,666 34,665
Take-or-pay buy-outs, buy-downs, and prepayments, net............ 33,356 34,019
Other regulatory assets.......................................... 12,000 12,000
Deferred income tax benefit...................................... 41,257 44,141
Costs recoverable through insurance.............................. 291 23,260
Other............................................................ 18,303 22,490
------------ ------------
Total current assets..................................... 299,159 304,012
------------ ------------
Property, plant, and equipment, net................................ 1,865,897 1,765,486
Take-or-pay buy-outs, buy-downs, and prepayments, net.............. 14,502 48,106
Other regulatory assets............................................ 59,021 62,249
Other.............................................................. 93,192 89,810
------------ ------------
2,032,612 1,965,651
------------ ------------
Total assets............................................. $ 2,331,771 $ 2,269,663
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade......................................................... $ 117,575 $ 125,944
Other......................................................... 111,781 73,939
Commercial paper................................................. 106,800 1,300
Take-or-pay financing liability.................................. 36,700 40,125
Accrual for regulatory issues.................................... -- 47,263
Current maturities of long-term debt............................. 6,824 6,184
Accrued interest................................................. 31,236 30,447
Accrued taxes, other than income taxes........................... 27,373 21,135
Other............................................................ 13,766 10,127
------------ ------------
Total current liabilities................................ 452,055 356,464
------------ ------------
Long-term debt, less current maturities............................ 779,097 795,783
Deferred income taxes, less current portion........................ 304,918 298,080
Take-or-pay financing liability, less current portion.............. -- 40,383
Deferred credits................................................... 40,325 25,540
Other liabilities.................................................. 45,740 45,865
------------ ------------
1,170,080 1,205,651
------------ ------------
Commitments and contingent liabilities (see Notes 2, 4, and 13)
Stockholders' equity
Common stock, par value $3 per share; authorized, 100,000 shares;
issued, 37,351 shares and 37,350 shares....................... 112,053 112,051
Additional paid-in capital....................................... 454,705 455,496
Retained earnings................................................ 202,558 157,506
Less: Treasury stock 1,799 shares and 486 shares................. 59,680 17,505
------------ ------------
Total stockholders' equity............................... 709,636 707,548
------------ ------------
Total liabilities and stockholders' equity............... $ 2,331,771 $ 2,269,663
============ ============
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 STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-------------------------------------
1994 1993 1992
--------- --------- ---------
Cash flows from operating activities
Income from operations................................ $ 89,613 $ 91,673 $ 76,326
Adjustments to reconcile income to net cash provided
by operating activities
Depreciation and amortization...................... 65,037 54,051 73,229
Deferred income taxes.............................. 49,394 8,550 (54,468)
Net take-or-pay recoveries......................... 31,932 60,799 213,748
Costs recovered (recoverable) through insurance.... 22,969 (22,578) 1,096
Other working capital changes
Accounts and notes receivable.................... 862 34,877 7,215
Inventories...................................... (2,527) 11,530 3,700
Other current assets............................. 4,684 10,209 (16,707)
Accounts payable................................. 33,322 (38,644) 17,680
Accrual for regulatory issues.................... (34,903) 1,210 15,267
Accrued taxes, other than income taxes........... 4,132 5,291 4,566
Other current liabilities........................ (4,037) 3,609 (24,693)
Other.............................................. (7,276) 14,975 16,579
--------- --------- ---------
Net cash provided by operating activities..... 253,202 235,552 333,538
--------- --------- ---------
Cash flows from investing activities
Capital expenditures.................................. (173,252) (164,333) (245,799)
Mojave acquisition.................................... -- (35,695) --
Proceeds from property dispositions................... 7,299 1,674 4,812
Other................................................. (23,381) (7,553) (2,111)
--------- --------- ---------
Net cash used in investing activities......... (189,334) (205,907) (243,098)
--------- --------- ---------
Cash flows from financing activities
Proceeds from sale of common stock, net............... 26 947 95,557
Proceeds from reissuance of treasury stock............ 1,204 3,869 10,754
Proceeds from long-term financings.................... -- -- 575,000
Long-term debt retirements............................ (16,174) (2,871) (186,416)
Net commercial paper borrowings....................... 105,500 1,300 --
Proceeds from sale of volumetric take-or-pay
receivables........................................ -- -- 210,621
Repayment of volumetric take-or-pay receivable........ (43,808) (35,313) (94,800)
Repayment of payable to BR............................ -- -- (624,804)
Acquisition of treasury stock......................... (43,994) (18,001) (23,988)
Dividends paid prior to initial public offering....... -- -- (274,000)
Dividends paid subsequent to initial public
offering........................................... (43,491) (39,935) (18,651)
Other................................................. 4,505 11,721 (35,846)
--------- --------- ---------
Net cash used in financing activities......... (36,232) (78,283) (366,573)
--------- --------- ---------
Increase (decrease) in cash and temporary cash
investments........................................... 27,636 (48,638) (276,133)
Cash and temporary cash investments
Beginning of period........................... -- 48,638 324,771
--------- --------- ---------
End of period................................. $ 27,636 $ -- $ 48,638
========= ========= =========
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 STATEMENT OF STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
COMMON STOCK ADDITIONAL TREASURY STOCK TOTAL
-------------------- PAID-IN RETAINED --------------------- STOCKHOLDERS'
SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT EQUITY
--------- -------- -------- --------- ---------- -------- -------------
January 1, 1992.............. 31,421,731 $ 94,265 $382,260 $ 338,353 $ -- $ 814,878
Net income................. 76,326 76,326
Issuance of common stock,
net of related costs.... 5,882,700 17,648 72,220 89,868
Common stock dividends,
prior to the Offering... (274,000) (274,000)
Common stock dividends,
subsequent to the
Offering
($.75 per share)........ (27,817) (27,817)
Acquisition of treasury
stock................... (812,773) (23,988) (23,988)
Reissuance of treasury
stock................... (4,837) 628,258 18,562 13,725
---------- -------- -------- --------- ---------- -------- -------------
December 31, 1992............ 37,304,431 111,913 454,480 108,025 (184,515) (5,426) 668,992
Net income................. 91,673 91,673
Issuance of common stock,
net of related costs.... 45,694 138 1,016 1,154
Common stock dividends,
($1.10 per share)....... (40,904) (40,904)
Acquisition of treasury
stock................... (509,095) (18,001) (18,001)
Reissuance of treasury
stock................... (1,288) 207,249 5,922 4,634
---------- -------- -------- --------- ---------- -------- -------------
December 31, 1993............ 37,350,125 112,051 455,496 157,506 (486,361) (17,505) 707,548
Net income................. 89,613 89,613
Issuance of common stock,
net of related costs.... 800 2 24 26
Common stock dividends,
($1.21 per share)....... (44,179) (44,179)
Acquisition of treasury
stock................... (1,362,937) (43,994) (43,994)
Reissuance of treasury
stock................... (382) 50,162 1,819 1,437
Other...................... (815) (815)
---------- -------- -------- --------- ---------- -------- -------------
December 31, 1994............ 37,350,925 $112,053 $454,705 $ 202,558 (1,799,136) $(59,680) $ 709,636
========== ======== ======== ========= ========= ======== ==========
The accompanying Notes and Supplemental Schedules are an integral part of
these Consolidated Financial Statements.
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EL PASO NATURAL GAS COMPANY
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.
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 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 Statement of Income.
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 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) 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; and (viii) the cost of equity funds used during construction has been
capitalized.
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 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 AFUDC have been recorded in
other regulatory assets to be recovered in future rates.
Management believes that MPC remains "regulated" as the term is used in the
relevant accounting literature. However, management is currently evaluating
whether or not the application of these principles will continue to be
appropriate for MPC in the future. At December 31, 1994, the Consolidated
Balance Sheet contains assets and liabilities related to MPC's operations which
have been recorded pursuant to regulatory accounting principles. If these
accounting principles should no longer be applied to MPC's operations, an amount
would be charged to earnings as an extraordinary item. At December 31, 1994,
this amount was estimated to be approximately $8 million.
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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, 1994, and 1993 were $6.2 million and $3.9 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 the provision at December 31, 1994, and 1993 were $8.8 million and
$5.6 million, respectively.
Materials and Supplies Inventory
Inventory is valued at cost and relieved 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 five 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 buy-out and
buy-down costs through a surcharge added to its transportation rates.
Property, Plant, and Equipment
Included in the Company's property, plant, and equipment is construction
work in progress of approximately $78 million and $53 million at December 31,
1994, and 1993, 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 1994 and 1993 was 1.6 percent for
transmission facilities. For 1992, the depreciation rate for transmission
facilities was 2.67 percent adjusted to 1.6 percent in accordance with the
settlement agreement. The depreciation rate for gathering facilities was 3.5
percent for 1994, 1993, and 1992.
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. (See "Accounting for
Regulated Operations" of this note.)
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,
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31
by BR's former parent, Burlington Northern Inc. ("BNI"). 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.
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.
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.
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 activities resulting from
holding these financial instruments are treated in the same manner as the
underlying instrument.
Income Taxes
Income taxes are based on income reported for tax return purposes and 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.
Treasury Stock
Treasury stock is accounted for using the cost method and is shown as a
reduction to stockholders' equity in the Consolidated Balance Sheet. Treasury
stock sold or reissued is valued on a first-in first-out basis. Included in
treasury stock at December 31, 1994, are 430,000 shares that have been used 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 1994, 1993, and 1992 were 36,632,236,
37,212,192, and 36,049,135, respectively. Stock options are the only common
stock equivalents and are currently not dilutive.
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2. RATES AND REGULATORY MATTERS
General Rate Filings and Other
In July 1991, EPG filed for FERC approval of new system rates and placed
the proposed new rates into effect on January 1, 1992, subject to refund. In
July 1992, EPG again filed for 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. In the July 1992
filing, EPG's rate base increased from $752 million to approximately $1.2
billion. 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 filed in January 1993 to
supersede EPG's December 1992 compliance filing. As required by the FERC order,
EPG filed revised rates in September 1993, which implemented the settlement
agreement effective October 1, 1993. Under the settlement 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 $56.7 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 $56.7 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, 1994 was $32 million. The outstanding
balances at December 31, 1994, and 1993 were $24 million and $37 million,
respectively, of which $12 million is reflected in the current portion of other
regulatory assets for both periods and $12 million and $25 million,
respectively, are included in other regulatory assets in the Consolidated
Balance Sheet. The settlement agreement also established new depreciation rates
for certain of EPG's facilities effective January 1, 1992.
MPC filed a service and rate design restructuring plan in November 1992 in
compliance with FERC's industry-wide Restructuring Rules. In March 1993, FERC
issued an order essentially approving MPC's compliance filing, subject to
changes, which were made in an amended restructuring plan in March 1993.
Several of MPC's customers filed protests and requests for rehearing of the
March 1993 FERC order. The rehearing requests were denied, and FERC approved the
amended restructuring plan in July 1993 with an effective date of August 1,
1993. In October 1993, FERC issued an order which denied requests for rehearing
of the July 1993 order. Several of MPC's customers have filed petitions with the
Court of Appeals for review of the March 1993, July 1993, and October 1993
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. The application of SFV rates requires MPC's existing firm shippers to
pay a higher proportion of their total transportation rate in the reservation
component of the rate. Such shippers have contended that FERC's application of
SFV rate design to MPC unlawfully abrogates the rate provisions of MPC's service
agreements and constitutes an unlawful rate increase. Management believes the
Court of Appeals will uphold SFV rates as applied to MPC.
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, 1994, and 1993, the recoupable
prepayment balances were $6 million and $9 million, respectively.
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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, 1994, EPG had recovered
approximately $1.0 billion. EPG has established a reserve, based on current
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 $9 million and $19 million at December 31, 1994, and 1993,
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 approved an order, subject to rehearing, resolving all but one of the
outstanding issues regarding EPG's take-or-pay proceedings. However, certain of
EPG's customers have sought review of the eligibility of certain costs for which
EPG has received FERC approval for recovery. The remaining 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. In June
1994, FERC affirmed a 1993 decision of an ALJ 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 July 1994, EPG filed
for rehearing of the June 1994 order. In accordance with the FERC decision, EPG
refunded $34 million, inclusive of interest, to its customers in September 1994.
In November 1994, FERC issued an order which denied EPG's request for rehearing.
EPG has filed a petition with the Court of Appeals for the review of the June
1994 order.
In January 1992, EPG completed a sale of substantially all of its remaining
take-or-pay buy-out and buy-down receivables. The sale totaled $325 million,
including $305 million of cash received at closing, which was used to repay $300
million of a payable to BR. The receivables sold in this transaction included
$104 million which was recovered through direct bill and $221 million to be
recovered through volumetric surcharge. The volumetric surcharge portion of the
sale has been accounted for as a financing transaction because EPG is subject to
certain recourse provisions related to such receivables. At December 31, 1994,
and 1993, $47 million and $87 million, respectively, of the volumetric surcharge
portion of the receivables sold remained outstanding. Amounts collected related
to the take-or-pay receivables sold are remitted to the purchasers of the
receivables.
3. LONG-TERM DEBT AND OTHER FINANCING
Long-term debt outstanding is as follows:
DECEMBER 31,
---------------------
1994 1993
-------- --------
(IN THOUSANDS)
Long-term debt
EPG
6.90% Notes, due January 1997..................... $100,000 $100,000
9.45% Notes, due September 1999................... 47,447 47,442
7 3/4% Notes, due January 2002.................... 214,624 214,570
8 5/8% Debentures, due March 2012................. 16,811 16,791
8 5/8% Debentures, due January 2022............... 258,420 258,362
Other............................................. 35 43
MPC
Project financing loan, due March 2007, average
interest rates of 8.0% and 7.6%................. 148,584 164,759
-------- --------
785,921 801,967
Less current maturities........................... 6,824 6,184
-------- --------
Total long-term debt............................ $779,097 $795,783
======== ========
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The following are aggregate maturities of long-term debt for the next five
years and in total thereafter:
(IN THOUSANDS)
1995............................................................. $ 6,824
1996............................................................. 7,517
1997............................................................. 108,279
1998............................................................. 18,081
1999............................................................. 65,366
Thereafter....................................................... 579,854
-----------
Total long-term debt, including current
maturities.................................... $785,921
===========
In January 1992, EPG completed a purchase of $46 million and $41 million of
aggregate principal amounts of the 9.45% Notes and 8 5/8% Debentures,
respectively. Funds for these purchases were provided by proceeds from
borrowings under the BR Loan Agreements described below. In addition, in
December 1991 EPG called for redemption, on January 23, 1992, of all the
outstanding 9 5/8% Debentures ($100 million aggregate principal amount) at a
price equal to 106.84 percent of their principal amount.
EPG had a Commitment Agreement with BR under which it could borrow up to
$300 million and Loan Agreements for borrowings up to $500 million. Proceeds
from the sale of the take-or-pay receivables were used to repay the borrowings
under the Commitment Agreement. In January 1992, EPG borrowed $109 million under
the Loan Agreements. Borrowings under the Loan Agreements were used to pay for
the purchase of the 9.45% Notes and the 8 5/8% Debentures in January 1992 and
the payment of related transaction costs.
In January 1992, EPG issued $575 million principal amount of new debt
securities consisting of $100 million of 6.90% Notes due 1997, $215 million of
7 3/4% Notes due 2002, and $260 million of 8 5/8% Debentures due 2022. The net
proceeds of $569 million received from such issuance were used to repay $434
million of borrowings under the Loan Agreements with BR, to redeem $107 million
of 9 5/8% Debentures, and for general corporate purposes ($28 million) including
costs related to the transactions discussed above. The Commitment Agreement and
the Loan Agreements with BR were terminated prior to the completion of the
Offering.
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 which expires in five years. As of December 31,
1994, and 1993, respectively, there were no borrowings outstanding under these
facilities. Approximately $107 million and $1 million of commercial paper were
outstanding as of December 31, 1994, and 1993, respectively. The weighted
average interest rates on these borrowings for 1994 and 1993 were 4.58 percent
and 3.24 percent, respectively.
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. Also, EPG must
maintain consolidated tangible net worth of at least $400 million. Furthermore,
certain EPG subsidiaries (other than any project financing subsidiary, as
defined in the agreements) may not incur debt obligations which would exceed $75
million in the aggregate. As of December 31, 1994, EPG's consolidated debt and
guaranties to capitalization ratio was 51.2 percent, its consolidated tangible
net worth exceeded the minimum restrictive covenant requirement by approximately
$300 million, and there were no subsidiary debt obligations of those
subsidiaries limited by the debt agreements.
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. As of
December 31, 1994, EPG had not requested that the registration statement be
declared effective by the Securities and Exchange Commission.
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In September 1991, MPC entered into a credit agreement ("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 $149 million and $165 million at December 31, 1994, and 1993, 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.
MPC has entered into interest rate swap agreements which effectively
convert $114.3 million of the current loan balance from floating-rate debt to
fixed-rate debt. MPC makes payments to counterparties at fixed rates and in
return receives payments at floating rates. Substantially all of the remaining
$34.3 million of loan principal had interest rates ranging from 4.1 percent to
6.0 percent during 1994. With the impact of the interest rate swap agreements,
the overall effective interest rates on the loan were approximately 8.0 percent
and 7.6 percent during 1994 and 1993, respectively.
4. ENVIRONMENTAL
As of December 31, 1994, EPG had a reserve of approximately $40 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. Future PCB remediation costs are estimated to range between $7
million and $11 million over the next 5 years.
2 -- EPG executed an Administrative Order on Consent with EPA in June 1993
to conduct a RI/FS for a BI site located in Statesville, North Carolina,
that has been identified for cleanup. BI and EPG have entered into an
agreement to jointly fund the RI/FS for the site. EPG's share of the
potential remediation costs is estimated to be between $17 million and $29
million over a 30 year period.
3 -- In November 1993, in accordance with an EPA order, EPG and ARCO
submitted work plans for remediation of the subsurface at the Prewitt
Refinery in McKinley County, New Mexico. EPG and ARCO have a cost sharing
agreement to each pay one-half of any remediation costs at this site. EPG's
share of the remediation costs is estimated to be between $12 million and
$20 million over a 30 year period.
4 -- In December 1993, EPA issued EPG a Notice of Liability for the CSMRI
site in Golden, Colorado. EPA has determined that the volume of hazardous
substances sent to the site by EPG represent 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 $500,000.
5 -- EPG and Texaco have been conducting environmental assessments of
groundwater and soil contamination at various sites in southeastern Utah.
Based upon currently available information, EPG estimates costs for
remediation will be approximately $4 million. However, costs could be
higher once the environmental assessment has been completed. EPG and Texaco
are engaged in negotiations over the appropriate allocation of the
remediation costs.
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. These costs are estimated to be approximately
$1.7 million. EPG and the other PRP are engaged in negotiations over the
appropriate allocation of the alleged costs.
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 for the site in November
1994. The proposed remediation and EPA oversight costs are estimated to be
$800,000. The allocation of these costs between EPG and the other PRPs is
currently
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being negotiated. EPG's share of the costs is estimated to be between
$300,000 and $500,000 over a 5 year period.
8 -- EPG has entered into a de minimis administrative order on consent with
EPA for EPG's share of the environmental remediation costs associated with
a site in Odessa, Texas. In accordance with the order, EPG paid total costs
of approximately $32,000 in the fourth quarter of 1994.
Management believes the amount reserved as of December 31, 1994 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 and EPA are in the preliminary stages of
investigating the nature and extent of contamination, as well as identifying
other PRPs. Since testing 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 CAAA, and believes that these rules will impact the
Company's operations 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) enhanced monitoring of air emissions. EPG anticipates capitalizing
the equipment costs associated with complying with CAAA and estimates that
approximately $30 million will be spent from 1995 through 2005. However,
EPA's proposed enhanced monitoring rules, when finalized, could potentially
impose greater costs to the Company.
2 -- EPG has been conducting remediation of mercury contamination at
certain facilities and is replacing mercury containing meters with other
measurement devices. The mercury remediation project is expected to be
completed in 1995 at a cost of approximately $8 million. EPG will close and
retire about 1,500 earthen siphon/dehydration pits in the San Juan Basin as
required by certain environmental regulations. The project is expected to
be completed in 1995 at a cost of approximately $6 million. The mercury
remediation and pit closure costs, which are associated with the retirement
of equipment, will be recorded as adjustments to accumulated depreciation,
as permitted by regulatory accounting.
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 or developments occur, related accrual amounts will be
adjusted accordingly.
5. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is presented in accordance with the requirements of SFAS No. 107.
The estimated fair value amounts have been determined by the Company using
available market information and valuation methodologies.
As of December 31, 1994, and 1993, 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
34
37
settled, based on quoted market prices or estimates obtained from dealers. The
following table reflects the carrying amount and estimated fair value of the
Company's financial instruments.
DECEMBER 31,
---------------------------------------------------
1994 1993
----------------------- -----------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN THOUSANDS)
Balance sheet financial instruments
Long-term debt........................ $637,337 $ 621,400 $637,208 $ 696,200
Project financing..................... 148,584 148,584 164,759 164,759
Other financial instruments
Interest rate swap agreements......... -- 2,144 -- 19,264
Price rate swap agreements............ -- 1,190 -- 1,004
Futures contracts..................... -- 84 -- --
-------- ---------- -------- ----------
Total......................... $785,921 $ 773,402 $801,967 $ 881,227
======== ========= ======== =========
Derivative Financial Instruments
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. The Company uses
derivatives to manage well-defined interest rate and commodity price risks.
Those financial instruments held for hedging purposes are used to hedge only
firm commitments. In 1993, both EPG and EPGM entered into separate price swap
agreements; however, all contracts held by EPG were settled by the end of 1993.
There were no futures or option contracts held in 1993. With the exception of
MPC's interest rate swap agreements, all derivative financial instrument
contracts at December 31, 1994, are held by EPGM.
1. Interest Rate Swap Agreements
MPC has entered into interest rate swap agreements which effectively
converted $114.3 million of floating-rate debt to fixed-rate debt. MPC
makes payments to counterparties at fixed rates and in return receives
payments at floating rates. At December 31, 1994, and 1993, MPC had two
interest rate swap agreements outstanding with an aggregate notional amount
of $114.3 million. The two swap agreements were entered into in March 1992
and have remaining terms of approximately 5 years and 7 years,
respectively.
The primary risks associated with 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, MPC
does not anticipate non-performance by the other party.
2. Price Swap Agreements
In 1994 and 1993, EPG and EPGM entered into certain price swap
agreements with counterparties to effectively manage a portion of the
market risk associated with the fluctuations in the price of natural gas.
The agreements include both (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, and (ii) transactions in which the parties agree to pay
based on different indices. At December 31, 1994, and 1993, EPGM had swap
agreements used on the buying side of natural gas transactions with
notional contract amounts of approximately $22.3 million and $22.5 million,
respectively. EPGM had swap agreements used on the selling side of natural
gas transactions with notional contract amounts of approximately $6.3
million and $7.5 million, at December 31, 1994, and 1993, respectively.
EPGM also held two swap agreements in which payment by both parties is
based on different indices. These agreements had a notional contract amount
of approximately $0.7 million at December 31, 1994. The price swap
agreements entered into in 1994 extend for periods of up to 5 years, while
those originating in 1993 have current terms of up to 4 years. During 1994,
EPGM realized a pretax loss of approximately $1.4 million pertaining to
price swap agreements. During 1993, EPG and EPGM, collectively, realized a
pretax loss of approximately $0.2 million pertaining to price swap
agreements.
35
38
The primary risks associated with swaps are the exposure to movements
in the value of natural gas and the ability of the counterparties to meet
the terms of the contracts. While the notional contract amounts reflect the
extent of involvement in the price swap agreements, the amounts potentially
subject to credit risk, in the event of non-performance by the other
parties, are substantially smaller. EPG periodically reviews and assesses
counterparty risk to limit any material impact to its financial position or
results of operations; consequently, EPGM does not anticipate
non-performance by the other parties.
3. Futures Contracts
In 1994, EPGM entered into futures contracts to effectively manage a
portion of the market risk associated with fluctuations in the price of
natural gas. At December 31, 1994, EPGM held in its portfolio 25 futures
contracts for an aggregate notional value of $0.5 million, expiring in
March 1995. During 1994, EPGM realized a pretax loss of approximately $0.5
million pertaining to futures contracts. At December 31, 1994, EPGM had an
unrealized loss of approximately $1.2 million pertaining to such contracts
which is reflected in the Consolidated Balance Sheet. Risks on futures
contracts stem from market movements in the value of natural gas.
4. Option Contracts
Options give EPGM the right, but not the obligation, to buy or sell
natural gas at a predetermined price during a specified period. EPGM
purchased option contracts during 1994; however, at December 31, 1994, did
not hold any in its portfolio. Risks on option contracts stem from
movements in the value of natural gas.
Risk Management
The Company does not obtain collateral or other security to support
financial instruments subject to credit risk, but monitors the credit standing
of counterparties. MPC's objective in entering into the interest rate swap
agreements was to avoid the interest rate risk associated with the floating rate
debt. EPGM is engaged in the trading of natural gas in the spot (30 day),
intermediate (up to 1 year), and long-term (in excess of 1 year) markets.
Volatility of prices for natural gas has inherently created financial risk in
conducting seasonal and long-term marketing. The primary reason EPGM's risk
management program includes the use of these instruments is to guard against
adverse changes in the price of natural gas and attempt to ensure a margin on
purchases or sales of natural gas. EPGM has established policies and procedures
governing the use of derivative financial instruments in over-the-counter and
listed exchange-based markets to manage the risks of buying and selling natural
gas.
A designated committee oversees risk management activities of EPGM to
ensure that specific risk management strategies have been developed, reviewed,
and implemented, which comply with the stated objectives approved by management.
6. ACQUISITION
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.
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
===========
36
39
The operating results of MPC are included in the Company's consolidated
results of operations for 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 Statement of Income.
The following pro forma summary presents the consolidated results of
operations of the Company as if the acquisition had occurred as of January 1,
1993 or January 1, 1992. These pro forma results have been prepared for
comparative purposes only and do not purport to be indicative of what may have
resulted had the acquisition occurred as of those dates or of results which may
occur in the future.
YEAR ENDED DECEMBER
31,
---------------------
1993 1992
-------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
Operating revenue.............................................. $922,593 $834,181
Net income..................................................... 93,102 78,603
Earnings per common share...................................... 2.50 2.18
7. CORPORATE REORGANIZATION
During 1992, EPG completed several transactions in preparation for its
separation from BR. In January and February 1992, EPG declared and paid
dividends totaling $274 million to BR. These dividends were paid from the
balance owed to EPG under an intercorporate cash management arrangement.
In March 1992, EPG completed the Offering. The proceeds from the Offering,
net of related costs, totaled approximately $96 million. In June 1992, BR
distributed its 31.4 million shares of EPG's common stock, which represented
approximately 85 percent of EPG's outstanding common stock, to BR shareholders.
As a result, BR no longer retains an ownership interest in EPG.
8. CAPITAL STOCK
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 one to three 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 stock
appreciation rights ("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 cancelled, and to the extent an option is
exercised, the related SAR is cancelled.
In January 1992, the Board granted options exercisable for 722,300 shares
of common stock effective upon the closing of the Offering. One-third of the
options became exercisable on December 19, 1992; one-third became exercisable on
January 15, 1994; and one-third became exercisable on January 15, 1995.
After the Offering, 597,838 BR stock options and 100,730 BR SARs, at prices
ranging from $25.50 to $44.75 per share, were converted to EPG stock options and
SARs at prices ranging from $13.51 to $22.91 per share.
37
40
Additionally, the Board granted the following stock options:
NUMBER OF EXERCISE
STOCK PRICE PER EXERCISABLE
GRANT DATE OPTIONS SHARE DATE
- ---------- --------- --------- -----------
1/12/93 554,000 $ 30.81 1/12/94
3/18/93 3,000 36.19 3/18/93
5/1/93 3,000 38.19 5/1/93
7/22/93 15,000 37.25 1/22/94
1/14/94 655,100 36.88 1/14/95
1/14/94 3,000 36.88 1/14/94
3/17/94 5,000 39.56 3/17/94
1/13/95 633,000 29.94 1/13/96
Activity in EPG's stock option plans for 1992, 1993, and 1994 was as
follows:
EXERCISE
PRICE PER
OPTIONS SARS SHARE
--------- -------- -----------------
Balance, June 30, 1992....................... 1,705,498 631,702 $13.51 to $21.81
Converted.................................. 13,821 -- 20.82 to 22.91
Granted.................................... 3,000 -- 25.69
Exercised.................................. 628,258 441,499 13.51 to 19.00
Cancelled.................................. 30,800 85,000 13.51 to 19.00
--------- --------
Balance, December 31, 1992................... 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
Cancelled.................................. 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
Cancelled.................................. 29,983 -- 19.00 to 36.88
--------- --------
Balance, December 31, 1994................... 1,932,691 48,154 $18.14 to $39.56
========= ========
At December 31, 1994, 1,062,871 stock options and 48,154 SARs were
exercisable at prices ranging from $18.14 to $39.56 per share.
Stock options shown as cancelled in the table above may be a result of the
tandem SAR being exercised. SARs shown as cancelled in the table above were
cancelled when the underlying stock options were exercised.
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 shall be
determined by the Board.
In October 1992, the Board authorized the repurchase of up to 2 million
shares of EPG's outstanding shares of common stock from time to time in the open
market. Shares repurchased are held in EPG's treasury and are expected to be
used in connection with EPG employee stock option plans to minimize dilution to
existing shareholders. During 1992, EPG acquired 812,773 shares of its common
stock for an aggregate value of $24 million and reissued, 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 reissued 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 reissued, 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
38
41
treasury stock. In addition, from April 1993 through December 1993, EPG issued
43,394 shares of common stock in connection with EPG's employee stock option
plans.
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. 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. During 1994, EPG acquired 1,362,937 shares of its common stock for an
aggregate value of $44 million and subsequently reissued, in connection with
employee stock option plans, 50,162 shares of its common stock out of treasury
stock for an aggregate value of $1.8 million. In addition, 430,000 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. As of December
31, 1994, EPG had 1,799,136 shares of treasury stock.
A total of 800, 2,300, and 132,700 restricted shares of EPG's common stock
were granted to certain employees during 1994, 1993, and 1992, respectively. The
market value of such shares awarded was approximately $26,000, $76,000, and $2.8
million in 1994, 1993, and 1992, respectively.
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. As of
December 31, 1994, there had been no securities issued under this registration
statement.
9. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consists of the following:
DECEMBER 31,
-----------------------
1994 1993
--------- ---------
(IN THOUSANDS)
Property, plant, and equipment, at cost............. $2,979,368 $2,873,301
Less accumulated depreciation....................... 1,212,477 1,212,233
---------- ----------
1,766,891 1,661,068
Additional acquisition cost assigned to utility
plant, net of accumulated amortization............ 99,006 104,418
---------- ----------
Total property, plant, and equipment,
net..................................... $1,865,897 $1,765,486
========== ==========
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10. INCOME TAXES
The following table reflects the components of income tax expense.
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Current
Federal............................................ $ 14,678 $ 42,112 $ 84,315
State.............................................. (5,609) 8,491 17,116
-------- -------- --------
9,069 50,603 101,431
-------- -------- --------
Deferred
Federal............................................ 35,062 7,506 (42,590)
Change in enacted tax rate......................... -- 503 --
State.............................................. 14,332 541 (11,878)
-------- -------- --------
49,394 8,550 (54,468)
-------- -------- --------
Total tax expense.......................... $ 58,463 $ 59,153 $ 46,963
======== ======== ========
The following table reflects the components of deferred tax expense
(benefit).
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Gas cost settlements and recovery.................... $ 3,904 $ 17,633 $(51,602)
Financial accruals and reserves...................... 28,176 (13,001) (8,481)
Depreciation and amortization........................ 33,363 7,355 10,567
Alternative minimum tax.............................. (15,134) 2,103 (2,103)
Change in enacted tax rate........................... -- 503 --
Other................................................ (915) (6,043) (2,849)
-------- -------- --------
Total deferred tax expense (benefit)....... $ 49,394 $ 8,550 $(54,468)
======== ======== ========
The following table reflects the components of the net deferred tax
liability.
DECEMBER 31,
-------------------------
1994 1993
-------- --------
(IN THOUSANDS)
Deferred tax liabilities
Property, plant and equipment............................ $275,214 $253,639
Regulatory and other assets.............................. 62,168 71,896
-------- --------
Total deferred tax liability..................... 337,382 325,535
-------- --------
Deferred tax assets
Take-or-pay buy-outs, buy-downs and prepayments.......... 2,509 2,186
Accrual for regulatory issues............................ -- 22,119
Other liabilities........................................ 55,740 40,842
Other.................................................... 15,472 6,449
-------- --------
Total deferred tax asset......................... 73,721 71,596
-------- --------
Net deferred tax liability................................. $263,661 $253,939
======== ========
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43
Tax expense of the Company differs from the amount computed by applying the
statutory federal income tax rate to income before taxes. The reasons for this
difference are as follows:
YEAR ENDED DECEMBER 31,
-------------------------------
1994 1993 1992
------- ------- -------
(IN THOUSANDS)
Tax expense at the statutory federal rate of 35% for
1994 and 1993 and 34% for 1992...................... $51,827 $52,789 $41,918
Increase (decrease)
State income tax, net of federal income tax
benefit.......................................... 5,670 5,871 3,458
Change in enacted tax rate.......................... -- 503 --
Other............................................... 966 (10) 1,587
------- ------- -------
Income tax expense.................................... $58,463 $59,153 $46,963
======= ======= =======
Effective tax rate.................................... 39% 39% 38%
Deferred credits, in the Consolidated Balance Sheet, 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
Sheet include expected future recoveries resulting from the increase of the
statutory federal rate from 34 to 35 percent on January 1, 1993. Management
expects to seek recovery of such amounts through its rates.
11. PENSION PLANS
Prior to July 1992, the Company participated in BR's pension plans, which
were non-contributory defined benefit plans covering substantially all
employees. The benefits were based on the number of years of credited service
and the highest five-year average compensation levels. Contributions to the
plans were determined by BR and were limited to amounts that were deductible for
tax purposes.
In 1992, the Company established its own pension plans with provisions
similar to those of the BR plans. On July 1, 1992, the Company's qualified
pension plan received from BR's plan assets equal to the accumulated benefit
obligation relating to the Company's employees.
The following table sets forth the qualified pension plan's funded status
and amounts recognized in the Company's Consolidated Balance Sheet.
DECEMBER 31,
----------------------
1994 1993
-------- --------
(IN THOUSANDS)
Actuarial present value of benefit obligations
Vested benefits............................................. $430,499 $471,600
Nonvested benefits.......................................... 818 896
-------- --------
Accumulated benefit obligation................................ $431,317 $472,496
======== ========
Projected benefit obligation for service rendered to date..... $489,121 $546,180
Plan assets at fair value, primarily listed stocks and U.S.
bonds....................................................... 407,620 434,505
-------- --------
Projected benefit obligation in excess of plan assets......... $ 81,501 $111,675
======== ========
Unrecognized net loss......................................... $ 36,686 $ 64,194
Unrecognized net transition obligation........................ 19,305 22,008
Recognized pension liability.................................. 25,510 37,991
Minimum liability adjustment included in recognized pension
liability................................................... -- (12,518)
-------- --------
$ 81,501 $111,675
======== ========
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The following table reflects the components of net periodic pension cost.
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Service cost -- benefits earned during the period.... $ 9,345 $ 7,568 $ 3,311
Interest cost on projected benefit obligation........ 39,458 38,786 19,364
Actual return on plan assets......................... 4,721 (43,850) (27,641)
Pension cost allocated from BR plan.................. -- -- 4,922
Net amortization and deferral........................ (39,669) 10,724 11,328
-------- -------- --------
Net periodic pension cost............................ $ 13,855 $ 13,228 $ 11,284
======== ======== ========
The following table reflects the actuarial assumptions used in the
valuation of the projected benefit obligation.
1994 1993
----- -----
Weighted average discount rate..................................... 8.75% 7.50%
Rate of increase in future compensation levels..................... 5.00% 5.00%
Weighted average expected long-term rate of return on plan
assets........................................................... 9.25% 9.00%
Contributions to the plans are limited to amounts currently deductible for
tax purposes. 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.
12. POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS
The Financial Accounting Standards Board issued SFAS No. 106 which requires
companies to account for OPEBs, (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 OPEBs 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.
EPG began recovering through its rates the OPEB costs included in the
settlement agreement. To the extent actual OPEB costs differ from the amounts
funded, a regulatory asset or liability is recorded. Management expects to seek
inclusion of such amounts in its rates.
The following table sets forth the postretirement plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheet.
DECEMBER 31,
---------------------
1994 1993
-------- --------
(IN THOUSANDS)
Accumulated postretirement benefit obligation.................. $ 86,656 $124,914
Plan assets at fair value, primarily U.S. stocks and U.S.
bonds........................................................ 16,758 8,751
-------- --------
Accumulated postretirement benefit obligation in excess of plan
assets....................................................... $ 69,898 $116,163
======== ========
Unrecognized net (gain) loss................................... $(26,441) $ 9,285
Unrecognized transition obligation............................. 96,987 105,796
(Prepaid) accrued postretirement benefit costs................. (648) 1,082
-------- --------
$ 69,898 $116,163
======== ========
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The following table reflects the components of net periodic postretirement
benefit cost.
YEAR ENDED DECEMBER
31,
---------------------
1994 1993
-------- --------
(IN THOUSANDS)
Interest cost on accumulated postretirement benefit
obligation................................................... $ 6,983 $ 9,377
Actual return on plan assets................................... 472 (254)
Net amortization and deferral.................................. 6,585 9,062
-------- --------
Net periodic postretirement benefit cost....................... $ 14,040 $ 18,185
======== ========
A 10 percent annual rate of increase in the per capita costs of covered
health care benefits was assumed for 1995, gradually decreasing to 6 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 as of December 31, 1994, by approximately $8.0 million and
increase the interest cost components of net periodic postretirement benefit
cost for 1994 by approximately $0.7 million. A discount rate of 8.75 percent and
7.5 percent was used to determine the accumulated postretirement benefit
obligation at December 31, 1994, and 1993, respectively. The weighted average of
expected long-term rate of return for 1994 was 7.7 percent.
The Financial Accounting Standards Board issued SFAS No. 112 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 to reflect the initial adoption of SFAS No. 112.
Management expects to seek recovery of the $8 million through rates and has
recorded a regulatory asset equal to that amount.
13. COMMITMENTS AND CONTINGENT LIABILITIES
See Note 2 and 4 of Notes to Consolidated Financial Statements, Items 1 and
2 -- Business and Properties, El Paso Natural Gas Company, Master Separation
Agreement, and Item 3 -- Legal Proceedings for discussions of litigation and
other contingencies.
Minimum annual rental commitments at December 31, 1994, are as follows:
YEAR ENDING DECEMBER 31, OPERATING LEASES
------------------------------------------------------- ----------------
(IN THOUSANDS)
1995................................................... $ 9,167
1996................................................... 9,576
1997................................................... 10,010
1998................................................... 10,465
1999................................................... 10,943
Thereafter............................................. 94,154
------------
Total........................................ $144,315
============
Rental expense for operating leases was $9 million in 1994 and $8 million
in 1993 and 1992.
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.
The lease expires in May 2007, and grants EPG two ten year options to extend the
term of the lease.
At December 31, 1994, EPG had a commitment to purchase approximately $9
million of pipe in connection with the expansion of its existing mainline system
in the San Juan Basin.
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The Company, through a subsidiary, plans to enter into a 7.75 year lease.
The lease will be an unconditional "triple net" lease with the trustee of a
special purpose trust. The trust will obtain 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 and a variable interest rate. The
Company will have an option at the end of the lease term, and will have an
obligation upon the occurrence of certain events, to purchase the plant for a
price sufficient to pay the entire amount financed and accrued interest. If the
Company does not purchase the plant at the end of the lease term, it will have
an obligation to pay a residual guaranty amount equal to approximately 87
percent of the amount financed. Construction of the plant is expected to be
completed in early 1996.
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.
14. SIGNIFICANT CUSTOMERS
The Company had gross revenues equal to or in excess of 10 percent of
consolidated operating revenues from the following customers:
YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Southern California Gas Company.................... $190,989 $238,885 $249,277
Pacific Gas & Electric Company..................... 154,674 168,246 137,968
Southwest Gas Corporation.......................... -- (a) 95,188 79,784
- ---------------
(a) Less than 10 percent of consolidated operating revenues.
15. SUPPLEMENTAL CASH FLOW INFORMATION
The following provides additional information concerning supplemental
disclosures of cash flow activities:
YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Interest........................................... $ 70,906 $ 66,773 $ 47,047
Income taxes, net of refunds....................... 31,231 38,993 140,766
16. RELATED PARTY TRANSACTIONS
For the first six months of 1992, BR and Meridian were considered related
parties of EPG. Through February 1992, EPG participated in an intercorporate
cash management arrangement with BR, pursuant to which excess cash balances from
each of BR's operating subsidiaries were advanced to BR on a daily basis and
cash requirements of BR's operating subsidiaries were funded daily through
advances from BR. Balances under the arrangement accrued interest at rates
approximating short-term market rates. In January and February 1992, EPG
declared and paid dividends totaling $274 million to BR from the balance owed to
EPG under the intercorporate cash management arrangement.
In April 1992, the Board declared a quarterly dividend on common stock of
$0.25 per share to the June 1, 1992, stockholders of record. EPG paid the
dividend on June 19, 1992, in the amount of $9.3 million, $8 million of which
was paid to BR.
Revenues associated with the transportation of gas for Meridian by EPG were
$15 million for the six months ended June 30, 1992.
Certain BR corporate overhead expenses were allocated to EPG for the first
six months of 1992. The allocated amounts were not material and management
believes the allocation methodology was appropriate.
44
47
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 schedules of El Paso Natural Gas Company listed in Item 14(a) of this
Form 10-K. These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and financial statement schedules 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, 1994 and 1993, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement schedules
referred to above, when considered in relation to the basic financial statements
taken as a whole, present fairly, in all material respects, the information
required to be included therein.
COOPERS & LYBRAND L.L.P.
El Paso, Texas
January 20, 1995
45
48
EL PASO NATURAL GAS COMPANY
CONSOLIDATED QUARTERLY INFORMATION
YEARS ENDED DECEMBER 31, 1994 AND 1993
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
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
======== ======== ======== ========
1993
Operating revenues............................ $232,349 $245,056 $220,611 $210,912
======== ======== ======== ========
Operating income.............................. $ 53,177 $ 55,487 $ 57,397 $ 63,184
======== ======== ======== ========
Net income.................................... $ 21,785 $ 18,365 $ 20,683 $ 30,840
======== ======== ======== ========
Earnings per common share..................... $ 0.59 $ 0.49 $ 0.55 $ 0.83
======== ======== ======== ========
46
49
SCHEDULE II
EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
(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
- -------------------------------------------- ---------- --------- -------- ---------- ----------
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(b) $ 3,868
Allowance for gas imbalances.............. 12,097 -- -- 6,500(c) 5,597
Allowance for take-or-pay receivables..... -- 19,387 -- -- 19,387
1992(a)
Allowance for bad debts................... $ 8,229 $ -- $ 115 $ 3,260(b) $ 5,084
Allowance for gas imbalances.............. 2,082 10,015 -- -- 12,097
(a) Presentation of prior years has been changed to conform to current year
presentation.
(b) Primarily accounts charged off.
(c) Primarily accounts recovered.
47
50
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 1995 Annual Meeting of
Stockholders (the "Proxy Statement") 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
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 a Certain
Beneficial Owner and Management" in the Proxy Statement is incorporated herein
by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
48
51
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 statement of income...................................... 23
Consolidated balance sheet............................................ 24
Consolidated statement of cash flows.................................. 25
Consolidated statement of stockholders' equity........................ 26
Notes to consolidated financial statements............................ 27
Report of independent accountants..................................... 45
2. Financial statement schedules and supplementary information required
to be submitted.
Consolidated quarterly information.................................... 46
Schedule II - Valuation and qualifying accounts....................... 47
Schedules other than those listed above are omitted because they are
not applicable
3. Exhibit list.......................................................... 50
(B) REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the quarter
ended December 31, 1994.
49
52
EL PASO NATURAL GAS COMPANY
EXHIBIT LIST
DECEMBER 31, 1994
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.
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.
*10.D -- Transportation Service Agreement as Amended and Restated effective
July 16, 1993, between EPG and Southern California Gas Company.
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).
*10.E.1 -- 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.
50
53
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).
51
54
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 -- Incentive Compensation Plan dated as of January 1, 1992, (Amendment
No. 1 to Form S-2, No. 33-45369, filed February 27, 1992).
10.K -- Compensation Plan for Non-Employee Directors dated as of January 1,
1992, (Amendment No. 1 to Form S-2, No. 33-45369, filed February 27,
1992).
10.L -- 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 -- Rights Plan dated as of January 1, 1992, (Amendment No. 1 to Form
S-2, No. 33-45369, filed February 27, 1992).
*10.N -- Supplemental Benefits Plan, Amended and Restated Effective as of
January 13, 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.
*10.Q -- Retirement Income Plan for Non-Employee Directors, Amended and
Restated Effective as of January 13, 1995.
*10.R -- Key Executive Severance Protection Plan, Amended and Restated
Effective as of January 13, 1995.
*10.S -- Director Charitable Award Plan, Amended and Restated Effective as of
January 13, 1995.
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 The Company and
William A. Wise (Form 10-K, No. 1-2700, filed February 3, 1993).
10.V -- Letter Agreement dated October 22, 1990, between The Company and
Luino Dell'Osso, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
10.W -- Letter Agreement dated February 22, 1991, between The Company and
Britton White, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
*10.X -- Letter Agreement dated January 13, 1995, between The Company and
William A. Wise.
*11 -- Computation of Earnings per Common Share.
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*21 -- Subsidiaries of the Registrant.
*23 -- Consents of Experts and Counsel.
*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.
52
55
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, January 13, 1995
(William A. Wise) President, Chief
Executive Officer, and
Director
/s/ LUINO DELL'OSSO JR. Vice Chairman of the January 13, 1995
(Luino Dell'Osso Jr.) Board, Chief Operating
Officer, and Director
/s/ H. BRENT AUSTIN Senior Vice President January 13, 1995
(H. Brent Austin) and Chief Financial
Officer
/s/ THOMAS E. RICKS Vice President, Chief January 13, 1995
(Thomas E. Ricks) Accounting Officer, and
Controller
/s/ BYRON ALLUMBAUGH Director January 13, 1995
(Byron Allumbaugh)
Director January 13, 1995
(Eugenio Garza Laguera)
/s/ JAMES F. GIBBONS Director January 12, 1995
(James F. Gibbons)
/s/ BEN F. LOVE Director January 13, 1995
(Ben F. Love)
/s/ KENNETH L. SMALLEY Director January 13, 1995
(Kenneth L. Smalley)
53
56
EXHIBIT INDEX
EXHIBIT
NUMBER EXHIBIT
- ---------- ------------------------------------------------------------------------
3(i) -- Restated Certificate of Incorporation of The Company dated January 2,
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.
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.
10.D -- Transportation Service Agreement as amended and Restated effective
July 16, 1993, between EPG and Southern California Gas Company.
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).
10.E.1 -- 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.
57
EXHIBIT
NUMBER EXHIBIT
- ---------- ------------------------------------------------------------------------
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).
58
EXHIBIT
NUMBER EXHIBIT
- ---------- ------------------------------------------------------------------------
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 -- Incentive Compensation Plan dated as of January 1, 1992, (Amendment
No. 1 to Form S-2, No. 33-45369, filed February 27, 1992).
10.K -- Compensation Plan for Non-Employee Directors dated as of January 1,
1992, (Amendment No. 1 to Form S-2, No. 33-45369, filed February 27,
1992).
10.L -- 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 -- Rights Plan dated as of January 1, 1992, (Amendment No. 1 to Form
S-2, No. 33-45369, filed February 27, 1992).
10.N -- Supplemental Benefits Plan, Amended and Restated Effective as of
January 13, 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.
10.Q -- Retirement Income Plan for Non-Employee Directors, Amended and
Restated Effective as of January 13, 1995.
10.R -- Key Executive Severance Protection Plan, Amended and Restated
Effective as of January 13, 1995.
10.S -- Director Charitable Award Plan, Amended and Restated Effective as of
January 13, 1995.
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 The Company and
William A. Wise (Form 10-K, No. 1-2700, filed February 3, 1993).
10.V -- Letter Agreement dated October 22, 1990, between The Company and
Luino Dell'Osso, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
10.W -- Letter Agreement dated February 22, 1991, between The Company and
Britton White, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
10.X -- Letter Agreement dated January 13, 1995, between The Company and
William A. Wise.
11 -- Computation of Earnings per Common Share.
12 -- Computation of Ratio of Earnings to Fixed Charges.
21 -- Subsidiaries of the Registrant.
23 -- Consents of Experts and Counsel.
27 -- Financial Data Schedule.