Back to GetFilings.com
1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
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
304 TEXAS AVENUE, 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 .
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 14,
1994, computed by reference to the closing sale price of the registrant's common
stock on the New York Stock Exchange on such date: $1,359,380,797.
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 14, 1994: 36,864,564.
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
1994 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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2
EL PASO NATURAL GAS COMPANY
TABLE OF CONTENTS
ITEM NO. CAPTION PAGE
- -------- ------- ----
PART I
1. and 2. Business and Properties.................................................... 1
3. Legal Proceedings.......................................................... 10
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................................ 22
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure............................................................... 51
PART III
10. Directors and Executive Officers of the Registrant......................... 51
11. Executive Compensation..................................................... 51
12. Security Ownership of Certain Beneficial Owners and Management............. 51
13. Certain Relationships and Related Transactions............................. 51
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............ 52
Signatures................................................................. 56
i
3
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 field and mainline natural gas transmission
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"). On June 30, 1992, BR distributed all of EPG's 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.
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 gives 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 construction,
ownership and operation of 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.
Regulatory Environment
EPG's and MPC's pipeline facilities, services and rates are regulated by
the Federal Energy Regulatory Commission ("FERC") in accordance with the Natural
Gas Act of 1938 and the Natural Gas Policy Act of 1978. Prior to the mid-1980s,
EPG, as was the case with virtually all other interstate pipelines, was engaged
primarily in the business of purchasing gas from producers at the wellhead and
reselling such gas to local distribution companies, such as Southern California
Gas Company ("SoCal") and Pacific Gas & Electric Company ("PG&E"), for resale to
retail customers and to large industrial and electric generation concerns for
their own consumption. During this period, almost all of the gas that moved
through EPG's system was gas that EPG purchased for resale to its customers
("sales service"). Gas that EPG transported for others ("transportation
service") constituted a very small portion of EPG's total throughput.
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
1
4
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.
Components of Consolidated Revenues
The following table sets forth the components of the Company's consolidated
revenues:
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Reservation(a)..................................... $483,471 $346,027 $189,721
Transportation..................................... 59,631 141,789 227,280
Gas and liquid sales............................... 280,839 237,965 182,797
All other(b)....................................... 84,987 77,031 135,398
-------- -------- --------
Total.................................... $908,928 $802,812 $735,196
-------- -------- --------
-------- -------- --------
- ------------
(a) Reservation revenue relates to the charge for firm transportation service
or, prior to September 1991, firm sales service.
(b) Included in "All other" are revenues generated from gas gathering services
on the field transmission systems.
In 1993, natural gas deliveries to SoCal, PG&E and Southwest Gas
Corporation accounted for 26 percent, 19 percent and 10 percent, respectively,
of the Company's revenues. No other customer accounted for 10 percent or more of
the Company's consolidated revenues. The Company's revenues for volumes
transported to the Mexico border represented less than one percent of the
Company's operating revenues for each of 1993, 1992 and 1991.
EL PASO NATURAL GAS COMPANY
General
EPG is directly connected to three of the nation's most prolific gas
producing areas -- the San Juan, Permian and Anadarko Basins. During 1993, EPG
delivered 1.3 trillion cubic feet ("Tcf") of natural gas, accounting for
approximately seven percent of estimated total 1993 United States consumption.
EPG's system consists of approximately 17,000 miles of pipeline with 77
mainline compressor stations having an aggregate installed horsepower of
approximately 1.1 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 1993, EPG delivered approximately 43 percent of
all the natural gas consumed in California.
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
2
5
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 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,
-------------------------
1993 1992 1991
----- ----- -----
Transportation
California................................................ 2,288 2,551 2,736
East-of-California........................................ 599 596 477
Off-system................................................ 691 560 525
----- ----- -----
Total transportation........................................ 3,578 3,707 3,738
Total sales (at the citygate)............................... -- -- 121
----- ----- -----
Total throughput.................................. 3,578 3,707 3,859
----- ----- -----
----- ----- -----
Gathering and Production Area Facilities
On January 14, 1994, EPG filed an application with FERC seeking an order
which would terminate, effective January 1, 1996, certificates applicable to
certain gathering and production area facilities owned by EPG on the basis that
such facilities are not subject to FERC jurisdiction.
EPG intends, effective January 1, 1996, to transfer all of its
nonjurisdictional gathering and production area facilities to a wholly owned
subsidiary of EPG. 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 horsepower of 40,600 and
various treating and processing plants. These nonjurisdictional facilities,
together with the facilities included in the January 14, 1994 FERC application,
constitute all of EPG's gathering and production area facilities.
Rate Matters
On July 1, 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. On
July 31, 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 on December 31, 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 31, 1992 compliance filing. As required by FERC order,
EPG filed revised rates on September 14, 1993, which implemented the settlement
agreement effective October 1, 1993.
The settlement agreement provides for the accelerated recovery of a
substantial portion of EPG's investment in its underground storage facility.
This is being recovered by a demand charge mechanism over the period from
October 1, 1993 through December 31, 1996. The amount recovered through December
31, 1993 was $19 million. The outstanding balance was $37 million at December
31, 1993. The settlement agreement also established new depreciation rates for
certain of EPG's facilities effective January 1, 1992.
3
6
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. Pursuant to FERC orders,
EPG has absorbed approximately 25 percent of such costs and is entitled to
recover the balance. Such recovery is made through direct billing of EPG's
customers of 25 percent of the $1.5 billion and through a surcharge on all
throughput volumes for the remaining 50 percent of such amount. 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 the direct bill portion of the take-or-pay
buy-out and buy-down costs extends through May 1994. The collection period for
the volumetric surcharge portion of such costs extends through March 1996.
Through December 31, 1993, EPG had recovered approximately $1.0 billion; of that
recovery, $361 million was collected by direct bill and $682 million by
volumetric surcharge. EPG has established a reserve for that portion of the
volumetric surcharge receivables balance which is unlikely to be collected over
the period through March 1996, based on current throughput projections. The
balance of this reserve was $19 million at December 31, 1993.
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. The remaining issue
involves the claim by several customers that EPG has 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. On March 8,
1993, an initial decision from the presiding Administrative Law Judge ("ALJ")
was rendered which, if adopted without changes by FERC, would require EPG to
refund to or forgo collection from its customers of up to $30 million, plus
interest. Exceptions to this initial decision were filed with FERC by both
parties on April 7, 1993. On April 27, 1993, briefs opposing exceptions were
filed by the same parties as well as by FERC staff. EPG has established adequate
reserves for this issue and does not believe that the ultimate outcome will have
a materially adverse effect on the Company's financial condition or results of
operations.
On January 14, 1992, EPG completed a sale of substantially all of its
remaining take-or-pay buy-out and buy-down receivables. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Financial Condition and Liquidity -- Take-or-pay Settlements."
Gas Supply
During 1993, approximately 270 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 1993. During 1993, EPG received an
average of 1.8 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. The total cost of the expansion and modification projects was
approximately $250 million.
On July 7, 1992, EPG filed an application with FERC, which was amended on
November 27, 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 provide shippers the opportunity to deliver natural gas to
Mexican markets in northern Baja California via new pipeline capacity of 348
MMcf/d. This project is expected to cost approximately
4
7
$71 million and will be financed through internally generated funds or through
short-term borrowings. On November 29, 1993, FERC issued an order which approved
the siting, construction and operation of facilities necessary for a border
crossing facility in Yuma, Arizona which would connect the proposed extension
with pipeline facilities in Mexico. The order also made a preliminary
determination on environmental issues. FERC is deferring action on the remainder
of the July 7, 1992 filing until EPG demonstrates that it has long-term executed
contracts or binding precedent agreements for a substantial amount of the firm
capacity of the proposed facilities.
EPG is a member of a five-company consortium that plans to build the
proposed Samalayuca II Power Plant near Ciudad Juarez, Mexico. On December 17,
1992, an award for construction was granted to the consortium by Comision
Federal de Electricidad, the Mexican government-owned utility. On March 16,
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 and
will be financed through internally generated funds or through short-term
borrowings. In the November 29, 1993 order, FERC also approved the proposed
border crossing facility south of Clint, Texas which would connect EPG's
facilities with facilities in Mexico. FERC is deferring action on the remainder
of the March 16, 1993 filing until EPG demonstrates that it has long-term
executed contracts or binding precedent agreements for a substantial amount of
the firm capacity of the proposed facilities.
On December 29, 1993, PG&E, SoCal and the California Public Utilities
Commission ("CPUC") jointly filed a motion with FERC seeking clarification or
rehearing of the November 29, 1993 FERC order for both the Yuma, Arizona and the
Samalayuca II Power Plant projects discussed above.
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
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.
MOJAVE PIPELINE COMPANY
General
In 1990, FERC issued orders authorizing MPC to construct and operate its
pipeline facilities, which commenced operations on March 1, 1992. MPC's system
consists of approximately 400 miles of pipeline with
5
8
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,
-----------------------
1993 1992 1991
--- --- ---
(MMCF/D)
Total MPC throughput....................................... 231 197 --
Included in throughput for May 1993 through December 1993 are 19 MMcf/d of
intercompany transportation volumes. Only revenues associated with the
throughput for May 1993 through December 1993, other than intercompany
throughput, are included in the Company's consolidated results of operations.
Revenues related to throughput associated with the Company's previously owned 50
percent equity interest in MPC are included in other-net in the accompanying
Consolidated Statement of Income.
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 the
pipeline facilities and the design and construction of future pipeline
expansions.
Rate Matters
Pursuant to the Restructuring Rules, MPC filed its restructuring plan on
November 3, 1992. On March 2, 1993, FERC issued an order essentially approving
MPC's compliance filing, subject to changes, which were made in an amended
restructuring plan on March 29, 1993. Several of MPC's customers filed protests
and requests for rehearing of the March 2, 1993 FERC order. The rehearing
requests were denied, and FERC approved the amended restructuring plan on July
9, 1993, with an effective date of August 1, 1993. On October 15, 1993, FERC
issued an order which denied requests for rehearing of the July 9, 1993 order.
Several of MPC's customers have filed petitions for review of the March 2, 1993,
July 9, 1993, and October 15, 1993 orders with the United States Court of
Appeals, which are currently pending.
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, and this increases aggregate transportation charges for low load
factor shippers. 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. MPC believes the United
States Court of Appeals will uphold SFV rates as applied to MPC.
Gas Supply
At certain times during 1993, MPC received as much as 360 MMcf/d at
physical points of interconnection with other pipelines pursuant to
transportation agreements. MPC's maximum mainline system inlet capacity is 400
MMcf/d.
System Expansion
On March 17, 1993, MPC filed an application, which was amended on November
8, 1993, for a certificate of public convenience and necessity to build and
operate a 475 MMcf/d expansion of its existing system. The proposed expansion
will extend from MPC's existing east lateral located near Bakersfield,
California approximately 352 miles northward to the vicinity of Sacramento and
the East Bay area near San Francisco. The expansion will also include 56 miles
of looping of the existing pipeline along with 207 miles of laterals. The
estimated cost of the entire system is $467 million which is expected to be
funded primarily through project financing. MPC expects to receive its FERC
certificate in early 1994 and put the expansion into service in January 1996.
6
9
On December 16, 1993, FERC held a public conference to examine a
jurisdictional question raised by the CPUC and PG&E regarding MPC's system
expansion. The primary issue is whether FERC or CPUC should have jurisdiction
over the proposed expansion. Written comments were filed by interested parties
on January 10, 1994, with a final decision by FERC expected in early 1994.
EL PASO GAS MARKETING COMPANY
EPGM buys and sells natural gas under both short-term and long-term
market-sensitive 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 certificated 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 will decline to a level of 58 MMcf/d in 1994 and continue to
decline in subsequent years. Based on the contract pricing provisions of these
remaining gas supply commitments, EPGM expects that it will experience no
difficulty in continuing to contract for the sale of such gas.
OTHER MATTERS
Competition
Currently, EPG faces 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; Pacific Gas Transmission Company ("PGT") has the capacity to deliver
about 1.8 Bcf/d of Canadian gas; and Kern River Gas Transmission ("Kern River")
has the capacity to deliver approximately 700 MMcf/d from Rocky Mountain supply
sources. PGT completed a 755 MMcf/d expansion of its California capacity on
November 1, 1993. In 1992, Kern River held an open season to determine interest
in expanding capacity to California by 200 MMcf/d; however, no planned
expansions have since been announced.
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 expects 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 fully subscribed under long-term contracts which
provide for the payment of fixed reservation charges.
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 this contract, SoCal has the option to relinquish an additional 300 MMcf/d of
capacity during the first quarter of 1996. 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. CPUC has directed PG&E to maintain 600 MMcf/d of capacity on
EPG's system to service PG&E's core and core subscription service customers. EPG
expects to offset potential future reductions in 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 general, natural gas faces varying degrees of competition from
electricity, coal and oil. Competitive pressure from alternative fuels is less
prevalent in EPG's market area due to strict environmental regulations in
California.
7
10
Environmental Compliance
Accruals for environmental compliance costs are established when
environmental assessments and/or remediation are probable, and when costs can be
reasonably estimated. As of December 31, 1993, EPG had a reserve of $38 million
for the following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of polychlorinated biphenyl
("PCB") contamination at its facilities. The majority of the required PCB
remediation has been completed. Future PCB remediation costs are estimated
to range between $8 million and $11 million over the next five years.
2 -- EPG executed an Administrative Order on Consent with the United States
Environmental Protection Agency ("EPA") on June 25, 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 $20 million
over a 30 year period.
3 -- On November 2, 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 $10 million and $20 million over a 30 year period.
4 -- EPG is involved in other environmental assessment and remediation
activities which include two additional Comprehensive Environmental
Response, Compensation and Liability Act of 1980 ("CERCLA") sites
(Fountain Inn, South Carolina and Odessa, Texas) and one state Superfund
site (Etowah, Tennessee). The amount reserved as of December 31, 1993 will
cover these and other small environmental assessments and other
remediation projects.
EPG also has potential expenditures, of a capital nature, for the following
environmental projects:
1 -- EPG has analyzed the Clean Air Act Amendments of 1990 ("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
nitrogen oxides ("NOx") in non-attainment areas; (ii) the requirement for
air emissions permitting of existing facilities; and (iii) enhanced
monitoring of air emissions. The Company anticipates capitalizing the
equipment costs associated with complying with CAAA and estimates that
approximately $5 million to $27 million will be spent during the 1995
through 1997 time frame. 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 dry flow
devices. The remaining remediation costs are estimated to be between $8
million and $12 million, most of which will be incurred over the next two
years. EPG will close and retire about 5,400 earthen siphon/dehydration
pits in the San Juan Basin as recently required by certain environmental
regulations. EPG estimates costs of approximately $17 million to $25
million to retire these pits over the next two years. The mercury
remediation and pit closure costs, which are associated with the retirement
of equipment, will be recorded as adjustments to accumulated depreciation,
as required by regulatory accounting.
On December 21, 1993, EPA issued EPG a Notice of Liability for the Colorado
School of Mines Research Institute ("CSMRI") site in Golden, Colorado. Because
EPA has not yet determined the volume of hazardous substances sent to the site
by all parties, there is no way to estimate EPG's potential share of remediation
costs. However, based on the volumes EPA presently lists as contributed by EPG
and other potentially responsible parties, it appears that EPG is a minor
contributor.
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, contingency amounts will be adjusted
accordingly.
8
11
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 and
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 2,460 and 2,499 full-time employees on December 31, 1993
and 1992, respectively.
Segment Information
The Company's principal business is its interstate pipeline operations;
therefore, segment information has not been presented.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPG as of January 14, 1994 are as follows:
OFFICER
NAME AGE OFFICE SINCE
- --------------------------------------- ---- --------------------------------------- --------
William A. Wise........................ 48 Chairman of the Board, President and 1983
Chief Executive Officer
Luino Dell'Osso, Jr.................... 54 Executive Vice President and Chief 1990
Operating Officer
H. Brent Austin........................ 39 Senior Vice President and Chief 1992
Financial Officer
Richard Owen Baish..................... 47 Senior Vice President 1987
Michael C. Holland..................... 52 Senior Vice President 1982
Joel Richards III...................... 47 Senior Vice President 1990
John W. Somerhalder II................. 37 Senior Vice President 1990
Britton White, Jr...................... 50 Senior Vice President and General 1991
Counsel
Mr. Wise has been Chairman of the Board of EPG since January 1994. Mr. Wise
has been Chief Executive Officer of EPG since January 1990 and President of EPG
since April 1989. Mr. Wise was Chief Operating Officer of EPG from April 1989 to
December 1989. From March 1987 until April 1989, Mr. Wise was an Executive Vice
President of EPG. From January 1984 to February 1987, Mr. Wise was a Senior Vice
President of EPG.
Mr. Dell'Osso has been Executive Vice President and Chief Operating Officer
of EPG since November l990. Mr. Dell'Osso was Senior Vice President and Chief
Financial Officer of BR from April 1989 until October l990 and Senior Vice
President, Finance and Planning of BR from May 1988 until March 1989. From April
1984 until December 1988, Mr. Dell'Osso was Senior Vice President, Finance and
Planning of Burlington Northern Inc., ("BNI").
Mr. Austin has been Senior Vice President and Chief Financial Officer of
EPG since April 1992. Mr. Austin was Vice President, Planning and Treasurer of
BR from November l990 to March 1992 and was Assistant Vice President, Planning
of BR from January 1989 to October l990 and Director, Planning of BNI from
September 1986 to December 1988.
Mr. Baish has been Senior Vice President, Marketing, Regulatory and Rates
of EPG since January l991. Mr. Baish was Senior Vice President, General Counsel
and Secretary of EPG from November 1990 to December 1990, Vice President and
Associate General Counsel of EPG from March 1987 to October 1990 and Assistant
General Counsel of EPG from February 1984 to February 1987.
Mr. Holland has been Senior Vice President, Joint Operations of EPG since
January 1991. Mr. Holland was a Vice President of EPG 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, Human Resources and
Administration of EPG since January 1991. Mr. Richards was Vice President, Human
Resources of EPG from June 1990 to December
9
12
1990. Mr. Richards was Senior Vice President, Finance and Human Resources of
Meridian Minerals Company, a wholly owned subsidiary of BR, from October 1988 to
June 1990 and was Vice President, Human Resources and Administration of Meridian
Minerals Company from September 1985 to October 1988.
Mr. Somerhalder has been Senior Vice President, Operations and Engineering
of EPG since August 1992. Mr. Somerhalder was Vice President, Engineering and
Technical Services of EPG from January 1990 to July 1992. For five years prior
to that time, Mr. Somerhalder served in a managerial capacity with EPG.
Mr. White has been Senior Vice President and General Counsel of EPG since
March 1991. From March 1991 to April 1992, Mr. White was also Secretary of EPG.
For more than five years prior to that time, Mr. White was a partner in the law
firm of Holland & Hart.
On December 31, 1993, Richard M. Bressler retired as Chairman of the Board
of EPG. Mr. Bressler had been Chairman since November 1990.
ITEM 3. LEGAL PROCEEDINGS
In El Paso Natural Gas Company and Meridian Oil Gathering Inc. v. Amoco
Production Company, filed in Delaware Chancery 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 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, and has 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 lights 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; however, the court's decision has not yet been issued.
Post-trial briefing and oral arguments concluded in early November 1993, and the
decision of the court is expected in early 1994. Management does not expect the
outcome of this matter to have a materially adverse effect on the Company's
financial condition.
The Company is a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of business.
While the outcome of such lawsuits or other proceedings against the Company
cannot be predicted with certainty, management 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 1993, no matters were submitted to a vote of
security holders.
10
13
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. On June 30, 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
14, 1994 the approximate number of holders of record of common stock was 25,673.
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)
1993
First Quarter.............................. $38.000 $30.250 $ 0.275
Second Quarter............................. $40.250 $35.250 $ 0.275
Third Quarter.............................. $40.375 $36.125 $ 0.275
Fourth Quarter............................. $39.500 $33.750 $ 0.275
1992
First Quarter.............................. $22.750 $20.250 --
Second Quarter............................. $24.375 $21.125 $ 0.250
Third Quarter.............................. $30.125 $23.750 $ 0.250
Fourth Quarter............................. $31.500 $26.875 $ 0.250
On January 14, 1994, EPG's Board of Directors declared a quarterly dividend
of $0.3025 per share on EPG's common stock, payable on April 4, 1994 to
shareholders of record on March 11, 1994.
11
14
ITEM 6. SELECTED FINANCIAL DATA
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
1993(e) 1992 1991 1990 1989
--------- --------- --------- --------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
For the Year:
Operating revenues............. $ 908,928 $ 802,812 $ 735,196 $ 851,750 $ 904,736
Depreciation and
amortization................ 54,051 73,229 61,300 67,098 62,624
Operating income............... 229,245 184,910 184,919 190,012 200,805
Income from continuing
operations before income
taxes....................... 150,826 123,289 140,500 128,481 143,009
Income taxes................... 59,153 46,963 51,956 44,847 45,155
Income from continuing
operations.................. 91,673 76,326 88,544 83,634 97,854
Earnings per common share --
continuing operations(a).... 2.46 2.12 2.82 2.66 3.05
Cash dividends declared per
common share(b)............. 1.10 .75 -- -- --
At Year End:
Total assets(c)................ 2,269,663 2,050,729 2,301,932 3,817,896 3,807,659
Payable to BR, including
current portion............. -- -- 624,804 -- --
Long-term debt(d).............. 795,783 637,074 249,942 848,633 631,516
Stockholders' equity(c)........ 707,548 668,992 814,878 1,828,261 1,715,518
- ------------
(a) Earnings per share of common stock is based on 37,212,192 weighted average
shares of common stock outstanding for 1993, 36,049,135 weighted average
shares of common stock outstanding for 1992 and 31,421,731 shares of common
stock outstanding for the years 1989 through 1991.
(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 has been consolidated for the months of May 1993 through December 1993.
12
15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
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.
Cash provided by continuing operating activities was $334 million for 1992
compared with $249 million for 1991. The increase was primarily due to proceeds
from the sale of the direct bill portion of the take-or-pay receivables, the
1991 net cash payments made in connection with the August 14, 1991 FERC order
(see Rates and Regulatory Matters of this section), the decrease in take-or-pay
expenditures and a decrease in interest payments. The increase was partially
offset by a reduction in volumetric take-or-pay receivable collections and a
decrease in accruals for regulatory issues.
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, gives 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 following MPC balances are included in the December 31, 1993
Consolidated Balance Sheet of the Company:
(IN THOUSANDS)
Cash and other current assets.................................. $ 19,570
Property, plant and equipment, net............................. 224,075
Regulatory assets and other.................................... 34,420
--------------
Total assets......................................... $278,065
--------------
--------------
Current liabilities............................................ $ 10,879
Long-term debt, less current portion........................... 158,584
Deferred income taxes and deferred credits..................... 20,427
Equity......................................................... 88,175
--------------
Total liabilities and equity......................... $278,065
--------------
--------------
The operating results of MPC are included in the Company's consolidated
results of operations for 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 accompanying Consolidated Statement of Income.
13
16
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 and 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
Gathering and Production Area Facilities
On January 14, 1994, EPG filed an application with FERC seeking an order
which would terminate, effective January 1, 1996, certificates applicable to
certain gathering and production area facilities owned by EPG on the basis that
such facilities are not subject to FERC jurisdiction.
EPG intends, effective January 1, 1996, to transfer all of its
nonjurisdictional gathering and production area facilities to a wholly owned
subsidiary of EPG. 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 horsepower of 40,600 and
various treating and processing plants. These nonjurisdictional facilities,
together with the facilities included in the January 14, 1994 FERC application,
constitute all of EPG's gathering and production area facilities.
Rates and Regulatory Matters
On July 1, 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. On
July 31, 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 on December 31, 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 31, 1992 compliance filing. As required by FERC order,
EPG filed revised rates on September 14, 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 provides for the accelerated recovery of a
substantial portion of EPG's investment in its underground storage facility.
This is being recovered by a demand charge mechanism over the period from
October 1, 1993 through December 31, 1996. The amount to be recovered was
approximately $56.7 million plus interest accruing beginning February 1, 1993 at
the FERC allowed rate, which approximates the prime rate. The amount recovered
through December 31, 1993 was $19 million. The outstanding balance at December
31, 1993 was $37 million, of which $12 million is included in other current
assets and $25 million is included in other assets in the accompanying
Consolidated Balance Sheet. The settlement agreement also established new
depreciation rates for certain of EPG's facilities effective January 1, 1992.
On August 14, 1991, FERC approved an order resolving all of the issues in
EPG's December 1987 rate case filing and certain other pending matters which
became effective on September 1, 1991. The order provided for: (i) the
establishment of revised rate levels for the period July 1, 1988 through the
effective date of EPG's next rate change, which occurred on January 1, 1992; and
(ii) payment of certain refunds for the
14
17
period July 1, 1988 through August 31, 1991. EPG disbursed to its customers $252
million in October 1991 in accordance with the order. The total refund
obligation at September 1, 1991 was $369 million before certain offsets,
including an unbilled portion of the $169 million of recoverable excess gas
costs. The net refund obligation and the remaining balance of the recoverable
excess gas costs, $25 million, were recorded against previously established
accruals.
Pursuant to the Restructuring Rules, MPC filed its restructuring plan on
November 3, 1992. On March 2, 1993, FERC issued an order essentially approving
MPC's compliance filing, subject to changes, which were made in an amended
restructuring plan on March 29, 1993. Several of MPC's customers filed protests
and requests for rehearing of the March 2, 1993 FERC order. The rehearing
requests were denied, and FERC approved the amended restructuring plan on July
9, 1993, with an effective date of August 1, 1993. On October 15, 1993, FERC
issued an order which denied requests for rehearing of the July 9, 1993 order.
Several of MPC's customers have filed petitions for review of the March 2, 1993,
July 9, 1993 and October 15, 1993 orders with the United States Court of Appeals
which are currently pending.
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, and this increases aggregate transportation charges for
low load factor shippers. 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. MPC believes the
United States Court of Appeals will uphold SFV rates as applied to MPC.
Take-or-Pay Settlements
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. In
certain cases, EPG resolved claims by making recoupable prepayments. At December
31, 1993 and December 31, 1992, the recoupable prepayment balances were $9
million and $19 million, respectively. 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.
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 the direct bill
portion of the take-or-pay buy-out and buy-down costs extends through May 1994.
The collection period for the volumetric surcharge portion of such costs extends
through March 1996. Through December 31, 1993, EPG had recovered approximately
$1.0 billion; of that recovery, $361 million was collected by direct bill and
$682 million by volumetric surcharge. EPG has established a reserve for that
portion of the volumetric surcharge receivables balance which is unlikely to be
collected over the period through March 1996, based on current throughput
projections. The balance of this reserve was $19 million at December 31, 1993.
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. The remaining issue
involves the claim by several customers that EPG has 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. On March 8,
1993, an initial decision from the presiding ALJ was rendered which, if adopted
without changes by FERC, would require EPG to refund to or forgo collection from
its customers of up to $30 million, plus interest. Exceptions to this initial
decision were filed with FERC by both parties on April 7, 1993. On April 27,
1993, briefs opposing exceptions were filed by the same parties as well as by
FERC staff. EPG has established adequate reserves for this issue and does not
believe that the ultimate outcome will have a materially adverse effect on the
Company's financial condition or results of operations.
15
18
On January 14, 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, 1993 and December 31, 1992, $87 million and $125 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.
Restructuring and Financing Transactions
In February 1992, EPG established a $300 million revolving credit facility
with a group of banks which expires in March 1996. As of December 31, 1993,
there were no borrowings outstanding under this facility. Approximately $1
million of commercial paper was outstanding as of December 31, 1993.
During 1992 and 1991, EPG completed several transactions in preparation for
its separation from BR. Among these transactions was the transfer of the net
assets of El Paso Production Company ("EPPC") and Meridian Oil Hydrocarbons Inc.
("Hydrocarbons"), collectively, the Company's Oil and Gas Operations Segment,
which is reported as discontinued operations.
In December 1991, EPG declared and paid a dividend to BR of $55 million. 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. On June 30, 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 common stock. As
a result, BR no longer retains an ownership interest in EPG.
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. At December
31, 1991, outstanding borrowings under the Commitment and Loan Agreements were
$300 million and $325 million, respectively. In January 1992, additional
borrowings of $109 million were made under the Loan Agreements to purchase the
notes and debentures described below.
EPG also undertook certain transactions to establish an appropriate capital
structure for its post-separation operations. In December 1991 and January 1992,
EPG purchased notes and debentures totaling $253 million and $134 million,
respectively. Funds were provided by proceeds from borrowings under the BR 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
with BR, redemption of debentures and payment of general corporate costs.
EPG repaid its outstanding commercial paper in December 1991 with
borrowings under the Commitment Agreement with BR. The proceeds from the sale of
the take-or-pay receivables, previously discussed herein, were used to repay the
borrowings under the Commitment Agreement with BR.
The Commitment Agreement and the Loan Agreements with BR were terminated
prior to the completion of the Offering.
Competition
Currently, EPG faces 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
16
19
gas to California. Transwestern has the capacity to deliver approximately 1.1
Bcf/d from Permian, Anadarko and San Juan Basin supply sources; PGT has the
capacity to deliver about 1.8 Bcf/d of Canadian gas; and Kern River has the
capacity to deliver approximately 700 MMcf/d from Rocky Mountain supply sources.
PGT completed a 755 MMcf/d expansion of its California capacity on November 1,
1993. In 1992, Kern River held an open season to determine interest in expanding
capacity to California by 200 MMcf; however, no planned expansions have since
been announced.
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 expects 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 fully subscribed under long-term contracts which
provide for the payment of fixed reservation charges.
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 this contract, SoCal has the option to relinquish an additional 300 MMcf/d of
capacity during the first quarter of 1996. 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. CPUC has directed PG&E to maintain 600 MMcf/d of capacity on
EPG's system to service PG&E's core and core subscription service customers. EPG
expects to offset potential future reductions in 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 general, natural gas faces varying degrees of competition from
electricity, coal and oil. Competitive pressure from alternative fuels is less
prevalent in EPG's market area due to strict environmental regulations in
California.
Environmental
Accruals for environmental compliance costs are established when
environmental assessments and/or remediation are probable, and when costs can be
reasonably estimated. As of December 31, 1993, EPG had a reserve of $38 million
for the following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of PCB contamination at its
facilities. The majority of the required PCB remediation has been
completed. Future PCB remediation costs are estimated to range between $8
million and $11 million over the next five years.
2 -- EPG executed an Administrative Order on Consent with EPA on June 25,
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
$20 million over a 30 year period.
3 -- On November 2, 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 $10 million and
$20 million over a 30 year period.
4 -- EPG is involved in other environmental assessment and remediation
activities which include two additional CERCLA sites (Fountain Inn, South
Carolina and Odessa, Texas) and one state Superfund site (Etowah,
Tennessee). The amount reserved as of December 31, 1993 will cover these
and other small environmental assessments and other remediation projects.
17
20
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. The Company anticipates
capitalizing the equipment costs associated with complying with CAAA and
estimates that approximately $5 million to $27 million will be spent during
the 1995 through 1997 time frame. 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 dry flow
devices. The remaining remediation costs are estimated to be between $8
million and $12 million, most of which will be incurred over the next two
years. EPG will close and retire about 5,400 earthen siphon/dehydration
pits in the San Juan Basin as recently required by certain environmental
regulations. EPG estimates costs of approximately $17 million to $25
million to retire these pits over the next two years. The mercury
remediation and pit closure costs, which are associated with the retirement
of equipment, will be recorded as adjustments to accumulated depreciation,
as required by regulatory accounting.
On December 21, 1993, EPA issued EPG a Notice of Liability for the CSMRI
site in Golden, Colorado. Because EPA has not yet determined the volume of
hazardous substances sent to the site by all parties, there is no way to
estimate EPG's potential share of remediation costs. However, based on the
volumes EPA presently lists as contributed by EPG and other potentially
responsible parties, it appears that EPG is a minor contributor.
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, contingency amounts will be adjusted
accordingly.
Common Stock Transactions Subsequent to the Offering
For the year ended December 31, 1993, EPG paid approximately $40 million in
dividends. On January 14, 1994, EPG's Board of Directors declared a quarterly
dividend of $0.3025 per share on EPG's common stock, payable on April 4, 1994 to
shareholders of record on March 11, 1994.
On October 22, 1992, EPG's Board of Directors 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 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 in the fourth quarter 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 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.
A total of 2,300 and 132,700 restricted shares of EPG's common stock were
granted to certain employees for 1993 and 1992, respectively. The market value
of such shares awarded was approximately $0.1 million and $2.8 million in 1993
and 1992, respectively.
Capital Expenditures
The Company's planned capital expenditures for 1994 of approximately $210
million are primarily for maintenance of business, system expansion and system
enhancement. These expenditures are expected to be
18
21
financed through internally generated funds. Capital expenditures for 1993 were
$164 million compared to $246 million for 1992. The decrease was due primarily
to the 1992 completion of system expansion and enhancement projects.
On July 7, 1992, EPG filed an application with FERC, which was amended on
November 27, 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 provide shippers the opportunity to deliver natural gas to
Mexican markets in northern Baja California via new pipeline capacity of 348
MMcf/d. This project is expected to cost approximately $71 million and will be
financed through internally generated funds or through short-term borrowings. On
November 29, 1993, FERC issued an order which approved the siting, construction
and operation of facilities necessary for a border crossing facility in Yuma,
Arizona which would connect the proposed extension with pipeline facilities in
Mexico. The order also made a preliminary determination on environmental issues.
FERC is deferring action on the remainder of the July 7, 1992 filing until EPG
demonstrates that it has long-term executed contracts or binding precedent
agreements for a substantial amount of the firm capacity of the proposed
facilities.
EPG is a member of a five-company consortium that plans to build the
proposed Samalayuca II Power Plant near Ciudad Juarez, Mexico. On December 17,
1992, an award for construction was granted to the consortium by the Comision
Federal de Electricidad, the Mexican government-owned utility. On March 16,
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 and
will be financed through internally generated funds or through short-term
borrowings. In the November 29, 1993 order, FERC also approved the proposed
border crossing facility south of Clint, Texas which would connect EPG's
facilities with facilities in Mexico. FERC is deferring action on the remainder
of the March 16, 1993 filing until EPG demonstrates that it has long-term
executed contracts or binding precedent agreements for a substantial amount of
the firm capacity of the proposed facilities.
On December 29, 1993, PG&E, SoCal and the CPUC jointly filed a motion with
FERC seeking clarification or rehearing of the November 29, 1993 FERC order for
both the Yuma, Arizona and the Samalayuca II Power Plant projects discussed
above.
On March 17, 1993, MPC filed an application, which was amended on November
8, 1993, for a certificate of public convenience and necessity to build and
operate a 475 MMcf/d expansion of its existing system. The proposed expansion
will extend from MPC's existing east lateral located near Bakersfield,
California approximately 352 miles northward to the vicinity of Sacramento and
the East Bay area near San Francisco. The expansion will also include 56 miles
of looping of the existing pipeline along with 207 miles of laterals. The
estimated cost of the entire system is $467 million which is expected to be
funded primarily through project financing. MPC expects to receive its FERC
certificate in early 1994 and put the expansion into service in January 1996.
On December 16, 1993, FERC held a public conference to examine a
jurisdictional question raised by CPUC and PG&E regarding MPC's system
expansion. The primary issue is whether FERC or CPUC should have jurisdiction
over the proposed expansion. Written comments were filed by interested parties
on January 10, 1994, with a final decision by FERC expected in early 1994.
Other
In January 1993, EPG experienced flood damage to its pipeline system in the
Gila, Arizona area due to heavy rain. Since that time, EPG has been incurring
costs for repairs and expects to be reimbursed through its property insurance
policies once all repairs have been completed.
RESULTS OF OPERATIONS
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
19
22
offset by a decrease in transportation revenues of $70 million. The
consolidation of MPC contributed $27 million to the increase. Higher production
area rates and volumes 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 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.
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.
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.
Allowance for funds used during construction ("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.
Year Ended December 31, 1992 Compared to Year Ended December 31, 1991
Operating revenues for 1992 were $68 million higher than 1991. The overall
increase in revenues was due primarily to new rates placed into effect on
January 1, 1992. The new rates resulted in a $156 million increase in
reservation revenues, which reflects the shift from firm sales service to firm
transportation service. By unbundling its sales service, the Company's sales
occur at the mainline receipt point as opposed to the delivery point. Lower
accruals for regulatory issues resulted in an increase in revenues of $42
million. Higher sales volumes resulted in increased revenues of $88 million;
however, lower sales rates offset that increase by $23 million. Also offsetting
the increases were lower transportation rates which resulted in decreased
revenues of $113 million. Other decreases affecting the improved 1992 results
were a $30 million decrease in production area revenues resulting from the sale
of certain gathering and processing facilities and lower rates, a $28 million
decrease in return on take-or-pay receivables, an $11 million decrease in liquid
revenues and a $6 million decrease in interest on receivables from customers.
Operating charges were $68 million higher for 1992 compared to 1991. The
increase was primarily due to higher purchased gas costs. Higher sales volumes
resulted in a $72 million increase in purchased gas costs; however, this
increase was partially offset by a $15 million decrease due to lower gas
purchase prices. A $12 million increase in depreciation and a $7 million
increase in taxes, other than income taxes, both resulting from system
expansions, also contributed to the increase in operating charges. An $8 million
decrease in operation and maintenance costs was principally due to reductions in
fees paid to outside operators and
20
23
contractors, partially offset by additional costs allocated to the Company from
BR resulting from the separation of the two companies.
Throughput for 1992 was 1,357 Bcf compared to 1,409 Bcf in 1991. The
decrease in throughput was principally due to increased competition in the
California markets. Lower deliveries to California were partially offset by
higher throughput to the East-of-California and off-system markets.
Interest and debt expense was $68 million for 1992 compared with $98
million for 1991. The decrease was primarily due to a $18 million reduction in
interest on commercial paper, which balance was repaid in December 1991, and a
$17 million reduction in interest on rate refund, which refund was made in
October 1991. These decreases were partially offset by an $8 million increase
resulting from the cost of the take-or-pay receivables sale.
Interest income from BR was $2 million for 1992 compared with $38 million
for 1991. This decrease was due to the dividends declared and paid to BR in
December 1991 and in January and February 1992, from the balance owed by BR to
EPG under the intercorporate cash management arrangement.
Reported as other-net was $2 million expense for 1992 compared with $12
million income for 1991. Contributing to lower income in 1992 was a $5 million
decrease in net gains on dispositions of facilities; a $7 million reduction in
MPC partnership earnings resulting from a non-recurring income adjustment in
1991; and a $6 million increase in other interest. A $6 million increase in
income from temporary investments and other interest income partially offset the
lower income.
OTHER
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 106 ("SFAS 106") requiring companies to account for
other post-retirement 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 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 exceed the amounts
reflected in the settlement agreement, a regulatory asset has been recorded.
Management expects such amounts to be fully recovered through its rates.
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 112 ("SFAS 112") which requires companies to account
for benefits to former or inactive employees after employment but before
retirement (referred to in SFAS 112 as "postemployment benefits"). SFAS 112 is
effective for the fiscal years beginning after December 15, 1993. 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. The cumulative effect at January 1, 1994
of adopting SFAS 112 is estimated to be approximately $8 million. Management
expects to fully recover its postemployment benefit costs through rates.
The Revenue Reconciliation Act of 1993, enacted in August 1993, changed the
corporate income tax rate from 34 to 35 percent effective January 1, 1993. As a
result, the Company's current year provision for income tax expense was adjusted
in the third quarter of 1993 by approximately $1 million, of which $0.5 million
is related to the balance of deferred income taxes at December 31, 1992. In
addition, the balance of accumulated deferred income taxes at January 1, 1993
was increased $5 million in accordance with Statement of Financial Accounting
Standards No. 109 ("SFAS 109"), and a corresponding regulatory asset was
recorded. Management expects such amounts to be fully recovered through its
rates.
Deferred credits, in the accompanying 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.
21
24
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,
----------------------------------
1993 1992 1991
-------- -------- --------
Operating revenues
Reservation.............................................. $483,471 $346,027 $189,721
Transportation........................................... 59,631 141,789 227,280
Gas and liquid sales..................................... 280,839 237,965 182,797
Other.................................................... 84,987 77,031 135,398
-------- -------- --------
908,928 802,812 735,196
-------- -------- --------
Operating charges
Operation and maintenance................................ 340,818 314,782 322,339
Natural gas and liquids.................................. 249,484 197,759 141,338
Depreciation and amortization............................ 54,051 73,229 61,300
Taxes, other than income taxes........................... 35,330 32,132 25,300
-------- -------- --------
679,683 617,902 550,277
-------- -------- --------
Operating income........................................... 229,245 184,910 184,919
-------- -------- --------
Other (income) and income deductions
Interest and debt expense................................ 75,429 68,075 97,900
Allowance for funds used during construction............. (5,438) (7,096) (3,742)
Interest income from BR.................................. -- (1,602) (38,216)
Other -- net............................................. 8,428 2,244 (11,523)
-------- -------- --------
78,419 61,621 44,419
-------- -------- --------
Income from continuing operations before income taxes...... 150,826 123,289 140,500
Income taxes............................................... 59,153 46,963 51,956
-------- -------- --------
Income from continuing operations.......................... 91,673 76,326 88,544
Income from discontinued operations, net of income taxes... -- -- 54,131
-------- -------- --------
Net income................................................. $ 91,673 $ 76,326 $142,675
-------- -------- --------
-------- -------- --------
Earnings per common share
Continuing operations.................................... $ 2.46 $ 2.12 $ 2.82
Discontinued operations.................................. -- -- 1.72
-------- -------- --------
$ 2.46 $ 2.12 $ 4.54
-------- -------- --------
-------- -------- --------
Average common shares outstanding.......................... 37,212 36,049 31,422
-------- -------- --------
-------- -------- --------
See accompanying Accounting Policies and Notes to Consolidated Financial
Statements.
22
25
EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT PER SHARE AMOUNT)
ASSETS
DECEMBER 31,
------------------------
1993 1992
--------- ----------
Current assets
Cash and temporary cash investments............................... $ -- $ 48,638
Accounts and notes receivable, net................................ 133,437 157,584
Inventories....................................................... 34,665 47,647
Take-or-pay buy-outs, buy-downs and prepayments, net.............. 34,019 49,711
Deferred income tax benefit....................................... 44,141 35,180
Costs recoverable through insurance............................... 23,260 682
Other............................................................. 34,490 24,880
---------- ----------
Total current assets...................................... 304,012 364,322
---------- ----------
Property, plant and equipment, net.................................. 1,765,486 1,450,328
Take-or-pay buy-outs, buy-downs and prepayments, net................ 48,106 104,038
Other regulatory assets............................................. 37,140 --
Other............................................................... 114,919 132,041
---------- ----------
1,965,651 1,686,407
---------- ----------
Total assets.............................................. $2,269,663 $2,050,729
---------- ----------
---------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade.......................................................... $ 125,944 $ 142,035
Other.......................................................... 92,635 94,503
Take-or-pay financing liability................................... 40,125 37,617
Accrual for regulatory issues..................................... 29,867 33,582
Accrued interest.................................................. 30,447 29,799
Accrued taxes, other than income taxes............................ 21,135 24,096
Other............................................................. 16,311 11,569
---------- ----------
Total current liabilities................................. 356,464 373,201
---------- ----------
Long-term debt, less current maturities............................. 795,783 637,074
Deferred income taxes, less current portion......................... 298,080 201,997
Take-or-pay financing liability, less current portion............... 40,383 78,204
Deferred credits.................................................... 25,540 61,829
Other liabilities................................................... 45,865 29,432
---------- ----------
1,205,651 1,008,536
---------- ----------
Commitments and contingent liabilities
Stockholders' equity
Common stock, par value $3 per share; authorized, 100,000 shares;
issued, 37,350 shares and 37,304 shares (including shares held
in treasury)................................................... 112,051 111,913
Additional paid-in capital........................................ 455,496 454,480
Retained earnings................................................. 157,506 108,025
Less: Treasury stock (at cost) 486 shares and 185 shares.......... 17,505 5,426
---------- ----------
Total stockholders' equity................................ 707,548 668,992
---------- ----------
Total liabilities and stockholders' equity................ $2,269,663 $2,050,729
---------- ----------
---------- ----------
See accompanying Accounting Policies and Notes to Consolidated Financial
Statements.
23
26
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-------------------------------------
1993 1992 1991
--------- --------- ---------
Cash flows from continuing operating activities
Income from continuing operations..................... $ 91,673 $ 76,326 $ 88,544
Adjustments to reconcile income to net cash provided
by continuing operating activities
Depreciation and amortization...................... 54,051 73,229 61,300
Deferred income taxes.............................. 8,550 (54,468) (96,944)
Net take-or-pay recoveries......................... 60,799 213,748 295,879
Recoverable excess gas costs....................... -- -- 194,111
Other working capital changes
Accounts and notes receivable.................... 34,877 7,215 52,372
Inventories...................................... 11,530 3,700 (3,168)
Other current assets............................. 10,209 (16,707) 1,341
Costs recoverable through insurance.............. (22,578) 1,096 (1,422)
Accounts payable................................. (38,644) 17,680 (22,448)
Accrual for regulatory issues.................... 1,210 15,267 (279,092)
Accrued taxes, other than income taxes........... 5,291 4,566 (796)
Other current liabilities........................ 3,609 (24,693) 20,227
Other.............................................. 14,975 16,579 (60,787)
--------- --------- ---------
Net cash provided by continuing operating
activities.................................. 235,552 333,538 249,117
--------- --------- ---------
Cash flows from continuing investing activities
Capital expenditures.................................. (164,333) (245,799) (308,103)
Mojave acquisition.................................... (35,695) -- --
Proceeds from property dispositions................... 1,674 4,812 10,656
Other................................................. (7,553) (2,111) (27,026)
--------- --------- ---------
Net cash used in continuing investing
activities.................................. (205,907) (243,098) (324,473)
--------- --------- ---------
Cash flows from continuing financing activities
Proceeds from sale of common stock, net............... 947 95,557 --
Proceeds from reissuance of treasury stock............ 3,869 10,754 --
Proceeds from long-term financings.................... -- 575,000 --
Net commercial paper borrowings....................... 1,300 -- (300,000)
Long-term debt retirements............................ (2,871) (186,416) (299,286)
Proceeds from sale of volumetric take-or-pay
receivables........................................ -- 210,621 --
Repayment of volumetric take-or-pay receivable........ (35,313) (94,800) --
Proceeds from (repayment of) payable to BR............ -- (624,804) 624,804
Dividends paid prior to initial public offering....... -- (274,000) (230,000)
Dividends paid subsequent to initial public
offering........................................... (39,935) (18,651) --
Acquisition of treasury stock......................... (18,001) (23,988) --
Other................................................. 11,721 (35,846) (20,199)
--------- --------- ---------
Net cash used in continuing financing
activities.................................. (78,283) (366,573) (224,681)
--------- --------- ---------
Decrease in cash and temporary cash investments from
continuing operations................................. (48,638) (276,133) (300,037)
Cash and temporary cash investments
Beginning of period........................... 48,638 324,771 624,808
--------- --------- ---------
End of period................................. $ -- $ 48,638 $ 324,771
--------- --------- ---------
--------- --------- ---------
See accompanying Accounting Policies and Notes to Consolidated Financial
Statements.
24
27
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
COMMON STOCK ADDITIONAL TOTAL
-------------------- PAID-IN RETAINED TREASURY STOCKHOLDERS'
SHARES AMOUNT CAPITAL EARNINGS STOCK EQUITY
--------- -------- --------- --------- -------- ----------
January 1, 1991.................. 31,421,731 $ 94,265 $ 882,260 $ 851,736 $ $1,828,261
Net income..................... 142,675 142,675
Common stock dividends......... (500,000) (656,058) (1,156,058)
---------- ------- --------- --------- -------- ----------
December 31, 1991................ 31,421,731 94,265 382,260 338,353 814,878
Net income..................... 76,326 76,326
Issuance of common stock, net
of related costs............ 5,882,700 17,648 72,220 89,868
Common stock dividends, prior
to the Offering............. (274,000) (274,000)
Common stock dividends,
subsequent to the Offering
($.75 per share)............ (27,817) (27,817)
Acquisition of treasury stock
(812,773 shares)............ (23,988) (23,988)
Reissuance of treasury stock
(628,258 shares)............ (4,837) 18,562 13,725
---------- -------- --------- --------- -------- ----------
December 31, 1992................ 37,304,431 111,913 454,480 108,025 (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 shares)............ (18,001) (18,001)
Reissuance of treasury stock
(207,249 shares)............ (1,288) 5,922 4,634
---------- -------- --------- --------- -------- ----------
December 31, 1993................ 37,350,125 $112,051 $ 455,496 $ 157,506 $(17,505) $ 707,548
---------- -------- --------- --------- -------- ----------
---------- -------- --------- --------- -------- ----------
See accompanying Accounting Policies and Notes to Consolidated Financial
Statements.
25
28
EL PASO NATURAL GAS COMPANY
ACCOUNTING POLICIES
PRESENTATION AND PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company.
All significant intercompany transactions of continuing operations 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 gives the Company 100 percent ownership of MPC.
The operating results of MPC are included in the Company's consolidated results
of operations for 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 accompanying Consolidated Statement of Income.
In September 1991, a dividend of the common stock of EPG's Oil and Gas
Operations Segment was made by EPG to its then parent company, TEPCO. The
accompanying financial statements and notes reflect the discontinuance of the
Oil and Gas Operations Segment.
CASH AND TEMPORARY CASH INVESTMENTS
Short-term investments purchased with an original maturity of three months
or less are considered cash equivalents. Through December 31, 1991, cash and
temporary cash investments also included excess cash advanced by the Company to
its then parent company, BR, under an intercorporate cash management
arrangement.
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 balance of this provision at
December 31, 1993 and 1992 was $3.9 million and $5.1 million, respectively.
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 Statement of Financial Accounting Standards No. 71 ("SFAS 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 have been 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 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) excess amounts of OPEB
costs have been recorded in other regulatory assets to be recovered in future
rates; (vi) 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; (vii) the cost of equity funds used during construction
has been capitalized; (viii) MPC's excess amounts due to straight-line
depreciation rates versus approved depreciation rates have been recorded as
other regulatory assets to be
26
29
EL PASO NATURAL GAS COMPANY
ACCOUNTING POLICIES (CONTINUED)
recovered in future rates and (ix) MPC's deferred taxes on the equity portion of
AFUDC have been recorded in other regulatory assets to be recovered in future
rates.
ACCOUNTING FOR GAS IMBALANCES
EPG currently accounts for gas imbalances due to or due from shippers and
operators. Gas imbalance payables and receivables are maintained at a net legal
entity basis in accordance with Statement of Financial Accounting Standards No.
105. Gas imbalances prior to October 1, 1993 are valued at the 1992 average El
Paso System index price as prescribed in EPG's tariff. Gas imbalances subsequent
to October 1, 1993 are valued at the current quarterly average El Paso System
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
balance of the provision at December 31, 1993 and 1992 was $5.6 million and
$12.1 million, respectively.
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.
PROPERTY, PLANT AND EQUIPMENT
Included in the Company's property, plant and equipment is construction
work in progress of approximately $53 million and $93 million at December 31,
1993 and 1992, 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. Straight-line
depreciation rates for 1993 and 1991 were 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 1993, 1992 and
1991.
MPC's depreciation rates reflect a levelized cost-of-service approach and a
25-year depreciation 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 Accounting Policies.)
Additional acquisition cost assigned to utility plant represents EPG's
portion of the excess of allocated acquisition cost over historical cost that
resulted from the 1983 acquisition of EPG's former parent, TEPCO, by BR's former
parent, BNI. These costs are being amortized on a straight-line basis over the
estimated remaining life of the properties.
27
30
EL PASO NATURAL GAS COMPANY
ACCOUNTING POLICIES (CONTINUED)
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.
INVENTORIES
Inventories are carried on either the first-in first-out or average cost
method at the lower of cost or market. Gas in storage inventories at December
31, 1992 were carried at cost determined on a last-in first-out basis. During
1993, EPG sold its gas in storage inventory in accordance with the settlement
agreement with EPG's customers and FERC staff. Inventories at December 31, 1993
and 1992 consist of the following components:
1993 1992
------- -------
(IN THOUSANDS)
Materials and supplies........... $34,664 $33,122
Gas in storage................... -- 14,522
Other............................ 1 3
------- -------
$34,665 $47,647
------- -------
------- -------
RECOVERABLE EXCESS GAS COSTS
The cash flow statement for 1991 shows recoveries of recoverable excess gas
costs. These costs represent the cumulative excess of actual purchased gas costs
over the average of these costs included in EPG's gas sales rates. FERC's August
14, 1991 order provided for a portion of the September 1, 1991 recoverable
excess gas costs balance to be offset against refund obligations. The remainder
of the costs, $25 million, was recorded against previously established accruals.
Effective with the implementation of the 1991 order, EPG no longer records
recoverable excess gas costs.
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.
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
number of shares of common stock outstanding for 1993, 1992 and 1991 were
37,212,192, 36,049,135 and 31,421,731, respectively. Stock options are the only
common stock equivalents and are currently not dilutive.
28
31
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. RATES AND REGULATORY MATTERS
General Rate Filings and Other
On July 1, 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. On
July 31, 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 were 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 on December 31, 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 31, 1992 compliance filing. As required by FERC order,
EPG filed revised rates on September 14, 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 provides for the accelerated recovery of a
substantial portion of EPG's investment in its underground storage facility.
This is being recovered by a demand charge mechanism over the period from
October 1, 1993 through December 31, 1996. The amount to be recovered was
approximately $56.7 million plus interest accruing beginning February 1, 1993 at
the FERC allowed rate, which approximates the prime rate. The amount recovered
through December 31, 1993 was $19 million. The outstanding balance at December
31, 1993 was $37 million, of which $12 million is included in other current
assets and $25 million is included in other assets in the accompanying
Consolidated Balance Sheet. The settlement agreement also established new
depreciation rates for certain of EPG's facilities effective January 1, 1992.
On August 14, 1991, FERC approved an order resolving all of the issues in
EPG's December 1987 rate case filing and certain other pending matters which
became effective on September 1, 1991. The order provided for: (i) the
establishment of revised rate levels for the period July 1, 1988 through the
effective date of EPG's next rate change, which occurred on January 1, 1992; and
(ii) payment of certain refunds for the period July 1, 1988 through August 31,
1991. EPG disbursed to its customers $252 million in October 1991 in accordance
with the order. The total refund obligation at September 1, 1991 was $369
million before certain offsets, including an unbilled portion of the $169
million of recoverable excess gas costs. The net refund obligation and the
remaining balance of the recoverable excess gas costs, $25 million, were
recorded against previously established accruals.
Pursuant to the Restructuring Rules, MPC filed its restructuring plan on
November 3, 1992. On March 2, 1993, FERC issued an order essentially approving
MPC's compliance filing, subject to changes, which were made in an amended
restructuring plan on March 29, 1993. Several of MPC's customers filed protests
and requests for rehearing of the March 2, 1993 FERC order. The rehearing
requests were denied, and FERC approved the amended restructuring plan on July
9, 1993, with an effective date of August 1, 1993. On October 15, 1993, FERC
issued an order which denied requests for rehearing of the July 9, 1993 order.
Several of MPC's customers have filed petitions for review of the March 2, 1993,
July 9, 1993, and October 15, 1993 orders with the United States Court of
Appeals which are currently pending.
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, and this increases aggregate transportation charges for
low load factor shippers. Such
29
32
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. MPC believes the United States Court of
Appeals will uphold SFV rates as applied to MPC.
Take-or-Pay Settlements
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. In
certain cases, EPG resolved claims by making recoupable prepayments. At December
31, 1993 and December 31, 1992, the recoupable prepayment balances were $9
million and $19 million, respectively. 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.
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 the direct bill
portion of the take-or-pay buy-out and buy-down costs extends through May 1994.
The collection period for the volumetric surcharge portion of such costs extends
through March 1996. Through December 31, 1993, EPG had recovered approximately
$1.0 billion; of that recovery, $361 million was collected by direct bill and
$682 million by volumetric surcharge. EPG has established a reserve for that
portion of the volumetric surcharge receivables balance which is unlikely to be
collected over the period through March 1996, based on current throughput
projections. The balance of this reserve was $19 million at December 31, 1993.
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. The remaining issue
involves the claim by several customers that EPG has 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. On March 8,
1993, an initial decision from the presiding ALJ was rendered which, if adopted
without changes by FERC, would require EPG to refund to or forgo collection from
its customers of up to $30 million, plus interest. Exceptions to this initial
decision were filed with FERC by both parties on April 7, 1993. On April 27,
1993, briefs opposing exceptions were filed by the same parties as well as by
FERC staff. EPG has established adequate reserves for this issue and does not
believe that the ultimate outcome will have a materially adverse effect on the
Company's financial condition or results of operations.
On January 14, 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, 1993 and December 31, 1992, $87 million and $125 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.
2. 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
30
33
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
the investment. The acquisition, which was funded by internally generated cash
flow, gives 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 following MPC balances are included in the December 31, 1993
Consolidated Balance Sheet of the Company:
(IN THOUSANDS)
Cash and other current assets.......................................... $ 19,570
Property, plant and equipment, net..................................... 224,075
Regulatory assets and other............................................ 34,420
--------------
Total assets...................................................... $278,065
--------------
--------------
Current liabilities.................................................... $ 10,879
Long-term debt, less current portion................................... 158,584
Deferred income taxes and deferred credits............................. 20,427
Equity................................................................. 88,175
--------------
Total liabilities and equity...................................... $278,065
--------------
--------------
The operating results of MPC are included in the Company's consolidated
results of operations for 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 accompanying 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
31
34
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT
Long-term debt outstanding is as follows:
DECEMBER 31,
---------------------
1993 1992
-------- --------
(IN THOUSANDS)
Long-term debt
EPG
6.90% Notes, due January 1997..................... $100,000 $100,000
9.45% Notes, due September 1999................... 47,442 47,437
7 3/4% Notes, due January 2002.................... 214,570 214,516
8 5/8% Debentures, due March 2012................. 16,791 16,774
8 5/8% Debentures, due January 2022............... 258,362 258,304
Other............................................. 43 51
MPC
Project financing loan, due March 2007, average
interest rate 7.6%.............................. 164,759 --
-------- --------
801,967 637,082
Less current maturities........................... 6,184 8
-------- --------
Total long-term debt............................ $795,783 $637,074
-------- --------
-------- --------
The following are aggregate maturities of long-term debt for the next five
years and in total thereafter:
(IN THOUSANDS)
1994............................................................. $ 6,184
1995............................................................. 6,824
1996............................................................. 7,517
1997............................................................. 108,279
1998............................................................. 18,070
Thereafter....................................................... 655,093
--------------
Total long-term debt, including current
maturities.................................... $801,967
--------------
--------------
On December 5, 1991, EPG commenced a tender offer with respect to the 9.45%
Notes and 8 5/8% Debentures. Pursuant to the tender offer, in December 1991, EPG
purchased $207 million aggregate principal amount of the 9.45% Notes for $228
million and $93 million aggregate principal amount of 8 5/8% Debentures for $93
million. In January 1992, EPG purchased an additional $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, on
December 19, 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. EPG also maintained Loan Agreements with BR under which it could
borrow up to $500 million. As of December 31, 1991, $300 million was outstanding
under the Commitment Agreement and $325 million was outstanding under the Loan
Agreements. In January 1992, EPG borrowed an additional $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 December 1991 and
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
32
35
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
EPG repaid its outstanding commercial paper in December 1991 with
borrowings under the Commitment Agreement with BR. The proceeds from the sale of
the take-or-pay receivables were used to repay the borrowings under the
Commitment Agreement with BR.
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 facility
expires in March 1996. As of December 31, 1993, there were no borrowings
outstanding under this facility. Approximately $1 million of commercial paper
was outstanding as of December 31, 1993.
EPG must comply with various restrictive covenants contained in its debt
agreements which include, among others, maintaining consolidated tangible net
worth (as defined in the agreements) of at least $400 million. Also, EPG's
consolidated debt and guaranties to capitalization ratio cannot exceed 70
percent. 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, 1993, EPG's
consolidated tangible net worth exceeded the minimum restrictive covenant
requirement by $298 million, its consolidated debt and guaranties to
capitalization ratio was 47 percent and there were no subsidiary debt
obligations of those subsidiaries limited by the debt agreements.
On September 30, 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 $165 million and $170 million at December 31, 1993 and
1992, respectively. The loan is repayable in semiannual installments over the
period to March 31, 2007. Interest on the loan is payable quarterly.
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
$50.5 million of loan principal had interest rates ranging from 3.9 percent to
4.3 percent during 1993. With the impact of the interest rate swap agreements,
the overall effective rate on the loan was approximately 7.6 percent during 1993
and 1992.
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.
33
36
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. ENVIRONMENTAL
Accruals for environmental compliance costs are established when
environmental assessments and/or remediation are probable, and when costs can be
reasonably estimated. As of December 31, 1993, EPG had a reserve of $38 million
for the following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of PCB contamination at its
facilities. The majority of the required PCB remediation has been
completed. Future PCB remediation costs are estimated to range between $8
million and $11 million over the next five years.
2 -- EPG executed an Administrative Order on Consent with EPA on June 25,
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
$20 million over a 30 year period.
3 -- On November 2, 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 $10 million and
$20 million over a 30 year period.
4 -- EPG is involved in other environmental assessment and remediation
activities which include two additional CERCLA sites (Fountain Inn, South
Carolina and Odessa, Texas) and one state Superfund site (Etowah,
Tennessee). The amount reserved as of December 31, 1993 will cover these
and other small environmental assessments and other remediation projects.
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. The Company anticipates
capitalizing the equipment costs associated with complying with CAAA and
estimates that approximately $5 million to $27 million will be spent during
the 1995 through 1997 time frame. 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 dry flow
devices. The remaining remediation costs are estimated to be between $8
million and $12 million, most of which will be incurred over the next two
years. EPG will close and retire about 5,400 earthen siphon/dehydration
pits in the San Juan Basin as recently required by certain environmental
regulations. EPG estimates costs of approximately $17 million to $25
million to retire these pits over the next two years. The mercury
remediation and pit closure costs, which are associated with the retirement
of equipment, will be recorded as adjustments to accumulated depreciation,
as required by regulatory accounting.
On December 21, 1993, EPA issued EPG a Notice of Liability for the CSMRI
site in Golden, Colorado. Because EPA has not yet determined the volume of
hazardous substances sent to the site by all parties, there is no way to
estimate EPG's potential share of remediation costs. However, based on the
volumes EPA presently lists as contributed by EPG and other potentially
responsible parties, it appears that EPG is a minor contributor.
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, contingency amounts will be adjusted
accordingly.
34
37
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. CORPORATE REORGANIZATION
During 1992 and 1991, EPG completed several transactions in preparation for
its separation from BR. Among these transactions was the transfer of the net
assets of the Company's Oil and Gas Operations Segment to TEPCO, which is
reported as discontinued operations.
In May 1991, EPG declared and paid a dividend of $175 million to TEPCO.
Effective August 31, 1991, EPG contributed its oil and gas cost-of-service
production properties to EPPC. 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, $500 million of which was a return of capital and,
accordingly, reduced additional paid-in-capital. TEPCO declared a dividend of
100 percent of the common stock of EPG to BR, TEPCO's parent company, effective
September 2, 1991.
In December 1991, EPG declared and paid a dividend to BR of $55 million. 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. On June 30, 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.
Discontinued Operations
The following results of operations of the Oil and Gas Operations Segment
are presented as income from discontinued operations, net of income taxes, in
the accompanying Consolidated Statement of Income:
YEAR ENDED
DECEMBER 31, 1991
-----------------
(IN THOUSANDS)
Operating revenues........................................... $ 303,456
Operating charges and other.................................. 249,972
Income taxes (benefit)....................................... (647)
-----------------
Income from discontinued operations, net of income taxes..... $ 54,131
-----------------
-----------------
The operations of EPG's cost-of-service production properties that were
contributed to EPPC on August 31, 1991, were reflected in the Company's Natural
Gas Operations Segment and are therefore not included in income from
discontinued operations. The net book value of the production properties was
$197 million on August 31, 1991. The earnings related to the cost-of-service
production properties are included in income from continuing operations and are
not material.
6. 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 Directors
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
35
38
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
On January 15, 1992, the Board of Directors of EPG 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 will become
exercisable on January 15, 1995. On January 12, 1993, EPG's Board of Directors
granted stock options exercisable for 554,000 shares of common stock at $30.81
per share. The stock options vested on January 12, 1994. On March 18, 1993,
3,000 stock options were granted at $36.19 per share and became exercisable
immediately. On May 1, 1993, 3,000 stock options were granted at $38.19 per
share and became exercisable immediately. On July 22, 1993, 15,000 stock options
were granted at $37.25 per share and vested on January 22, 1994. On January 14,
1994, EPG's Board of Directors granted stock options exercisable for 655,100
shares of common stock at $36.875 per share which will vest on January 14, 1995.
In addition, stock options were granted for 3,000 shares of common stock at
$36.875 per share, which became exercisable immediately.
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.
Activity in EPG's stock option plans for 1992 and 1993 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
--------- -------
--------- -------
At December 31, 1993, 321,286 stock options and 70,154 SARs were
exercisable at prices ranging from $13.51 to $38.19 per share. At December 31,
1992, 568,422 stock options and 105,203 SARs were exercisable at prices ranging
from $13.51 to $25.69 per share.
SARs shown as cancelled in the table above were cancelled when the
underlying stock options were exercised. Stock options shown as cancelled in the
table above may be a result of the tandem SAR being exercised.
The maximum number of shares for which stock options may be granted under
EPG's stock option plans are approximately seven 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 EPG's Board of Directors.
On October 22, 1992, EPG's Board of Directors authorized the repurchase of
up to two 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
36
39
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
for an aggregate value of $24 million and in the fourth quarter 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 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.
A total of 2,300 and 132,700 restricted shares of EPG's common stock were
granted to certain employees for 1993 and 1992 respectively. The market value of
such shares awarded was approximately $0.1 million and $2.8 million in 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.
For the year ended December 31, 1993, primary earnings per share of common
stock was $2.46 per share. If stock options exercised in 1993 had been exercised
on January 1, 1993, earnings per share would have remained at the same level.
For the year ended December 31, 1992, primary earnings per share of common stock
was $2.12 per share. If stock options exercised in December 1992 had been
exercised on January 1, 1992, earnings per share of common stock for 1992 would
have been $2.08.
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following:
DECEMBER 31,
-----------------------
1993 1992
--------- ---------
(IN THOUSANDS)
Property, plant and equipment, at cost.............. $2,873,301 $2,552,075
Less accumulated depreciation....................... 1,212,233 1,211,577
--------- ---------
1,661,068 1,340,498
Additional acquisition cost assigned to utility
plant, net of accumulated amortization............ 104,418 109,830
--------- ---------
Total property, plant and equipment,
net..................................... $1,765,486 $1,450,328
--------- ---------
--------- ---------
The December 31, 1993 balance of property, plant and equipment, net
includes $224 million for MPC.
37
40
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. INCOME TAXES
The following table reflects the components of income tax expense.
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Current
Federal............................................ $ 42,112 $ 84,315 $127,772
State.............................................. 8,491 17,116 18,264
Investment tax credit.............................. -- -- 2,864
-------- -------- --------
50,603 101,431 148,900
-------- -------- --------
Deferred
Federal............................................ 7,506 (42,590) (82,080)
Change in enacted tax rate......................... 503 -- --
State.............................................. 541 (11,878) (11,967)
Investment tax credit.............................. -- -- (2,897)
-------- -------- --------
8,550 (54,468) (96,944)
-------- -------- --------
Total tax expense.......................... $ 59,153 $ 46,963 $ 51,956
-------- -------- --------
-------- -------- --------
Investment tax credit as shown above is net of estimated recapture, if any,
provided for during each year.
The following table reflects the components of deferred tax expense
(benefit):
YEAR ENDED DECEMBER 31,
---------------------------------
1993 1992 1991
-------- -------- ---------
(IN THOUSANDS)
Gas cost settlements and recovery................... $ 17,633 $(51,602) $(195,765)
Financial accruals and reserves..................... (13,001) (8,481) 102,791
Depreciation and amortization....................... 7,355 10,567 (1,131)
Alternative minimum tax............................. 2,103 (2,103) --
Change in enacted tax rate.......................... 503 -- --
Other............................................... (6,043) (2,849) (2,839)
-------- -------- ---------
Total deferred tax expense (benefit)...... $ 8,550 $(54,468) $ (96,944)
-------- -------- ---------
-------- -------- ---------
The following table reflects the components of the net deferred tax
liability:
YEAR ENDED DECEMBER 31,
-------------------------
1993 1992
-------- --------
(IN THOUSANDS)
Deferred tax liabilities:
Property, plant and equipment............................ $253,639 $227,734
Regulatory and other assets.............................. 71,896 14,085
-------- --------
Total deferred tax liability..................... 325,535 241,819
-------- --------
Deferred tax assets:
Take-or-pay buy-outs, buy-downs and prepayments.......... 2,186 22,056
Accrual for regulatory issues............................ 22,119 11,545
Other liabilities........................................ 40,842 32,129
Other.................................................... 6,449 9,272
-------- --------
Total deferred tax asset......................... 71,596 75,002
-------- --------
Net deferred tax liability................................. $253,939 $166,817
-------- --------
-------- --------
38
41
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Tax expense of the Company differs from the amount computed by applying the
statutory federal income tax rate to income from continuing operations before
income taxes. The reasons for this difference are as follows:
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1992 1991
------- ------- -------
(IN THOUSANDS)
Tax expense at the statutory federal rate of 35% for
1993 and 34% for 1992 and 1991...................... $52,789 $41,918 $47,770
Increase (decrease)
State income tax, net of federal income tax
benefit.......................................... 5,871 3,458 4,156
Change in enacted tax rate.......................... 503 -- --
Investment tax credit............................... -- -- (33)
Non-taxable dividends received from affiliates...... -- -- (267)
Other............................................... (10) 1,587 330
------- ------- -------
Income tax expense.................................... $59,153 $46,963 $51,956
------- ------- -------
------- ------- -------
Effective tax rate.................................... 39% 38% 37%
The Revenue Reconciliation Act of 1993, enacted in August 1993, changed the
corporate income tax rate from 34 to 35 percent effective January 1, 1993. As a
result, the Company's current year provision for income tax expense was adjusted
in the third quarter of 1993 by approximately $1 million, of which $0.5 million
is related to the balance of deferred income taxes at December 31, 1992. In
addition, the balance of accumulated deferred income taxes at January 1, 1993
was increased $5 million in accordance with SFAS 109, and a corresponding
regulatory asset was recorded. Management expects such amounts to be fully
recovered through its rates.
Deferred credits, in the accompanying 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.
9. PENSION PLANS
The Company previously 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 January 1992, the Company established its own pension plans with
provisions similar to those of the BR plans. Upon separation from BR, the
Company's qualified pension plan received assets equal to the accumulated
benefit obligation relating to the Company's employees.
39
42
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table sets forth the qualified plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheet at December 31,
1993 and December 31, 1992:
YEAR ENDED DECEMBER 31,
-----------------------
1993 1992
-------- --------
(IN THOUSANDS)
Actuarial present value of benefit obligations:
Vested benefits............................................. $471,600 $407,478
Nonvested benefits.......................................... 896 541
-------- --------
Accumulated benefit obligation................................ $472,496 $408,019
-------- --------
-------- --------
Projected benefit obligation for service rendered to date..... $546,180 $469,850
Plan assets at fair value, primarily listed stocks and U.S.
bonds....................................................... 434,505 415,443
-------- --------
Projected benefit obligation in excess of plan assets......... $111,675 $ 54,407
-------- --------
-------- --------
Unrecognized net loss......................................... $ 64,194 $ 3,855
Unrecognized net transition obligation........................ 22,008 24,712
Recognized pension liability.................................. 37,991 25,840
Minimum liability adjustment included in recognized pension
liability................................................... (12,518) --
-------- --------
$111,675 $ 54,407
-------- --------
-------- --------
The following table reflects the components of net periodic pension cost:
YEAR ENDED DECEMBER 31,
-----------------------
1993 1992
-------- --------
(IN THOUSANDS)
Pension cost allocated from BR plan........................... $ -- $ 4,922
Service cost -- benefits earned during the period............. 7,568 3,311
Interest cost on projected benefit obligation................. 38,786 19,364
Actual return on plan assets.................................. (43,850) (27,641)
Net amortization and deferral................................. 10,724 11,328
-------- --------
Net periodic pension cost..................................... $ 13,228 $ 11,284
-------- --------
-------- --------
The 1993 weighted average discount rate and rate of increase in future
compensation levels used in determining the actuarial present value of the
projected benefit obligation were 7.5 percent and 5.0 percent, respectively. The
1993 weighted average expected long-term rate of return on plan assets was 9.0
percent. The 1992 weighted average discount rate and rate of increase in future
compensation levels used in determining the actuarial present value of the
projected benefit obligation were 8.5 percent and 5.0 percent, respectively. The
1992 weighted average expected long-term rate of return on plan assets was 9.0
percent. 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.
10. POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS
The Financial Accounting Standards Board issued SFAS 106 requiring
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 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.
40
43
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
EPG began recovering through its rates the OPEB costs included in the
settlement agreement. To the extent actual OPEB costs exceed the amounts
reflected in the settlement agreement, a regulatory asset has been recorded.
Management expects such amounts to be fully recovered through its rates.
The following table sets forth the plan's funded status and amounts
recognized in the Company's Consolidated Balance Sheet at December 31, 1993:
(IN THOUSANDS)
--------------
Accumulated postretirement benefit obligation.......................... $124,914
Plan assets at fair value, primarily U.S. stocks and U.S. bonds........ 8,751
--------------
Accumulated postretirement benefit obligation in excess of plan
assets............................................................... $116,163
--------------
--------------
Unrecognized net loss.................................................. $ 9,285
Unrecognized transition obligation..................................... 105,796
Accrued postretirement costs included in other liabilities............. 1,082
--------------
$116,163
--------------
--------------
The following table reflects the components of net periodic postretirement
benefit cost for the twelve months ended December 31, 1993:
(IN THOUSANDS)
--------------
Interest cost on accumulated postretirement benefit obligation......... $ 9,377
Actual return on plan assets........................................... (254)
Net amortization and deferral.......................................... 9,062
--------------
Net periodic postretirement benefit cost............................... $ 18,185
--------------
--------------
A 13.5 percent annual rate of increase in the per capita costs of covered
health care benefits was assumed for 1994, gradually decreasing to 6 percent by
the year 2002. 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, 1993 by approximately $13.9 million and
increase the interest cost components of net periodic postretirement benefit
cost for 1993 by approximately $1 million. A discount rate of 7.5 percent was
used to determine the accumulated postretirement benefit obligation.
The Financial Accounting Standards Board issued SFAS 112 which requires
companies to account for benefits to former or inactive employees after
employment but before retirement (referred to in SFAS 112 as "postemployment
benefits"). SFAS 112 is effective for the fiscal years beginning after December
15, 1993. 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. The
cumulative effect at January 1, 1994 of adopting SFAS 112 is estimated to be
approximately $8 million. Management expects to fully recover its postemployment
benefits costs through rates.
11. COMMITMENTS AND CONTINGENT LIABILITIES
See Note 1 and 4 of Notes to Consolidated Financial Statements, Item 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.
41
44
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Minimum annual rental commitments at December 31, 1993, are as follows:
OPERATING LEASES
YEAR ENDING DECEMBER 31, ----------------
------------------------------------------------------- (IN THOUSANDS)
1994................................................... $ 8,837
1995................................................... 9,233
1996................................................... 9,647
1997................................................... 10,082
1998................................................... 10,537
Thereafter............................................. 103,424
----------------
Total........................................ $151,760
----------------
----------------
Rental expense for operating leases was $8 million in 1993 and 1992, and $7
million in 1991.
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 on May 31, 2007, and grants EPG two ten year options to extend
the term of the lease.
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.
12. 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,
----------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Southern California Gas Company.................... $238,885 $249,277 $231,837
Pacific Gas & Electric Company..................... 168,246 137,968 113,729
Southwest Gas Corporation.......................... 95,188 79,784 89,999
13. SUPPLEMENTAL CASH FLOW INFORMATION
The following provides additional information concerning supplemental
disclosures of cash flow activities:
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Interest paid...................................... $ 66,773 $ 47,047 $128,646
Income taxes paid.................................. 38,993 140,766 125,743
14. RELATED PARTY TRANSACTIONS
In 1991 and 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.
On April 8, 1992, EPG's Board of Directors 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.
42
45
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Revenues associated with the transportation of gas for Meridian by EPG were
$15 million for the six months ended June 30, 1992, and $47 million for the year
ended December 31, 1991.
Operating revenues include $26 million related to transactions with the
discontinued Oil and Gas Operations Segment in 1991. Operating charges related
to transactions with the discontinued segment were less than $1 million in 1991.
In May 1991, EPG declared and paid a dividend to TEPCO of $175 million and in
December 1991 declared and paid a $55 million dividend to BR.
Certain BR corporate overhead expenses were allocated to EPG. The allocated
amounts were not material and management believes the allocation methodology was
appropriate.
15. FINANCIAL INSTRUMENTS
Fair Value
The following disclosure of the estimated fair value of financial
instruments was made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107 ("SFAS 107"). The estimated fair value
amounts have been determined by the Company using available market information
and valuation methodologies.
As of December 31, 1993, the carrying amounts of the various financial
instruments employed by the Company, including cash, cash equivalents,
short-term borrowings, and trade receivables and payables are representative of
fair value because of the short maturity of these instruments. The carrying
amounts and estimated fair values of the Company's other financial instruments
at December 31, 1993 are as follows:
CARRYING FAIR
AMOUNT VALUE
-------- --------
(IN MILLIONS)
EPG long-term debt.................................... $637.2 $ 696.2
MPC project financing................................. 50.5 50.5
Interest rate swap agreements......................... 114.3 133.6
-------- --------
Total....................................... $802.0 $ 880.3
-------- --------
-------- --------
The fair value of the Company's long-term debt has been estimated based on
quoted market prices for the same or similar issues. The fair value of interest
rate swap agreements is the amount at which they could be settled, based on
estimates obtained from dealers.
Off-Balance Sheet Risk
During 1993, EPG and EPGM entered into certain price swap agreements to, in
effect, hedge the market risk caused by fluctuations in the price of natural
gas. The agreements call for EPG and EPGM to make payments to or receive
payments from the other parties based upon the differential between a fixed and
a variable price for natural gas as specified by the contract. The current price
swap agreements run for periods of up to five years and had a notional contract
amount of approximately $30 million at December 31, 1993. While EPG and EPGM's
notional contract amounts are used to express the magnitude of price swap
agreements, the amounts potentially subject to credit risk, in the event of
non-performance by the other parties, are substantially smaller. EPG and EPGM do
not anticipate non-performance by the other parties.
MPC has entered into interest rate swap agreements which effectively
convert $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.
43
46
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, 1993 and 1992, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1993, 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
El Paso, Texas
January 21, 1994
44
47
EL PASO NATURAL GAS COMPANY
CONSOLIDATED QUARTERLY INFORMATION
YEARS ENDED DECEMBER 31, 1993 AND 1992
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
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
1992
Operating revenues............................ $222,775 $217,203 $188,424 $174,410
Operating income.............................. 44,426 39,661 44,047 56,776
Net income.................................... 16,600 14,009 17,295 28,422
Earnings per common share..................... 0.45 0.38 0.46 0.87
45
48
SCHEDULE IV
EL PASO NATURAL GAS COMPANY
INDEBTEDNESS OF AND TO RELATED PARTIES -- NOT CURRENT
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN F COLUMN G COLUMN H COLUMN I
- ------------------------------------------------ ---------- -------- ---------- ---------
BALANCE AT BALANCE
BEGINNING AT END
NAME OF PERIOD ADDITIONS DEDUCTIONS OF PERIOD
- ------------------------------------------------ ---------- -------- ---------- ---------
Year ended December 31, 1993
-- -- -- --
---------- -------- ---------- ---------
---------- -------- ---------- ---------
Year ended December 31, 1992
Long-term payable to BR......................... $ 374,011 -- $374,011 --
---------- -------- ---------- ---------
---------- -------- ---------- ---------
Year ended December 31, 1991
Long-term payable to BR......................... -- $374,011 -- $ 374,011
---------- -------- ---------- ---------
---------- -------- ---------- ---------
46
49
SCHEDULE V
EL PASO NATURAL GAS COMPANY
PROPERTY, PLANT AND EQUIPMENT
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
------------- ---------- --------- ----------- -------- ----------
BALANCE AT BALANCE
BEGINNING ADDITIONS AT END
CLASSIFICATION OF PERIOD AT COST RETIREMENTS OTHER OF PERIOD
- --------------------------------- ---------- --------- ----------- -------- ----------
Year ended December 31, 1993
Historical cost.................. $2,552,075 $ 164,333(a) $ 48,733 $205,626(b) $2,873,301
Additional acquisition cost
assigned to utility plant...... 150,978 -- -- -- 150,978
---------- --------- ----------- -------- ----------
$2,703,053 $ 164,333 $ 48,733 $205,626 $3,024,279
---------- --------- ----------- -------- ----------
---------- --------- ----------- -------- ----------
Year ended December 31, 1992
Historical cost.................. $2,391,593 $ 245,799(c) $ 85,336 $ 19 $2,552,075
Additional acquisition cost
assigned to utility plant...... 150,978 -- -- -- 150,978
---------- --------- ----------- -------- ----------
$2,542,571 $ 245,799 $ 85,336 $ 19 $2,703,053
---------- --------- ----------- -------- ----------
---------- --------- ----------- -------- ----------
Year ended December 31, 1991
Historical cost.................. $2,674,154 $ 308,103(c) $ 619,258 $ 28,594(d) $2,391,593
Additional acquisition cost
assigned to utility plant...... 150,978 -- -- -- 150,978
---------- --------- ----------- -------- ----------
$2,825,132 $ 308,103 $ 619,258 $ 28,594 $2,542,571
---------- --------- ----------- -------- ----------
---------- --------- ----------- -------- ----------
For depreciation rates and methods, see Accounting Policies.
(a) Primarily from system enhancement and maintenance projects.
(b) Primarily the consolidation of MPC's $242 million of property, plant and
equipment and reclassification of $46 million of underground storage
facility.
(c) Primarily from major system expansion and enhancement projects.
(d) Primarily reclassification of $31 million of gas in storage inventory
consistent with the August 14, 1991 FERC order.
47
50
SCHEDULE VI
EL PASO NATURAL GAS COMPANY
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
------------- ---------- -------- ----------- -------- ----------
ADDITIONS
BALANCE AT CHARGED BALANCE
BEGINNING TO AT END
CLASSIFICATION OF PERIOD EXPENSES RETIREMENTS OTHER OF PERIOD
- ----------------------------------------- ---------- -------- ----------- -------- ----------
Year ended December 31, 1993
Historical cost.......................... $1,211,577 $48,639 $ 51,182 $ 3,199 $1,212,233
Additional acquisition cost assigned to
utility plant.......................... 41,148 5,412 -- -- 46,560
---------- -------- ----------- -------- ----------
$1,252,725 $54,051 $ 51,182 $ 3,199 $1,258,793
---------- -------- ----------- -------- ----------
---------- -------- ----------- -------- ----------
Year ended December 31, 1992
Historical cost.......................... $1,223,039 $67,817 $ 90,874 $11,595 $1,211,577
Additional acquisition cost assigned to
utility plant.......................... 35,736 5,412 -- -- 41,148
---------- -------- ----------- -------- ----------
$1,258,775 $73,229 $ 90,874 $11,595 $1,252,725
---------- -------- ----------- -------- ----------
---------- -------- ----------- -------- ----------
Year ended December 31, 1991
Historical cost.......................... $1,482,678 $57,916 $ 321,363 $ 3,808 $1,223,039
Additional acquisition cost assigned to
utility plant.......................... 32,352 3,384 -- -- 35,736
---------- -------- ----------- -------- ----------
$1,515,030 $61,300 $ 321,363 $ 3,808 $1,258,775
---------- -------- ----------- -------- ----------
---------- -------- ----------- -------- ----------
48
51
SCHEDULE VIII
EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(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
- -------------------------------------------- ---------- --------- --------- ---------- ----------
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
1991(a)
Allowance for bad debts................... $ 9,851 $ 318 $ 176 $2,116(b) $ 8,229
Allowance for gas imbalances.............. -- 2,082 -- -- 2,082
- ---------------
(a) Presentation of prior years has been changed to conform to current year
presentation.
(b) Primarily accounts charged off.
(c) Primarily accounts recovered.
49
52
SCHEDULE X
EL PASO NATURAL GAS COMPANY
SUPPLEMENTARY INCOME STATEMENT INFORMATION
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B
----------- -------------------------------
CHARGED TO COSTS AND EXPENSES
-------------------------------
ITEM 1993 1992 1991
------- ------- -------
Maintenance and repairs....................................... $43,154 $39,959 $43,000
Taxes, other than payroll and income taxes:
Ad valorem taxes............................................ 22,463 18,718 10,946
- ------------
Note -- Items omitted are either less than 1 percent of consolidated revenues or
are disclosed elsewhere in the consolidated financial statements or
notes thereto.
50
53
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 1994 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.
51
54
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...................................... 22
Consolidated balance sheet............................................ 23
Consolidated statement of cash flows.................................. 24
Consolidated statement of stockholders' equity........................ 25
Accounting policies and notes to consolidated financial statements.... 26
Report of independent accountants..................................... 44
2. Financial statement schedules and supplementary information required to
be submitted.
Consolidated quarterly information.................................... 45
Schedule IV - Indebtedness of and to related parties -- not current... 46
Schedule V - Property, plant and equipment............................ 47
Schedule VI - Accumulated depreciation, depletion and amortization of
property, plant and equipment....................................... 48
Schedule VIII - Valuation and qualifying accounts..................... 49
Schedule X - Supplementary income statement information............... 50
Schedules other than those listed above are omitted because they are
not applicable
3. Exhibit list.......................................................... 53
(B) REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the quarter
ended December 31, 1993.
52
55
EL PASO NATURAL GAS COMPANY
EXHIBIT LIST
DECEMBER 31, 1993
3(i) -- Restated Certificate of Incorporation of EPG (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 July 22, 1993.
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 15,
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, dated October 10, 1990 and
effective September 1, 1991, between EPG and Pacific Gas and Electric
Company (Form 10-Q, No. 1-2700, filed November 14, 1991).
10.D -- Transportation Service Agreement, dated October 16, 1990 and
effective September 1, 1991, between EPG and Southern California Gas
Company (Form 10-Q, No. 1-2700, filed November 14, 1991); Amendment
to Exhibits A and B to the Transportation Service Agreement (Form
10-K, No. 1-2700, filed January 29, 1992).
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); Amendment to Exhibit B to the Transportation
Service Agreement for service to Arizona (Form 10-K, No. 1-2700,
filed January 29, 1992). 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).
53
56
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).
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).
54
57
10.H -- $300 million Revolving Credit Agreement dated as of February 11, 1992
between EPG and Citibank, N.A. (Form 8 amending the Form 10-K for the
year ended December 31, 1991, No. 1-2700, filed February 26, 1992).
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.N -- Supplemental Benefits Plan effective January 1, 1992 (Amendment No. 1
to Form S-2, No. 33-45369, filed February 27, 1992). El Paso Natural
Gas Company Supplemental Benefits Plan, Amendment No. 1, effective
July 7, 1992 (Form 10-Q, No. 1-2700, filed October 29, 1993).
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 dated as of January 1, 1992 (Amendment No.
1 to Form S-2, No. 33-45369, filed February 27, 1992).
10.Q -- Retirement Income Plan for Directors adopted January 15, 1992 (Form
10-K, No. 1-2700, filed February 3, 1993).
10.R -- Key Executive Severance Protection Plan effective as of July 7, 1992
(Form 10-K, No. 1-2700, filed February 3, 1993).
10.S -- Director Charitable Award Plan dated as of January 1, 1992 (Form
10-K, No. 1-2700, filed February 3, 1993).
10.T -- Receivables Purchase and Sale Agreement dated as of January 1, 1992,
between the Company, CIESCO L.P., Corporate Asset Funding Company
Inc. and Citicorp North America Inc. (Form 10-K, No. 1-2700, filed
February 3, 1993).
10.U -- Employment Agreement dated July 31, 1992, between EPG and William A.
Wise (Form 10-K, No. 1-2700, filed February 3, 1993).
10.V -- Letter Agreement dated October 22, 1990, between EPG and Luino
Dell'Osso, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
10.W -- Letter Agreement dated February 22, 1991, between EPG and Britton
White, Jr. (Form 10-K, No. 1-2700, filed February 3, 1993).
*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.
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.
55
58
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 14, 1994
(William A. Wise) President, Chief
Executive Officer and
Director
/s/ LUINO DELL'OSSO JR. Executive Vice January 14, 1994
(Luino Dell'Osso Jr.) President, Chief
Operating Officer and
Director
/s/ H. BRENT AUSTIN Senior Vice President January 14, 1994
(H. Brent Austin) and Chief Financial
Officer
/s/ THOMAS E. RICKS Vice President, Chief January 14, 1994
(Thomas E. Ricks) Accounting Officer and
Controller
/s/ BYRON ALLUMBAUGH Director January 14, 1994
(Byron Allumbaugh)
/s/ EUGENIO GARZA LAGUERA Director January 14, 1994
(Eugenio Garza Laguera)
/s/ BEN F. LOVE Director January 14, 1994
(Ben F. Love)
/s/ KENNETH L. SMALLEY Director January 14, 1994
(Kenneth L. Smalley)
56
59
INDEX TO EXHIBITS
Each exhibit set forth below is filed as part of this report.
EXHIBIT
NUMBER EXHIBIT
- --------------------
3(ii) -- By-Laws of EPG, as amended July 22, 1993.
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.