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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ____ TO ____
COMMISSION FILE NUMBER 0-296
EL PASO ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 74-0607870
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
KAYSER CENTER, 100 NORTH STANTON, EL PASO, TEXAS 79901
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (915) 543-5711
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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COMMON STOCK, NO PAR VALUE AMERICAN 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 WHETHER THE REGISTRANT HAS FILED ALL DOCUMENTS AND
REPORTS REQUIRED TO BE FILED BY SECTION 12, 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 SUBSEQUENT TO THE DISTRIBUTION OF SECURITIES UNDER A PLAN
CONFIRMED BY A COURT. 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. [ ]
AS OF MARCH 20, 1997, THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY
NON-AFFILIATES OF THE REGISTRANT WAS $309,772,975.
AS OF MARCH 20, 1997, THERE WERE OUTSTANDING 60,239,236 SHARES OF COMMON
STOCK, NO PAR VALUE.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE REGISTRANT'S DEFINITIVE PROXY STATEMENT FOR THE 1997 ANNUAL
MEETING OF ITS SHAREHOLDERS ARE INCORPORATED BY REFERENCE INTO PART III OF THIS
REPORT.
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DEFINITIONS
The following abbreviations, acronyms or defined terms used in this report
are defined below:
Abbreviations,
Acronyms or Defined Terms Terms
------------------------- -----
Agreed Order...................... Agreed Order of the Texas Commission
entered August 30, 1995 implementing
certain provisions of the Rate
Stipulation
ANPP Participation Agreement...... Arizona Nuclear Power Project
Participation Agreement dated August
23, 1973, as amended
APS............................... Arizona Public Service Company
Bankruptcy Case................... The case commenced January 8, 1992 by
El Paso Electric Company in the
Bankruptcy Court as Case No.
92-10148-FM
Bankruptcy Code................... United States Bankruptcy Code, 11
U. S. C. (S)101 et seq.
Bankruptcy Court.................. United States Bankruptcy Court for the
Western District of Texas, Austin
Division
CFE............................... Comision Federal de Electricidad de
Mexico (the national electric
utility of Mexico)
Common Plant or Common
Facilities...................... Facilities at or related to Palo Verde
that are common to all three Palo
Verde Units
Common Stock...................... Common stock, stated value $1 per
share, issued by the Company in the
Reorganization
Company........................... El Paso Electric Company
CSW............................... Central and South West Corporation
DOE............................... United States Department of Energy
Effective Date.................... February 12, 1996, the date the
Reorganization became effective
EPE............................... El Paso Electric Company
FERC.............................. Federal Energy Regulatory Commission
Four Corners...................... Four Corners Generating Station
FPA............................... Federal Power Act
Freeze Period..................... Ten-year period beginning August 2,
1995, during which base rates for
most Texas retail customers are
expected to remain frozen pursuant
to the Rate Stipulation
IID............................... Imperial Irrigation District, an
irrigation district in Southern
California
KV................................ Kilovolt(s)
KW................................ Kilowatt(s)
KWH............................... Kilowatt-hour(s)
Merger Agreement.................. Agreement and Plan of Merger dated as
of May 3, 1993 among the Company,
CSW and CSW Sub, as amended
MW................................ Megawatt(s)
MWH............................... Megawatt-hour(s)
New Mexico Commission............. New Mexico Public Utility Commission
NRC............................... Nuclear Regulatory Commission
OPC............................... Texas Office of Public Utility Counsel
Palo Verde........................ Palo Verde Nuclear Generating Station
Palo Verde Leases................. Leases and other documents entered
into in connection with a series of
sale and leaseback transactions in
1986 and 1987 involving a portion of
the Company's interest in Palo Verde
Palo Verde Participants........... Those utilities who share in power and
energy entitlements, and bear
certain allocated costs, with
respect to Palo Verde pursuant to
the ANPP Participation Agreement
Plan.............................. The Company's Fourth Amended Plan of
Reorganization dated November 7,
1995, pursuant to which the Company
emerged from bankruptcy on the
Effective Date
(i)
Abbreviations,
Acronyms or Defined Terms Terms
------------------------- -----
PNM.............................. Public Service Company of New Mexico
Predecessor Company.............. The Company prior to the
Reorganization
Rate Stipulation................. Stipulation and Settlement Agreement
dated as of July 27, 1995, between
the Company, the City of El Paso,
OPC and most other parties to the
Company's rate proceedings before
the Texas Commission providing for a
ten-year rate freeze and other
matters
Reorganization................... Reorganization and the emergence from
bankruptcy by the Company pursuant
to the Plan
Reorganized Company.............. The Company following the
Reorganization
SFAS............................. Statement of Financial Accounting
Standards
Texas Commission................. Public Utility Commission of Texas
TNP.............................. Texas-New Mexico Power Company
(ii)
TABLE OF CONTENTS
Item Description Page
- ---- ----------- ----
PART I
1 Business....................................................... 1
2 Properties..................................................... 20
3 Legal Proceedings.............................................. 20
4 Submission of Matters to a Vote of Security Holders............ 23
PART II
5 Market for Registrant's Common Equity and
Related Stockholder Matters.................................. 25
6 Selected Financial Data........................................ 27
7 Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 28
8 Financial Statements and Supplementary Data.................... 38
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 84
PART III
10 Directors and Executive Officers of the Registrant............. 84
11 Executive Compensation......................................... 84
12 Security Ownership of Certain Beneficial Owners
and Management............................................... 84
13 Certain Relationships and Related Transactions................. 84
PART IV
14 Exhibits, Financial Statement Schedules
and Reports on Form 8-K...................................... 84
(iii)
PART I
ITEM 1. BUSINESS
GENERAL
The Company is a public utility engaged in the generation, transmission and
distribution of electricity in an area of approximately 10,000 square miles in
west Texas and southern New Mexico. The Company also serves wholesale customers
in Texas, New Mexico, California and Mexico. The Company owns or has
significant ownership interests in five electrical generating facilities
providing it with a total capacity of approximately 1,500 megawatts. For the
twelve months ended December 31, 1996, the Company's energy sources consisted of
approximately 53% nuclear fuel, 32% natural gas, 7% coal and 8% purchased power.
The Company serves approximately 279,000 residential, commercial,
industrial and wholesale customers. The Company distributes electricity to
retail customers principally in El Paso, Texas and the City of Las Cruces ("Las
Cruces"), New Mexico (representing approximately 56% and 7%, respectively, of
the Company's revenues for the twelve months ended December 31, 1996). In
addition, the Company sells electricity to wholesale customers, including Texas-
New Mexico Power Company, the Imperial Irrigation District (a southern
California electric power agency), and the Comision Federal de Electricidad de
Mexico (the national electric utility of Mexico). Principal industrial and
other large customers of the Company include steel production, copper and oil
refining, garment manufacturing concerns and United States military
installations, including the United States Army Air Defense Center at Fort Bliss
in Texas and White Sands Missile Range and Holloman Air Force Base in New
Mexico.
The Company's principal offices are located at Kayser Center, 100 North
Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was
incorporated in Texas in 1901. As of March 3, 1997, the Company had
approximately 1,100 employees, approximately 30% of whom are covered by a
collective bargaining agreement that expires in June 1997.
REORGANIZATION UNDER CHAPTER 11 OF THE BANKRUPTCY CODE
PLAN OF REORGANIZATION
On February 12, 1996, the Company emerged from a bankruptcy proceeding
which it instituted in January 1992.
As a result of the Reorganization, the Company significantly reduced its
debt and simplified its capital structure. The Company's total obligations
subject to compromise (including obligations related to the Palo Verde Leases,
which represented $700 million of allowed claims in the Bankruptcy Case) prior
to its Reorganization was $2,007 million. Under the Plan, this debt and the
Palo Verde Lease obligations were extinguished and the creditors received a
combination of cash and newly issued debt and equity securities of the
Reorganized Company. On December 31, 1996, the capital structure of the
Reorganized Company consisted of approximately $1,046 million of long-term debt,
including the long-term portion of financing and capital lease obligations,
approximately $108 million of redeemable preferred stock and approximately $331
million of common stock equity.
The Company has a $100 million revolving credit facility to finance nuclear
fuel purchases and to provide working capital. At December 31, 1996,
approximately $46.6 million of this revolving credit facility
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had been drawn to finance nuclear fuel, of which approximately $20.2 million is
included in the long-term debt described above. Under the Plan, all of the
Predecessor Company's common and preferred stock was canceled and the holders of
such securities received approximately 15% of the Reorganized Company's Common
Stock and the right to receive certain litigation recoveries, if any.
In addition, on the Effective Date, the Palo Verde Leases were terminated
and the Company reacquired such interests. The Company has agreed to indemnify
certain parties to the Palo Verde Lease transactions against certain possible
tax liabilities.
The Company's Common Stock began trading on the American Stock Exchange on
February 16, 1996 under the symbol "EE."
RATE STIPULATION
The Agreed Order entered on August 30, 1995 by the Texas Commission became
effective on the Effective Date. The Agreed Order implemented the Rate
Stipulation, dated July 27, 1995, among the Company and substantially all of the
other parties to a rate proceeding in Texas. Among other things, under the Rate
Stipulation, (i) the Company received a one-time annual increase in Texas retail
base rates of approximately $24.9 million; (ii) the Company's base rates for
most customers in Texas were fixed at this increased level for ten years
beginning August 2, 1995; (iii) the City of El Paso granted the Company a new
franchise that extends through the Freeze Period; and (iv) the Company will
retain 75% during the first five years of the Freeze Period and 50% during the
remainder of the Freeze Period of (A) the revenues generated by providing third-
party transmission services and (B) profit margins from certain off-system power
sales. See "Regulation - Texas Rate Matters - Rate Stipulation and Agreed
Order."
ACCOUNTING TREATMENT
The Reorganization had significant impacts on the Company's financial
statements, including the creation of a new reporting entity upon emergence from
bankruptcy through the application of fresh-start reporting pursuant to
Statement of Position 90-7, "Financial Reporting by Entities in Reorganization
Under the Bankruptcy Code" ("SOP 90-7"). Accordingly, the Company's post-
Reorganization financial statements, which reflect the application of fresh-
start reporting, have not been prepared on a consistent basis with the pre-
Reorganization financial statements and are not comparable in all respects to
the financial statements prior to the Reorganization. The implementation of the
Rate Stipulation and fresh-start reporting resulted in (i) decreased operation
expense and increased depreciation expense due to the reacquisition of
previously sold and leased back generation facilities and due to accelerated
depreciation expense on a portion of the reorganization value assigned to
certain plant assets; (ii) increased interest expense due to the changes in the
Company's capital structure; and (iii) increased operating revenues related to a
rate increase in the Company's Texas jurisdiction. For accounting purposes, the
inception date of the Reorganized Company is deemed to be February 12, 1996. A
vertical line is shown in the financial statements to separate the Reorganized
Company from the Predecessor Company since the financial statements have not
been prepared on a consistent basis of accounting.
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FACILITIES
As described below, the Company currently has a net installed generating
capacity of approximately 1,500 MW, consisting of an entitlement of 600 MW from
Palo Verde Units 1, 2 and 3, 482 MW at its Newman Power Station, 246 MW at its
Rio Grande Power Station, an entitlement of 104 MW from Four Corners Units 4 and
5, and 68 MW at its Copper Power Station.
PALO VERDE STATION
The Company owns a 15.8% interest in each of the three 1,270 MW nuclear
generating units and Common Plant at Palo Verde, located west of Phoenix,
Arizona. The Palo Verde Participants include the Company and six other
utilities: APS, Southern California Edison Company ("SCE"), PNM, Southern
California Public Power Authority, Salt River Project Agricultural Improvement
and Power District ("SRP") and the Los Angeles Department of Water and Power.
APS serves as operating agent for Palo Verde.
The NRC has granted facility operating licenses and full power operating
licenses for all three units at Palo Verde for terms of forty years each. In
addition, the Company is separately licensed by the NRC to own its proportionate
share of Palo Verde.
Pursuant to the ANPP Participation Agreement, the Palo Verde Participants
share costs and generating entitlements in the same proportion as their
percentage interests in the generating units and each Palo Verde Participant is
required to fund its proportionate share of fuel, other operation, maintenance
and capital costs. The Company's total monthly share of these costs was
approximately $6.9 million in 1996. The ANPP Participation Agreement provides
that if a participant fails to meet its payment obligations, each non-defaulting
participant shall pay its proportionate share of the payments owed by the
defaulting participant.
Decommissioning. Pursuant to the ANPP Participation Agreement, as well as
pursuant to applicable law, the Company is required to fund its share of the
estimated costs to decommission Palo Verde over the estimated service life of
forty years. The Company's funding requirements are derived from periodic
engineering cost estimates.
In December 1995, the Palo Verde Participants approved a study by an
outside engineering firm of the cost of decommissioning Palo Verde. The 1995
study determined that the Company will have to fund approximately $229 million
(stated in 1995 dollars) to cover its share of such costs. The 1995 study
assumes that (i) maintenance expense for spent fuel storage will be incurred for
ten years after the shutdown of the last unit (estimated to be in 2024) rather
than the approximately 30 years utilized in a 1993 study; (ii) a national
interim spent fuel storage facility will be available; and (iii) as a result of
such national spent fuel storage facility, the amount of spent fuel stored on-
site is reduced from all spent fuel assemblies to the final core plus fuel
assemblies from approximately three refuelings. See "Energy Sources - Nuclear
Fuel - Spent Fuel Storage."
Cost estimates for decommissioning have increased with each study, although
the 1995 cost estimate is comparable to the previous cost estimate from a 1993
study (which determined that the Company would have to fund approximately $221
million, stated in 1993 dollars). The 1993 study was based on different
assumptions, primarily related to the decommissioning of spent fuel. The 1993
cost estimate included an estimated cost of approximately $50 million related to
on-site spent fuel storage facilities, while the 1995 study includes an
estimated cost of approximately $13 million related to spent fuel. This
difference in
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estimates is primarily due to the different timing assumptions discussed above.
The 1993 estimate reflected an 84% increase from the previous estimate made in
1989, primarily due to an increase in the estimated costs associated with the
permanent burial of low-level radioactive waste due to the uncertainty
surrounding the availability and cost of low-level radioactive waste
repositories, as discussed below.
Although the 1995 study is based on the latest available information, there
can be no assurance that decommissioning cost estimates will not continue to
increase in the future or that regulatory requirements will not change. In
addition, until a new low-level radioactive waste repository opens and operates
for a number of years, estimates of the cost to dispose of low-level radioactive
waste may increase significantly. See "Disposal of Low-Level Radioactive Waste"
below.
The rate freeze under the Rate Stipulation would preclude the Company from
seeking a rate increase in Texas during the Freeze Period to recover increases
in decommissioning cost estimates. Additionally, there can be no assurance that
the Company could increase its rates in any of its other jurisdictions to
recover such increased costs. See Item 7, "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Operational Prospects and
Challenges."
Steam Generators. Palo Verde has experienced degradation in the steam
generator tubes of each unit. The degradation includes axial tube cracking in
the upper regions of the two steam generators in Unit 2 and, to a lesser degree,
in Units 1 and 3. This form of steam generator tube degradation has recently
been seen at other U.S. nuclear generating stations. The units also have
experienced circumferential cracking at the tube sheet, a more common type of
tube cracking. The axial tube cracking was discovered following a steam
generator tube rupture in Unit 2 in March 1993. Since that time, APS has
undertaken an ongoing investigation and analysis and has performed corrective
actions designed to mitigate further degradation. Corrective actions have
included changes in operational procedures designed to lower the operating
temperatures of the units, chemical cleaning and the implementation of other
technical improvements. APS has stated that it believes its remedial actions
have slowed the rate of tube degradation.
Each of the Palo Verde units has been inspected during regularly scheduled
refueling outages and mid-cycle inspection outages. If tube cracks are detected
during an inspection, the affected tubes are taken out of service by plugging.
This may impair the performance of a unit if sufficient numbers of steam
generator tubes are affected.
The projected service lives of the units' steam generators are reassessed
by APS periodically in conjunction with inspections made during outages of the
Palo Verde units. In August 1995, APS announced that its ongoing analyses
indicated that it will be economically desirable to replace the Unit 2 steam
generators, which have been the most affected by tube cracking, in four to nine
years. APS further stated that it expects replacement of the steam generators
will be performed in conjunction with a normal refueling outage to limit
incremental outage time. APS also has stated that, based on the latest
available data, it estimates that the steam generators in Units 1 and 3 should
operate for their designated life of 40 years (to 2025 and 2027, respectively).
APS will continue to assess these steam generators periodically.
Steam generator replacement could be done through new steam generators
manufactured for Palo Verde or through the purchase of existing steam generators
that are compatible with Palo Verde's design. The Company believes replacement
of the steam generators would require the unanimous approval of the Palo Verde
Participants. The Company has not yet completed its analysis of the economic
feasibility of steam generator replacement, or other options that may be
available in connection with the operation of Unit 2. Also, the Company cannot
predict whether it or other Palo Verde Participants will agree to replace
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the Unit 2 steam generators. The Company expects that if the steam generators
in Unit 2 are replaced, most of such costs would be incurred between 1998 and
2005. The Company's portion of total costs associated with replacement of the
Unit 2 steam generators, including replacement power costs, is currently
estimated not to exceed $30 million.
The Rate Stipulation, however, precludes the Company from seeking a rate
increase in Texas during the Freeze Period to recover capital costs associated
with such replacement should it be necessary. It is uncertain whether the costs
associated with replacing the Unit 2 steam generators would be approved by the
New Mexico Commission and included in the Company's rate base in New Mexico.
See Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Operational Prospects and Challenges."
Disposal of Low-Level Radioactive Waste. Congress has established
requirements for the disposal of radioactive waste by each state generated
within its borders. Arizona, California, North Dakota and South Dakota have
entered into a compact (the "Southwestern Compact") for the disposal of low-
level radioactive waste. California will act as the first host state of the
Southwestern Compact, and Arizona will serve as the second host state. The
construction and opening of the California low-level radioactive waste disposal
site in Ward Valley has been delayed due to extensive public hearings, disputes
over environmental issues and review of technical issues related to the proposed
site. Despite being licensed by the State of California, the Department of the
Interior has not transferred the land to the state. Following a report by the
National Academy of Sciences, the Department of the Interior announced that if
certain environmental conditions were implemented prior to the transfer, it was
prepared to convey the land. The State of California is attempting to obtain
the land through the court system without the imposition of these environmental
restrictions. Although Palo Verde is estimated to undergo decommissioning
during the period in which Arizona will act as host for the Southwestern
Compact, the opposition, delays, uncertainty and costs experienced in California
demonstrate possible roadblocks that may be encountered in the future when
Arizona seeks to open its own waste repository.
Liability and Insurance Matters. The Palo Verde Participants have public
liability insurance against nuclear energy hazards up to the full limit of
liability of $200 million under federal law in the form of primary liability
insurance provided by commercial insurance carriers. Additionally, the Company
participates in an industry-wide retrospective assessment program, under which
industry participants would be required to pay an assessment to cover any loss
in excess of $200 million. The maximum assessment per reactor for each nuclear
incident is approximately $79.2 million, subject to an annual limit of $10
million per incident. Based upon the Company's 15.8% interest in Palo Verde,
the Company's maximum potential assessment per incident is approximately $37.6
million, with an annual payment limitation of approximately $4.7 million.
The Palo Verde Participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.7 billion, a substantial portion of the proceeds
of which must first be applied to stabilization and decontamination. Finally,
the Company has insurance against a portion of any increased cost of generation
or purchased power which may result from the accidental outage of any of the
three Palo Verde units if the outage exceeds 21 weeks.
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NEWMAN POWER STATION
The Company's Newman Power Station, located in El Paso, Texas, consists of
four generating units with an aggregate capacity of 482 MW. The units operate
primarily on natural gas, but are also capable of operating on fuel oil.
RIO GRANDE POWER STATION
The Company's Rio Grande Power Station, located in Sunland Park, New
Mexico, adjacent to El Paso, Texas, consists of three steam-electric generating
units with an aggregate capacity of 246 MW. The units operate primarily on
natural gas, but are also capable of operating on fuel oil.
FOUR CORNERS STATION
The Company owns an undivided 7% interest in Units 4 and 5 at Four Corners,
located in northwestern New Mexico. The two coal-fired generating units each
have a generating capacity of 739 MW. The Company shares power entitlements and
certain allocated costs of the two units with APS (the Four Corners operating
agent) and the other participants.
Four Corners is located on land held under easements from the federal
government and a lease from the Navajo Nation that expires in 2016. Certain of
the facilities associated with Four Corners, including transmission lines and
almost all of the contracted coal sources, are also located on Navajo land.
Units 4 and 5 are located adjacent to a surface-mined supply of coal.
COPPER POWER STATION
The Company's Copper Power Station, located in El Paso, Texas, consists of
a 68 MW combustion turbine used primarily to meet peak demands. The unit
operates primarily on natural gas, but is also capable of operating on fuel oil.
The combustion turbine and other generation equipment at the station were sold
and leased-back by the Company in 1980 pursuant to a twenty-year lease with an
option to renew for up to a seven-year period.
TRANSMISSION AND DISTRIBUTION LINES AND AGREEMENTS
The Company owns or has significant ownership interests in four major
transmission lines and owns the distribution network within its retail service
area. The Company is also a party to various transmission and power exchange
agreements that, together with its owned transmission lines, enable the Company
to obtain its energy entitlements from its remote generation at Palo Verde and
Four Corners.
Springerville-Diablo Line. The Company owns a 310-mile, 345 KV
transmission line from Tucson Electric Power Company's ("TEP") Springerville
Generating Plant near Springerville, Arizona to the Luna Substation near Deming,
New Mexico, and to the Diablo Substation near Sunland Park, New Mexico,
providing an interconnection with TEP for delivery of the Company's generation
entitlements from Palo Verde and, if necessary, Four Corners.
Arroyo-West Mesa Line. The Company owns a 202-mile, 345 KV transmission
line from the Arroyo Substation located near Las Cruces, New Mexico to PNM's
West Mesa Substation located near Albuquerque, New Mexico. This is the delivery
point for the Company's generation entitlement from Four
6
Corners, which power is transmitted to the West Mesa Substation over
approximately 150 miles of transmission lines owned by PNM. This transmission
line also carries power from the region to the west and north of Four Corners,
where the Company has a major interconnection with the other Four Corners
Participants.
Greenlee-Newman Line. The Company owns undivided interests in a 196-mile,
345 KV transmission line from the Newman Power Station to TEP's Greenlee
Substation in Arizona. This line provides an interconnection with TEP for
delivery of the Company's entitlements from Palo Verde and, if necessary, Four
Corners.
AMRAD-Eddy County Line. The Company owns an undivided 66.7% interest in a
125-mile, 345 KV transmission line from the AMRAD Substation near Oro Grande,
New Mexico to the Company's and TNP's high voltage direct current terminal at
the Eddy County substation near Artesia, New Mexico. This terminal enables the
Company to connect its transmission system to that of Southwestern Public
Service Company ("SPS"), providing the Company with access to power markets to
the east.
ISSUES REGARDING OPERATION OF TRANSMISSION SYSTEM
The Company experienced three system outages between September 19, 1995 and
October 21, 1995 and a fourth system outage on March 29, 1996. The four outages
were caused by different combinations of factors. The first three outages
involved faults on one of the Company's transmission lines, followed by relay
failures that resulted in the loss of a second Company transmission line and the
subsequent inability of the Company's load shedding programs to prevent general
system instability. The fourth outage was caused by a fault on a neighboring
utility's transmission line followed by relay failures on the Company's
transmission system that caused the loss of two of the Company's transmission
lines. Although the Company was able to stabilize its system for a brief period
of time following the loss of the two lines through a controlled load-reduction
scheme, a system outage occurred after a third Company line tripped out of
service.
In response to the outages, the Company has undertaken numerous remedial
measures, including the replacement of certain relay equipment, the
reconfiguration of structures that support certain high voltage wires and the
installation of two new load shedding systems, to lessen the likelihood that
future transmission faults will cause general system instability and widespread
outages. While performing these measures between mid-November 1995 and early
January 1996, the Company materially reduced the amount of power imported into
the El Paso load center in order to reduce stress on the system in the event of
a fault on these lines. Operation in this mode resulted in increased operating
costs of approximately $2.3 million due to the use of higher cost power from
local generating plants and the necessity of purchasing power from other
utilities to supply the Company's customers. While the Company can operate in
this mode during cool weather months when demand is low, the Company requires
its full allocation of power from its remote generating sources to meet the
normal demands of customers and contractual commitments to Mexico in the warmer
months.
The Company believes that its remedial efforts have solved the outage
problem, and the Company has continued to import normal amounts of power over
its transmission lines since January 1996. If the Company experiences further
difficulties with its system, it could be required to adopt costly operating
procedures until appropriate remedial efforts are implemented, and the Company
might not be able to deliver sufficient power to meets its contractual
obligations or to fulfill its statutory obligation to serve customers. In
addition, the Texas and the New Mexico Commissions, which have monitored the
7
Company's efforts to address the outages, could impose penalties or other
sanctions or deny the Company recovery of certain fuel and/or purchased power
costs related to the Company's decision to reduce power imports during the
period referenced above. The Company's capital expenditure budget does not
provide for major expenditures relating to the transmission system, and certain
of the Company's debt obligations restrict or prohibit major unanticipated
capital expenditures. In addition, the cost of constructing new transmission
facilities could not be charged to Texas retail customers under the Rate
Stipulation, and the Company cannot assure that it would be able to charge any
of its customers outside of Texas for such construction costs.
ENVIRONMENTAL MATTERS
The Company is subject to regulation with respect to air, soil and water
quality, solid waste disposal and other environmental matters by federal, state
and local authorities. These authorities govern current facility operations and
exercise continuing jurisdiction over facility modifications. Environmental
regulations can change rapidly and are difficult to predict. Because
construction of new facilities is subject to standards imposed by environmental
regulation, substantial expenditures may be required to comply with such
regulations. The Company analyzes the costs of its obligations arising from
environmental matters on an ongoing basis, and management believes it has made
adequate provision in its financial statements to meet such obligations.
However, unforseen expenses associated with compliance could have a material
adverse effect on the future operations and financial condition of the Company.
See Part II, Item 8, "Financial Statements and Supplementary Data - Note J of
Notes to Financial Statements."
PCB Treatment, Inc. The Company received a request from the U.S.
Environmental Protection Agency ("EPA") to participate in the remediation of
polychlorinated biphenyls ("PCBs") at two facilities in Kansas City, Missouri,
which had been operated by PCB Treatment, Inc. ("PTI"). The Company's manifests
indicate that between 1982 and 1986, the Company sent 23 shipments of PCBs or
PCB-containing electric equipment ("PCB Equipment") to PTI, accounting for
approximately 2 to 3%, by weight, of the PCBs and PCB Equipment received at that
site by PTI. Presently, PTI has discontinued operations and the EPA has
determined that PTI's abandoned facilities require remediation.
The Company and the PTI Steering Committee, which consists of the largest
generators of the PCBs sent to PTI, have executed a settlement agreement. In
consideration for the payment of approximately $0.2 million, the settlement
agreement excuses any further liability to the Steering Committee by the Company
and indemnifies the Company for any liabilities to other parties as may be
asserted in the future.
The Company may still face liability for possible deliveries of PCBs by PTI
to a third site which is also subject to remedial action by the federal
authorities, except to the extent that those PCBs were transferred from the
first site. The Company's records do not indicate any deliveries of PCBs to
this third site. Management believes the Company is unlikely to face
substantial unindemnified liabilities associated with this third site.
Coal Mine Reclamation. The Company has been informed by APS that the
Company's estimated financial obligation for coal mine reclamation at Four
Corners is not being fully reflected in the costs for which the Company is
billed. APS, the operating agent of Four Corners, is performing an analysis to
establish an appropriate revised cost estimate. Based on preliminary estimates
from APS and the coal provider, the Predecessor Company recorded a liability of
approximately $12 million which reflects the present value of the estimated
future costs of reclamation at the Effective Date to reflect its share of the
coal mine reclamation obligation.
8
CONSTRUCTION PROGRAM
The Company has no current plans to construct any new generating facilities
through at least 2004. Utility construction expenditures reflected in the table
below consist primarily of expanding and updating the electric transmission and
distribution systems and the cost of improvements at Palo Verde. The Company's
estimated cash construction costs for 1997 through 2000 are approximately $206
million. Actual costs may vary from the construction program estimates set forth
below. Such estimates are reviewed and updated periodically to reflect changed
conditions.
BY YEAR (1) BY FUNCTION
(IN MILLIONS) (IN MILLIONS)
------------- -------------
1997....... $ 50 Production (1)... $ 53
1998....... 52 Transmission..... 20
1999....... 50 Distribution..... 102
2000....... 54 General.......... 31
---- ----
Total... $206 Total......... $206
==== ====
- -----------------
(1) Does not include acquisition costs for nuclear fuel. See "Energy Sources -
Nuclear Fuel."
ENERGY SOURCES
GENERAL
The following table summarizes the percentage contribution of nuclear,
natural gas, coal, and purchased power to the total KWH energy mix of the
Company.
YEARS ENDED DECEMBER 31,
-----------------------
POWER SOURCE 1996 1995 1994
------- ------ ------
Nuclear........................ 53% 53% 45%
Natural Gas.................... 32 30 32
Coal........................... 7 9 9
Purchased Power................ 8 8 14
---- ---- ----
Total......................... 100% 100% 100%
==== ==== ====
Fuel and purchased power costs are generally passed through directly to
customers in Texas and New Mexico pursuant to currently applicable regulations.
Historical fuel costs and revenues are reconciled periodically in proceedings
before the appropriate commission to establish the applicable fuel rate to be
charged customers and to determine whether a refund or surcharge based on such
historical costs and revenues is necessary. See "Regulation -Texas Rate Matters
- -Fuel," " - New Mexico Rate Matters - Fuel" and Part II, Item 8, "Financial
Statements and Supplementary Data - Note C of Notes to Financial Statements."
9
NUCLEAR FUEL
The Palo Verde Participants have contracts for uranium concentrate which
should be sufficient to meet Palo Verde's operational requirements through at
least 2000. Spot purchases in the uranium market will also be made, as
appropriate. The Palo Verde Participants have contracted for up to 100% of
conversion services required through 2000. The Palo Verde Participants have an
enrichment services contract with the United States Enrichment Corporation
("USEC") which obligates USEC to furnish the enrichment services required for
the operation of the three Palo Verde units through 2002, with an option for
five additional years. A new contract provides fuel assembly fabrication
services for each Palo Verde unit through 2016.
Spent Fuel Storage. The spent fuel storage facilities at Palo Verde
have sufficient capacity to store all fuel expected to be discharged from normal
operation of all of the Palo Verde units through at least 1999. If necessary,
more spaces in the existing fuel pool may be approved for use by the NRC which
would extend storage capacity through 2001, or, if more economical, alternative
storage facilities can be constructed on-site.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987,
the DOE is obligated to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by all domestic power reactors. In
November 1989, the DOE reported that such disposal facilities will not be in
operation until 2010. Subsequent judicial decisions require the DOE to start
disposing of spent nuclear fuel no later than January 31, 1998, although the DOE
has told APS that it will not meet this deadline. As a result, under the DOE's
current criteria for shipping allocation rights, it is estimated that Palo Verde
could not ship spent fuel to the DOE permanent disposal facility until
approximately 2025. APS has indicated that alternative interim spent fuel
storage methods will be available on-site or off-site for use by Palo Verde to
allow its continued operation and to store spent fuel safely until shipments to
the DOE's permanent disposal facility begin. The Texas Commission is currently
evaluating what, if any, action it should take with regard to payments made by
the Company to the DOE for funding of the DOE's obligation to start accepting
spent nuclear fuel by January 31, 1998.
Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement,
the Company has an undivided interest in nuclear fuel purchased in connection
with Palo Verde. On the Effective Date, the Company and Texas Commerce Bank, as
trustee, entered into a $100 million credit facility with Chemical Bank that
includes a portion for working capital requirements and up to $60 million for
the financing of nuclear fuel. At December 31, 1996, approximately $46.6
million had been drawn to finance nuclear fuel. The Company also entered into a
purchase contract with the trustee related to the financing of nuclear fuel
purchases. Under the terms of the documents related to the nuclear fuel
financing, the trust borrows under the credit facility amounts sufficient to
purchase and prepare nuclear fuel for use. The Company is obligated to repay
borrowings by the trustee under the facility, which obligation is secured by
Collateral Series Bonds, and is required to make quarterly payments to the trust
for the heat energy produced by the nuclear fuel and used by the Company. For
financial reporting purposes, the Company reports the assets and liabilities of
the trust as its own.
NATURAL GAS
In 1996, the Company's natural gas requirements at the Rio Grande
Power Station were met solely with spot natural gas purchases from various
suppliers. Interstate gas is delivered under a firm ten year transportation
agreement, which expires in 2001. Based on the current availability of economic
and reliable
10
spot natural gas, the Company anticipates it will continue to purchase spot
natural gas for the Rio Grande Power Station for the near term. To complement
the spot purchases, the Company has entered into a one-year gas supply contract
with Cook Inlet for 1997. For the long term, the Company will evaluate the
availability of spot natural gas versus other supplies in obtaining a reliable
and economical supply for the Rio Grande Power Station.
In 1996, the natural gas requirements for the Newman and Copper Power
Stations were supplied and transported pursuant to an intrastate natural gas
contract which expired December 31, 1996. The Company has an agreement with KN-
Energy to supply gas to the Newman and Copper Power Stations beginning in 1997
through 2001. To augment this contract, the Company procured a second natural
gas supply agreement with U.S. Gas Transportation, Inc., which runs through
2001.
COAL
APS, as operating agent for Four Corners, purchases Four Corners' coal
requirements from a supplier with a long-term lease of coal reserves owned by
the Navajo Nation. Management believes that Four Corners has sufficient
reserves of coal to meet the plant's operational requirements for its useful
life.
PURCHASED POWER
To supplement its own generation, the Company has a firm power
purchase agreement with SPS for a minimum of 35 MW for 1997.
11
OPERATING STATISTICS
DECEMBER 31,
------------------------------------------
1996 (A) 1995 (B) 1994 (B)
---------- ---------- ----------
Operating revenues (In thousands):
Base revenues:
Retail:
Residential........................................... $ 141,719 $ 128,295 $ 129,869
Commercial and industrial, small...................... 138,910 128,715 126,450
Commercial and industrial, large...................... 43,483 40,870 39,754
Sales to public authorities........................... 65,534 59,613 59,811
---------- ---------- ----------
Total retail...................................... 389,646 357,493 355,884
Wholesale sales for resale............................... 71,254 74,557 75,750
---------- ---------- ----------
Total base revenues............................... 460,900 432,050 431,634
Fuel revenues and economy sales............................ 114,042 68,823 101,076
Other...................................................... 3,981 3,744 4,050
---------- ---------- ----------
Total operating revenues.......................... $ 578,923 $ 504,617 $ 536,760
========== ========== ==========
Number of customers (End of year):
Residential........................................... 250,209 245,245 240,368
Commercial and industrial, small...................... 25,304 24,615 23,857
Commercial and industrial, large...................... 102 89 80
Other................................................. 3,711 3,674 3,470
---------- ---------- ----------
Total............................................. 279,326 273,623 267,775
========== ========== ==========
Average annual use and revenue per residential customer:
KWH................................................... 6,238 6,057 6,313
Revenue............................................... $ 661.04 $ 578.88 $ 644.82
========== ========== ==========
Average revenue per KWH (In cents):
Residential........................................... 10.60 9.56 10.21
Commercial and industrial, small...................... 9.21 8.15 8.88
Commercial and industrial, large...................... 4.85 4.34 5.01
========== ========== ==========
Energy supplied, net, KWH (In thousands):
Generated............................................. 7,920,675 7,439,404 7,018,423
Purchased and interchanged............................ 711,791 584,853 1,051,251
---------- ---------- ----------
Total............................................. 8,632,466 8,024,257 8,069,674
========== ========== ==========
Energy sales, KWH (In thousands):
Retail:
Residential........................................... 1,545,274 1,473,349 1,500,426
Commercial and industrial, small...................... 1,779,986 1,754,176 1,721,736
Commercial and industrial, large...................... 1,216,941 1,121,329 1,092,028
Sales to public authorities........................... 1,110,706 1,068,048 1,081,850
---------- ---------- ----------
5,652,907 5,416,902 5,396,040
Wholesale:
Sales for resale...................................... 1,753,553 1,646,357 1,925,671
Economy sales......................................... 757,999 538,102 320,026
---------- ---------- ----------
Total sales....................................... 8,164,459 7,601,361 7,641,737
Losses and company use................................ 468,007 422,896 427,937
---------- ---------- ----------
Total............................................. 8,632,466 8,024,257 8,069,674
========== ========== ==========
Native system:
Peak load, KW............................................ 1,105,000 1,088,000 1,093,000
Net generating capacity for peak, KW..................... 1,500,000 1,500,000 1,497,000
Load factor.............................................. 63.4 % 61.6 % 61.1 %
========== ========== ==========
Total system:
Peak load, KW............................................ 1,387,000 1,374,000 1,365,000
Net generating capacity for peak, KW..................... 1,500,000 1,500,000 1,497,000
Load factor.............................................. 64.2 % 62.0 % 63.7 %
========== ========== ==========
(A) Financial data is based on the combined results for the Predecessor Company
for the period January 1, 1996 to February 11, 1996 and the Reorganized
Company for the period February 12, 1996 to December 31, 1996.
(B) Predecessor Company.
12
REGULATION
TEXAS RATE MATTERS
The rates and services of the Company in Texas municipalities are
regulated by those municipalities, and in unincorporated areas by the Texas
Commission. The largest municipality in the Company's service area is the City
of El Paso. The Texas Commission has exclusive appellate jurisdiction to review
municipal orders and ordinances regarding rates and services in Texas and
jurisdiction over certain activities of the Company.
Rate Stipulation and Agreed Order. The Company's rates for its Texas
jurisdictional customers are governed by the Agreed Order, which became
effective on the Effective Date. The Agreed Order implemented certain
provisions of the Rate Stipulation and set rates consistent with the Rate
Stipulation. Among other things, under the Rate Stipulation: (i) the Company
received a one-time annual increase in Texas retail base rates of approximately
$24.9 million; (ii) the Company's base rates for most customers in Texas were
fixed at this increased level for the Freeze Period; (iii) the City of El Paso
granted the Company a new franchise that extends through the Freeze Period; (iv)
the Company will retain 75% during the first five years of the Freeze Period and
50% during the remainder of the Freeze Period of (A) the revenues generated by
providing third-party transmission services and (B) profit margins from certain
off-system power sales; (v) the Company's reacquisition of the Palo Verde leased
assets is deemed to be in the public interest; (vi) no refunds or surcharges
were made to customers with respect to fuel costs and revenues for the period
from July 1993 through June 1995; and (vii) all appeals of Texas Commission
orders concerning the Company and all outstanding Texas Commission dockets
concerning the Company's rates were resolved.
Neither the Rate Stipulation nor the Agreed Order deprives the Texas
regulatory authorities of their jurisdiction over the Company during the Freeze
Period. However, the Texas Commission determined in the Agreed Order that the
rate freeze is in the public interest and results in just and reasonable rates.
Further, the signatories to the Rate Stipulation (other than the General
Counsel, OPC and the State of Texas) agreed not to seek to initiate an inquiry
into the reasonableness of the Company's rates during the Freeze Period and to
support the Company's entitlement to rates at the freeze level throughout the
Freeze Period. The Company believes, but cannot assure, that its cost of
service will support rates at or above the freeze level throughout the Freeze
Period and, therefore, does not believe any attempt to reduce the Company's
rates would be successful. However, during the Freeze Period, the Company is
precluded from seeking rate increases in Texas, even in the event of increased
operating or capital costs. In the event of a merger, the parties to the Rate
Stipulation retain all rights provided in the Rate Stipulation, their rights to
participate as a party in any proceeding related to the merger, as well as the
right to pursue a reduction in rates below the freeze level to the extent of
post-merger synergy savings. See "Recent Changes in Utility Regulation."
Fuel. The Company must periodically reconcile its Texas fuel costs
pursuant to Texas Commission rules. The Company has not filed a reconciliation,
which must contain not less than twelve months nor more than thirty-six months
of reconcilable data for any period since June 1995. In a reconciliation,
revenues that the Company collected from Texas customers under its fixed fuel
factor are reconciled with the expenses for fuel and purchased power actually
incurred by the Company for the period covered by the reconciliation.
Differences between revenues collected and expenses incurred are subject to a
refund to customers (in the case of an overrecovery of fuel costs) or surcharge
(in the case of an underrecovery of fuel costs). The Commission staff, local
regulatory authorities such as the City of El Paso, and customers are
13
entitled to intervene in a fuel reconciliation proceeding and to challenge the
recovery of expenses on the basis of unreasonable or improper fuel and purchased
power costs.
Higher natural gas prices began in December 1996 and continued in the
first quarter of 1997. These higher natural gas prices will increase the
Company's underrecovered fuel costs, which will be reviewed in the next Texas
fuel reconciliation.
Palo Verde Performance Standards. The Texas Commission has
established performance standards for the operation of Palo Verde, pursuant to
which Palo Verde is evaluated annually to determine whether its three-year
rolling average capacity factor entitles the Company to a reward or subjects it
to a penalty. There are five performance bands based around a target capacity
factor of 70%. The capacity factor is calculated as the ratio of actual
generation to maximum possible generation. If the capacity factor, as measured
on a station-wide basis for any consecutive 24-month period, should fall below
35%, the Texas Commission could reconsider the rate treatment of Palo Verde,
regardless of the provisions of the Rate Stipulation. The removal of Palo Verde
from rate base could have a significant negative impact on the Company's
revenues and financial condition. Based upon the formula for calculating the
performance standards in Texas, the Company does not believe a performance
penalty will be assessed for the year ended December 31, 1996.
NEW MEXICO RATE MATTERS
The New Mexico Commission has jurisdiction over the Company's rates
and services in New Mexico and jurisdiction over certain activities of the
Company, including prior approval of the issuance, assumption or guarantee of
securities. The New Mexico Commission's decisions are subject to judicial
review. Current base rates in New Mexico were established in 1990 and have not
increased. The Company does not have an agreement with New Mexico regulatory
authorities or parties to past New Mexico regulatory proceedings comparable to
the Rate Stipulation.
Pending Rate Case. In October 1996, the New Mexico Commission issued
an order in Case No. 2722, requiring the Company to answer certain ratepayer
complaints and to file a rate filing package, including cost of service data and
supporting testimony. On March 3, 1997, the Company filed all of the rate
filing package data required by the Commission's order with the Commission.
Although the Company's filing demonstrates a revenue deficiency of approximately
$8.6 million under current rates, the Company did not request a rate change to
recover the deficiency. The Company cannot predict what action the New Mexico
Commission may take in this proceeding.
Fuel. The Company is required to file an annual fuel report and an
annual Palo Verde performance standards report, discussed below, with the New
Mexico Commission by January 31 of each year for the preceding calendar year.
The Company requested and received two extensions of time and filed these
reports on March 24, 1997. The Company's filing reflects a significant increase
in the monthly fuel charge to be effective with bills rendered on or after May
1, 1997. This increase is necessary because of significant increases in the
spot price of natural gas which have caused the Company to underrecover its fuel
costs in New Mexico by approximately $2.0 million for the year ended December
31, 1996. The recovery of this amount, coupled with projected higher gas costs
for 1997, results in an increase in the proposed 1997 fuel factor of
approximately 50% over the present factor. There can be no assurance that the
Commission will accept the Company's proposed fuel factor. As in Texas,
interested parties are allowed to intervene and challenge the recoverability of
expenses as unreasonable or imprudent. Any significant disallowance of recovery
could have a material adverse effect on the Company's financial results.
14
Palo Verde Performance Standards. The New Mexico Commission has
established performance standards for the operation of Palo Verde, pursuant to
which the entire Palo Verde station is evaluated annually to determine if its
achieved capacity factor allows the Company to claim a credit or subjects the
Company to a penalty. Because Unit 3 is not included in the Company's New
Mexico rate base, any penalty or credit calculated on a total station basis is
limited to two-thirds of such penalty or credit. The capacity factor is
calculated as the ratio of actual generation to maximum possible generation. If
the annual capacity factor is 35% or less, the New Mexico Commission is required
to initiate a proceeding to reconsider the rate base treatment of Palo Verde.
The removal of Palo Verde from rate base could have a significant negative
impact on the Company's revenues and financial condition. For the year ended
December 31, 1996, the Palo Verde station capacity factor was 86.20%. This
capacity factor resulted in the Company's entitlement to a credit. However, the
Company is voluntarily foregoing collection of this credit to partially mitigate
the increase in the proposed New Mexico fuel factor, discussed above.
FEDERAL REGULATORY MATTERS
Federal Energy Regulatory Commission. The Company is subject to
regulation by the FERC in certain matters, including rates for wholesale power
sales, transmission of electric power and the issuance of securities.
The Company has a long-term firm power sales agreement with IID
providing for the sale of 100 MW of firm capacity and 50 MW of contingent
capacity through April 2002. The agreement generally provides for level sales
prices over the life of the agreement. The Company has a firm power sales
agreement with TNP, providing for sales to TNP in the minimum amount of 25 MW
through 2002. Sales prices are essentially level for the remaining life of the
agreement. Rate tariffs currently applicable to IID and TNP contain fuel and
purchased power cost adjustment provisions designed to recover the Company's
fuel and purchased power costs.
In July 1996, the Company filed its open access transmission tariffs
(Docket No. OA96-200-000) in compliance with Order No. 888, Promoting Wholesale
Competition Through Open Access Non-Discriminatory Transmission Services by
Public Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities ("Order No. 888"), covering network and point-to-point
transmission services and the six specifically required ancillary services.
Several parties, including Las Cruces, other utilities and several wholesale
power marketers intervened and filed protests to the Company's tariffs. Issues
raised by the intervenors included rates and the terms and conditions of the
Company's tariffs, including the treatment and costs related to certain
facilities making access to the CFE more available to parties other than the
Company. In February 1997, the Company entered into a stipulated agreement among
the various parties settling all issues related to Docket No. OA96-200-000.
Under the settlement the Company will provide transmission service, to the
extent transmission capacity is available, to any party for firm or
interruptible service to the CFE until the earlier of the end of 1998 or the
date the FERC rules on the complaint filed by Enron. See Item 3, "Legal
Proceedings - Transmission Service to Mexico."
In December 1996, Las Cruces filed a request at the FERC for a
determination that Las Cruces would have no stranded cost obligation to the
Company in the event the city leaves the Company's system and operates its own
municipal utility. The Company calculated Las Cruces' stranded cost obligation
to be approximately $234 million. The FERC is expected to establish a
procedural schedule for discovery and hearings in this matter. The Company is
unable to predict the outcome of this proceeding or the impact it may have on
the Company. See Item 3, "Legal Proceedings - Litigation with Las Cruces."
Also in December 1996, SPS filed a request for the issuance of an
order by the FERC requiring the Company to accept as a "completed application"
for service under the Company's open access transmission tariff a September 1996
request by SPS for service that may be needed for SPS to deliver electricity to
a
15
newly-formed Las Cruces municipal electric system. The Company stated in
response to that request that SPS had failed to provide certain information
required to be submitted by persons seeking service under its open access
transmission tariff. The Company has asked that the proceedings initiated by
Las Cruces and by SPS, respectively, be consolidated. Both matters are
currently pending before the FERC.
Department of Energy. The DOE traditionally regulates the Company's
exports of power to the CFE in Mexico pursuant to a license granted by the DOE
and a presidential permit. In addition, the DOE is authorized to assess
operators of nuclear generating facilities for a share of the costs of
decommissioning the DOE uranium enrichment facilities.
In October 1996, the FERC issued an order requiring the Company to
provide Enron Power Marketing, Inc., a wholesale power marketer, with firm
point-to-point transmission service over the Company's transmission system to
substation facilities near the border. The FERC, however, concurred with the
Company's position that the FERC does not have jurisdiction to order
transmission across the border, suggesting that the DOE has such jurisdiction.
Promptly after the issuance of the FERC order, Enron asked the DOE to
exercise its authority over Presidential Permits relating to construction of
border-crossing transmission facilities and over export authorizations issued to
the Company and to Enron to require transmission access for delivery of
electricity to the CFE in Mexico. Pursuant to Enron's request, the DOE, on
October 30, 1996, issued a Notice and Delegation and Assignment which delegated
to the FERC its authority to carry out the DOE's duties with respect to
Presidential Permits and export authorizations issued to the Company. The
Company has filed responses to Enron's request at both the FERC and the DOE in
which it has asserted that the DOE has no authority to require transmission of
electric energy for delivery to the CFE. However, the Company agreed to provide
access, to the extent transmission capacity is available, to a winning bidder
during 1997, if someone other than the Company, pending resolution of this
jurisdictional dispute. The Company's agreement to provide such access in no
way prejudices the Company's position, which remains that under the current law
the provision of such access is not required. Neither the FERC nor the DOE has
taken any final action on this matter.
Nuclear Regulatory Commission. The NRC has jurisdiction over the
Company's licenses for Palo Verde and regulates the operation of nuclear
generating stations to protect the health and safety of the public from
radiation hazards and has authority to conduct environmental reviews pursuant to
the National Environmental Policy Act.
OTHER WHOLESALE CUSTOMERS
The primary term of the Company's previous five year sales agreement
for firm capacity and associated energy to the CFE terminated December 31, 1996.
In September 1996, the CFE issued a request for proposals for replacement power
for 1997. The Company submitted a bid and was ultimately selected by the CFE to
provide varying amounts of power during 1997 ranging from 120 to 200 MW. Since
the CFE load provided by the Company will be isolated from the rest of the CFE
system, the Company is also providing the CFE with the flexibility to increase
its power deliveries up to 5% above its monthly contract capacity level in order
to meet its customer power requirements. The price is stable throughout the
term of the agreement and includes charges for capacity and energy as well as
transmission and any required ancillary services. Under the new agreement with
the CFE, revenues in 1997 related to power sales to the CFE are expected to be
lower than revenues recorded in 1996. The agreement requires payment in United
16
States dollars. See Item 3, "Legal Proceedings - Transmission Service to
Mexico" and Part II, Item 8, "Financial Statements and Supplementary Data - Note
M of Notes to Financial Statements."
RECENT CHANGES IN UTILITY REGULATION
General. The electric utility industry faces increasing pressure to
become more competitive as legislative, regulatory, economic and technological
changes occur. Federal legislation, as well as legislative and regulatory
initiatives in various states and proposed initiatives in Texas and New Mexico,
encourages competition in the Company's service area for electricity generation
among electric utility and non-utility power producers. Together with
increasing customer demand for lower-priced electricity and other energy
services, these measures have accelerated the industry's movement toward more
competitive pricing and cost structures. Such competitive pressures could
result in the loss of customers and diminish the ability of the Company to fully
recover its investment in generation assets, as well as the cost of operating
these assets. This issue is particularly important to the Company because its
rates are significantly higher than the national and regional averages. In the
face of increased competition, there can be no assurance that such competition
will not adversely affect the future operations, cash flows and financial
condition of the Company, or that the Company will be able to sustain retail
rates at the levels established by the Rate Stipulation during the Freeze
Period.
Of particular importance to the Company is the issue of ultimate
recoverability of costs previously found by regulatory authorities to be
reasonable and prudent, but which at the same time are higher than would be
recovered under immediate, full competition (i.e., stranded costs). Across the
industry, as well as at the state level, there is much discussion and debate on
this issue. At this time, there appears to be no clear solution. At the
federal level, the FERC has announced, through a formal rulemaking, its
intention to allow 100% recovery of all legitimate verifiable stranded costs
attributable to FERC jurisdictional customers. Texas and New Mexico are engaged
in various activities, at the commission and legislative level, which are
attempting to address the issue of stranded cost recovery from customers subject
to state legislation.
FERC. In April 1996, pursuant to its authority under Sections 205 and
206 of the FPA, the FERC issued its Order No. 888. Order No. 888 requires all
public utilities owning, operating or controlling facilities used for
transmitting electricity in interstate commerce to (i) file open access
transmission tariffs containing minimum terms and conditions of non-
discriminatory service and (ii) take transmission service (including ancillary
services) for their own new wholesale sales and purchases of electric energy
under the open access tariffs. Additionally, Order No. 888 permits public
utilities to seek recovery of legitimate, prudent and verifiable stranded costs
and provides a mechanism for the recovery of such costs. Order No. 888 also
provides for recovery of costs associated with former power customers and new
municipally-owned entities becoming transmission-only customers as a result of
providing open access transmission if the utility had a reasonable expectation
of continuing to provide service to the departing customer. Order No. 888
established criteria under which stranded costs will be evaluated for contracts
entered into prior to July 11, 1994, and for stranded costs resulting from the
formation of any new municipal utilities. Recovery of stranded costs under
contracts entered into after July 10, 1994, will be governed by the terms of
those contracts.
In April 1996, the FERC also issued Order No. 889, Open Access Same-
Time Information System (formerly Real-Time Information Networks) and Standards
of Conduct ("Order No. 889"). Order No. 889 requires all public utilities
owning, operating or controlling facilities used for transmitting electricity in
interstate commerce to develop and maintain an Open Access Same-Time Information
System that will give existing and potential
17
transmission users access to transmission related information on a basis
consistent with that available to a utility's employees engaged in the buying
and selling of power. Order No. 889 further requires public utilities to
separate their transmission and generation marketing functions and
communications and adopt standards of conduct ensuring that all open access
transmission customers are treated in a non-discriminatory manner.
Texas. In February 1996, the Texas Commission adopted a rule
governing wholesale transmission access, as required by recent Texas
legislation. The Texas Commission does not have jurisdiction over the Company's
wholesale transactions. However, the rule required the Company to file its
FERC-approved open access transmission tariffs with the Texas Commission to
certify compliance with the Texas legislation.
During 1996, pursuant to the directives of the Texas Legislature in
legislation passed in 1995, the Texas Commission conducted projects to evaluate
the (i) scope of competition in the electric industry in Texas and (ii)
potential for stranded investment, procedures for allocating stranded costs and
acceptable methods of stranded cost recovery. The Texas Commission's report
consolidating the two projects was issued in January 1997. While it recommended
a careful and deliberate approach to continued expansion of competition in the
Texas electric market, ultimately leading to retail competition with certain
safeguards, it also recommended against any legislation that would introduce
broad based retail competition before 2000. The Texas Commission quantified the
potential "excess of cost over market" ("ECOM") at both wholesale and retail
levels under several scenarios. With respect to the Company's potential for
stranded costs, the Texas Commission estimated no wholesale ECOM, and estimated
retail ECOM ranging from a high of $1.3 billion to a low of $781.0 million, with
an expected value of $1.1 billion, assuming full retail access in 1998. The
Company cannot determine at this time the effects that would occur, including
any possible effects on the Rate Stipulation, as the result of any broad based
competition legislative action, if any, implemented in 1997.
New Mexico. The New Mexico Commission initiated a notice of inquiry
regarding competition and the restructuring of regulation of the electric
industry in 1996. The New Mexico Commission received comments from numerous
parties representing various interests and conducted workshops in an attempt to
arrive at a consensus with respect to the need for regulatory change, the nature
of such change and the timing/transition of any changes. No consensus was
reached by the participants. With respect to stranded costs, the New Mexico
Commission applied the same ECOM model that was developed for Texas. The
Company's New Mexico ECOM calculation ranged from a high of $248 million to a
low of $173 million. The Company also provided the New Mexico Commission with
its calculation of stranded costs for New Mexico pursuant to FERC Order No. 888,
which equaled $364 million.
18
EXECUTIVE OFFICERS OF THE COMPANY
Name Age Current Position and
Business Experience
---- --- --------------------
James S. Haines........... 50 Chief Executive Officer, President and Director
since May 1996; Executive Vice President and
Chief Operating Officer of Western Resources,
Inc. from June 1995 to May 1996; Executive
Vice President and Chief Administrative
Officer of Western Resources, Inc. from April
1992 to June 1995.
Eduardo A. Rodriguez...... 41 Senior Vice President - Customer and Corporate
Services since August 1996; Senior Vice
President since January 1994; Vice President
from April 1992 to January 1994; General
Counsel from 1988 to August 1996; Secretary
from January 1989 to January 1994.
J. Frank Bates............ 46 Vice President - Transmission and Distribution
since August 1996; Vice President - Operations
from May 1994 to August 1996; Vice President -
Customer Services Texas Division from June
1989 to May 1994.
Michael L. Blough......... 41 Vice President - Administration since August
1996; Vice President since May 1995;
Controller and Chief Accounting Officer from
November 1994 to August 1996; Assistant Vice
President -Financial Planning from September
1990 to November 1994.
Gary R. Hedrick........... 42 Vice President, Treasurer and Chief Financial
Officer since August 1996; Treasurer since
March 1996; Vice President -Financial Planning
and Rate Administration from September 1990 to
August 1996.
John C. Horne............. 48 Vice President - Power Generation since August
1996; Vice President - Power Supply from May
1994 to August 1996; Vice President -
Transmission Systems Division from August 1989
to May 1994.
Robert C. McNiel.......... 50 Vice President - Public Affairs and Marketing
since August 1996; Vice President - New Mexico
Division from December 1989 to August 1996.
Terry Bassham............. 36 General Counsel since August 1996; Shareholder
with Clark, Thomas & Winters, P.C. from May
1993 to August 1996; Shareholder with Moreno,
Fry & Bassham from February 1992 to May 1993;
Shareholder with Kemp, Smith, Duncan &
Hammond, P.C. for more than one year prior to
February 1992.
Guillermo Silva, Jr....... 43 Secretary since January 1994; Assistant
Secretary from June 1989 to January 1994.
The executive officers of the Company are elected annually and serve at the
discretion of the Board of Directors.
19
ITEM 2. PROPERTIES
The principal properties of the Company are described in Item 1,
"Business," and such descriptions are incorporated herein by reference.
Transmission lines are located either on private rights-of-way, easements or on
streets or highways by public consent. See Part II, Item 8, "Financial
Statements and Supplementary Data - Note H of Notes to Financial Statements" for
information regarding encumbrances against the principal properties of the
Company.
ITEM 3. LEGAL PROCEEDINGS
LITIGATION WITH CENTRAL AND SOUTH WEST CORPORATION
In May 1993, the Company entered into the Merger Agreement, pursuant
to which the Company would have been acquired by CSW. In June 1995, CSW
terminated the Merger Agreement. In response, the Company filed a complaint
against CSW in the 205th Judicial District Court of El Paso County, Texas,
alleging, among other claims, breach of contract, breach of duty of good faith
and fair dealing, breach of fiduciary duty, business disparagement, tortious
interference with contract and fraud in the inducement. The Company sought an
unspecified amount of damages, punitive damages, attorneys' fees and costs. In
June 1995, CSW filed an adversary proceeding against the Company in the
Bankruptcy Court seeking the recovery of termination fees of $25 million,
approximately $3.7 million in attorneys' fees and expenses that CSW claims it
advanced on behalf of the Company in certain regulatory proceedings, and $25
million for the alleged violation of the Merger Agreement's no-solicitation
provisions. All of the claims by both parties were tried in the Bankruptcy
Court. The trial concluded on January 30, 1997, and the matter has been taken
under advisement by the presiding judge. A ruling is expected in March 1997. The
Company cannot predict the outcome of this litigation. Pursuant to the terms of
the Reorganization, the first $20 million in proceeds, if any, to the Company
from this litigation will be distributed to the holders of preferred stock and
common stock of the Predecessor Company.
LITIGATION WITH LAS CRUCES
In the franchise fee action, Las Cruces is attempting to replace the
Company as its electric service provider by acquiring, through condemnation or
otherwise, the distribution assets and other facilities used to provide electric
service to customers in Las Cruces. Sales to customers in Las Cruces represented
approximately 7% of the Company's operating revenues in 1996. Las Cruces has two
actions pending against the Company in federal district court in New Mexico, one
seeking to recover franchise fees despite the expiration of the Company's Las
Cruces franchise in March 1994 and one seeking a declaratory judgment that Las
Cruces can proceed with a condemnation action against the Company. In addition,
the New Mexico State Legislature has recently passed a bill that would allow Las
Cruces to proceed with the condemnation.
Las Cruces is seeking the reasonable value of the Company's use, occupation
and rental of Las Cruces' rights-of-way or damages for trespass and an
unspecified amount of punitive damages. The Company has filed an answer denying
that it has any liability or continuing payment obligation to Las Cruces
regarding franchise fees or use of the Las Cruces rights-of-way, and also denies
that it has committed any trespass. The Company intends to vigorously defend the
lawsuit. The Company has also filed a counterclaim seeking to condemn, pursuant
to statutory authority, those Las Cruces rights-of-way currently used and
occupied by the Company. Las Cruces has filed an answer contesting the Company's
right to proceed with such a condemnation. In August 1996, the court severed the
Company's counterclaim from
20
Las Cruces' claims for all purposes, and stayed all proceedings on the Company's
counterclaim until further order of the court. The trial of Las Cruces' claims
is set for May 1997. The Company has reserved in its financial statements an
amount equal to the franchise fees under the expired agreement.
In April 1995, Las Cruces filed a Complaint for Declaratory Judgment
against the Company in the District Court for Dona Ana County, New Mexico,
seeking a declaratory judgment that Las Cruces has a right of eminent domain to
condemn the electric distribution system and related facilities owned and
operated by the Company within and adjacent to the city limits that provide or
assist in the provision of electricity within the municipal boundaries of Las
Cruces. In May 1995, the Company removed the case to the United States District
Court for the District of New Mexico. In October 1995, the Company's motion for
summary judgment was denied and the Court ruled that although Las Cruces lacks
express statutory authority to condemn the Company's assets, such express
authority is required only if the proposed condemnation would materially impair,
obliterate or destroy the existing use. Following a trial on the merits, the
federal magistrate issued an opinion holding that Las Cruces had not met its
burden of proof that its plan would not materially impair the public use of the
Company's property sought to be condemned. The magistrate also granted the
Company's motion to certify to the New Mexico Supreme Court the question as to
whether Las Cruces possesses the authority to condemn the Company's property for
use as a municipal utility when that property is already devoted to public use.
In February 1997, the New Mexico Supreme Court heard oral arguments and is
expected to issue its ruling in the near future.
In March 1997, the New Mexico House of Representatives and Senate passed a
bill that would give Las Cruces the authority to acquire and operate the
Company's distribution system within both the city limits and a territory within
five miles of the municipal boundary. If the Governor signs the bill, it would
become law immediately and most likely make the issues presented to the New
Mexico Supreme Court moot.
Las Cruces has taken several actions to position itself to acquire portions
of the Company's distribution system and certain related facilities in the event
it can proceed with condemnation. See Item 1, "Business - Regulation - Federal
Regulatory Matters" for discussion regarding Las Cruces' filing with the FERC
for determination of stranded cost. In June 1994, the Las Cruces City Council
approved a resolution selecting SPS to provide operation and maintenance
services for the proposed Las Cruces electric distribution system, substations
and associated transmission facilities and authorizing the staff of Las Cruces
to negotiate a contract with SPS related to such services. In August 1994, SPS
and Las Cruces entered into a fifteen-year contract granting SPS the right to
provide all of the electric power and energy required by Las Cruces during the
term of the contract. In addition, Las Cruces announced that, in October 1995,
it sold approximately $73 million in revenue bonds to provide funding to finance
the acquisition by condemnation or negotiated purchase of the Company's
electrical distribution assets within and adjacent to the Las Cruces city
limits.
The Company has filed a lawsuit in the Dona Ana County District Court and
is pursuing a complaint simultaneously before the New Mexico Commission
challenging the legality of the sale of the revenue bonds, and the New Mexico
Commission is investigating the agreement between SPS and Las Cruces which would
grant, in certain circumstances, Las Cruces an option to sell electric utility
assets acquired through condemnation to SPS. In August 1996, the Dona Ana County
District Court issued an opinion letter stating that Section 3-23-3 of the New
Mexico Municipal Code is inapplicable to home rule municipalities and Las
Cruces, therefore, was not required to acquire the New Mexico Commission's
approval before issuing revenue bonds to acquire utility property. However, the
Court did agree with the Company that the revenue bonds, in this case backed by
utility revenues, are subject to the same requirements of other revenue bonds
backed by gross receipts tax revenues. Therefore, if the Court's finding of the
applicability of Las Cruces' home rule authority is overturned on appeal, the
Company's position that the issuance of the bonds required prior approval could
be upheld. The Court's order was signed and entered in November 1996. The
Company has filed an appeal with the New Mexico Court of Appeals.
21
The Company continues to believe that it can provide lower cost electric
service to customers in Las Cruces than can be achieved through a municipal
takeover. Accordingly, the Company has stated its strong preference for a
resolution of its differences with Las Cruces through negotiation rather than
litigation and condemnation. The Company intends to vigorously pursue before the
FERC its right to recover stranded costs from Las Cruces in the event Las Cruces
succeeds in leaving the system.
If Las Cruces succeeds in its efforts to condemn the Company's distribution
system, the Company could lose its Las Cruces customer base, although the
Company would receive "just compensation" as established by the court under New
Mexico law. "Just compensation" is generally defined as the amount of money that
would compensate the party whose property is condemned. In the Company's case,
this amount would be the difference between the value of the Company's entire
system prior to the taking, as compared to the value of the entire system after
the taking. The Company is unable to predict the outcome of Las Cruces' efforts
or the effects it may have on the Company's financial position, results of
operations and cash flows.
TRANSMISSION SERVICE TO MEXICO
In September 1996, Enron, a wholesale power marketer and one of the
companies that submitted a bid to the CFE in connection with renewal of the
interchange agreement for the supply of power to Ciudad Juarez, Mexico, filed a
complaint against the Company with the FERC. Enron's complaint sought emergency
relief and requested the FERC to direct the Company to enter into an agreement
with Enron to provide Enron with firm point-to-point transmission service to the
CFE under its open access transmission tariff.
In October 1996, the FERC issued an order requiring the Company to provide
Enron with firm point-to-point transmission service over the Company's
transmission system to substation facilities near the border. The FERC, however,
concurred with the Company's position that the FERC does not have jurisdiction
to order transmission across the border, suggesting that the DOE has such
jurisdiction. Pursuant to an emergency application filed by Enron with the DOE,
on October 30, 1996, the DOE issued a Notice of Delegation and Assignment which
delegated to the FERC its authority to carry out the DOE's duties in this case.
In its response to the DOE's delegation of authority, the Company has asserted
that the DOE has no authority to require transmission access for delivery of
power to the CFE. However, the Company agreed to provide access, to the extent
transmission capacity is available, to a winning bidder in 1997, if the winning
bidder is someone other than the Company, pending resolution of this
jurisdictional dispute. The Company's agreement to provide such access in no way
prejudices the Company's position that, under current law, access is not
required. The FERC has docketed the Delegation and Assignment and the process is
expected to continue throughout 1997.
WATER CASES
San Juan River System. The Four Corners Participants are among the
defendants in a suit filed by the State of New Mexico in 1975 in state district
court in New Mexico against the United States of America, the City of
Farmington, New Mexico, the Secretary of the Interior as Trustee for the Navajo
Nation and other Indian tribes and certain other defendants (State of New Mexico
ex rel. S. E. Reynolds, New Mexico State Engineer v. United States of America,
et al., Eleventh Judicial District Court, County of San Juan, State of New
22
Mexico, Cause No. 75-184). The suit seeks adjudication of the water rights of
the San Juan River Stream System in New Mexico, which, among other things,
supplies the water used at Four Corners. The case has been inactive for many
years. The Company cannot predict the outcome of this case.
Gila River System. In connection with the construction and operation
of Palo Verde, APS entered into contracts with certain municipalities granting
APS the right to purchase effluent for cooling purposes at Palo Verde. In 1986,
a summons was served on APS that required all water claimants in the Lower Gila
River Watershed in Arizona to assert any claims to water in an action pending in
Maricopa County Superior Court, titled In re The General Adjudication of All
Rights to Use Water in the Gila River System and Source. Palo Verde is located
within the geographic area subject to the summons and the rights of the Palo
Verde Participants to the use of groundwater and effluent at Palo Verde is
potentially at issue in the action. APS, as operating agent, filed claims that
dispute the court's jurisdiction over the Palo Verde Participants' groundwater
rights and their contractual rights to effluent relating to Palo Verde and,
alternatively, seek confirmation of such rights. In December 1992, the Arizona
Supreme Court heard oral argument on certain issues in this matter that are
pending on interlocutory appeal. Issues important to Palo Verde Participants'
claims were remanded to the trial court for further action and the trial court
certified its decision for interlocutory appeal to the Arizona Supreme Court.
In September 1994, the Arizona Supreme Court granted review of the June 1994
trial court decision. No trial date has been set in the matter. The Company
cannot predict the outcome of this case.
FOUR CORNERS
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the
Navajo Nation Pesticide Act (collectively, the "Acts"). In October 1995, the
Four Corners Participants requested that the United States Secretary of the
Interior resolve their dispute with the Navajo Nation regarding whether the Acts
apply to operation of Four Corners. The Four Corners Participants subsequently
filed a lawsuit in the District Court of the Navajo Nation, Window Rock
District, seeking, among other things, a declaratory judgment that (i) the Four
Corners leases and federal easements preclude the application of the Acts to the
operation of Four Corners; and (ii) the Navajo Nation and its agencies and
courts lack adjudicatory jurisdiction to determine the enforceability of the
Acts as applied to Four Corners. On October 18, 1995, the Navajo Nation and the
Four Corners Participants agreed to indefinitely stay the proceedings referenced
above so that the parties may attempt to resolve the dispute without litigation.
The Company is unable to predict the outcome of this matter.
OTHER LEGAL PROCEEDINGS
The Company is a party to various other claims, legal actions and
complaints. In many of these matters, the Company has excess casualty liability
insurance which is applicable. Based upon a review of these claims and
applicable insurance coverage, management is of the opinion that none of these
claims will have a material adverse effect on the operations or financial
position of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On November 14, 1996, the Company held a Special Shareholders Meeting to
approve the Company's 1996 Long-Term Incentive Plan, which authorized the
issuance of up to 3,500,000 shares of common stock for the benefit of officers,
key employees and non-employee directors through the award or grant of non-
statutory stock options, incentive stock options, stock appreciation rights,
restricted stock, bonus
23
stock and performance stock. The total number of common shares outstanding at
this Special Meeting was 59,999,981, of which 46,078,152 were represented in
person or by proxy. Shares voted in favor of approving the plan were
38,325,050, and shares voted against were 7,308,727. There were 444,375
abstentions. Broker non-votes were not included in the determination of the
number of shares represented at the meeting for purposes of determining whether
a quorum was present and were not counted for purposes of determining whether
the proposal had been approved. See Part II, Item 8, "Financial Statements and
Supplementary Data - Note F of Notes to Financial Statements."
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock began trading on the American Stock Exchange on
February 16, 1996 under the symbol "EE." The high and low sales prices for the
Company's Common Stock, as reported in the consolidated reporting system of the
American Stock Exchange, for the periods indicated below, were as follows:
SALES PRICE
---------------
HIGH LOW
------ ------
1996
----
February 16 - March 31 $ 6 1/4 $ 4 3/4
Second Quarter 6 1/8 5
Third Quarter 6 1/8 5 1/4
Fourth Quarter 6 5/8 4 15/16
At March 20, 1997, there were 11,847 record holders of the Company's Common
Stock.
The Company's ability to pay dividends on the Common Stock for the next
several years will be limited by applicable law and, as explained below, by the
financing arrangements entered into pursuant to the Reorganization. All
distributions with respect to the Common Stock, including the declaration or
payment of dividends, are subject to the provisions of the Texas Business
Corporation Act, including provisions that prohibit any distribution that
exceeds the surplus of the Company. In addition, under Section 305 of the FPA,
it is unlawful for a director or officer of the Company to participate in the
making or payment of dividends from "any funds properly included in capital
account." As a result of Reorganization, the Company's first priority at this
time is debt retirement and deleveraging as opposed to paying dividends.
Pursuant to the resolutions creating the Company's Series A Preferred
Stock, no dividends can be paid on the Common Stock if there are dividends in
arrears on the Series A Preferred Stock. So long as the Company's First
Mortgage Bonds, Series A through H, are outstanding and the series with the
longest maturity is not rated "investment grade" by either Standard & Poor's
Rating Service or Moody's Investors Service, Inc., the Company may not declare
any dividend on the Common Stock, other than in additional shares of Common
Stock, or make any other distribution on, or acquire for value any shares of
Common Stock (with certain limited exceptions) unless, after giving effect
thereto, the aggregate of all such dividends, distributions and certain other
payments made by the Company since February 12, 1996 would be less than the sum
of (i) 50% of the consolidated net income (as defined in the mortgage indenture)
of the Company minus dividends paid in respect of the Series A Preferred Stock
for the period from February 13, 1996 to the most recently ended fiscal quarter
for which quarterly financial statements are available (or, if such consolidated
net income is a deficit, less 100% of such deficit), plus (ii) 100% of the
aggregate net proceeds received by the Company from the issuance or sale since
February 12, 1996 of equity securities or debt securities that have been
converted into equity securities, plus (iii) $10.0 million. Currently, the
Company's First Mortgage Bonds are not rated investment grade.
Pursuant to the terms of the reimbursement agreements related to four
letters of credit issued in respect to the four series of pollution control
revenue bonds, so long as a drawing is available under any of
25
the letters of credit, the same limitation on the declaration of dividends would
apply to the Company. In addition to the restriction contained in the mortgage
indenture, the reimbursement agreements limit to $15.0 million the aggregate
amount of dividends that can be paid on the Common Stock during the three years
after its initial issuance on February 12, 1996. The credit agreement for the
working capital and fuel financing facility contains the same limitations on the
payment of Common Stock dividends as the reimbursement agreements related to the
letters of credit on the pollution control revenue bonds.
26
ITEM 6. SELECTED FINANCIAL DATA
As of and for the following periods:
REORGANIZED
COMPANY PREDECESSOR COMPANY
----------- | --------------------------------------------------------------------
|
PERIOD FROM | PERIOD FROM
FEBRUARY 12 | JANUARY 1
TO | TO
DECEMBER 31, | FEBRUARY 11, YEARS ENDED DECEMBER 31,
| ------------------------------------------------------
|
1996 | 1996 1995 1994 1993 1992
------------ | ------------ ------------ ------------ ------------ ------------
|
| (IN THOUSANDS EXCEPT FOR SHARE DATA)
|
Operating revenues............................... $ 523,974 | $ 54,949 $ 504,617 $ 536,760 $ 543,594 $ 524,760
Operating income................................. 120,787 | 5,089 66,146 73,011 64,971 67,036
Income (loss) before extraordinary gain on |
discharge of debt and cumulative effect of a |
change in accounting principle................. 41,919 | 118,198 (33,319) (28,153) (41,855) (28,180)
|
Extraordinary gain on discharge of debt.......... - | 264,273 - - - -
Cumulative effect of a change in |
accounting principle........................... - | - - - (96,044)(1) -
Net income (loss) applicable to common stock.... 31,431 | 382,471 (33,319) (28,153) (137,899) (28,180)
|
Net income (loss) per common share: |
Income (loss) before extraordinary gain |
on discharge of debt and cumulative |
effect of a change in accounting principle. 0.52 | 3.33 (0.94) (0.79) (1.18) (0.79)
|
Extraordinary gain on discharge of debt...... - | 7.43 - - - -
Cumulative effect of a change |
in accounting principle.................... - | - - - (2.70)(1) -
Net income (loss) per common share........... 0.52 | 10.76 (0.94) (0.79) (3.88) (0.79)
|
Weighted average number of common shares and |
common share equivalents outstanding........... 60,181,494 | 35,544,330 35,544,330 35,544,330 35,539,480 35,530,264
Total assets..................................... 1,846,190 | 1,910,354 1,809,891 1,730,851 1,715,406 1,702,778
Additions to utility plant....................... 53,018 | 8,231 88,267 60,113 58,215 60,570
Long-term debt, financing and capital lease |
obligations.................................... 1,046,173 | 1,164,328 - - - -
Debt and obligations subject to compromise....... - | - 1,608,091 1,537,303 1,495,315 1,440,968
Preferred stock.................................. 108,426 | 100,000 81,464 81,464 81,464 81,464
Common stock equity (deficit).................... 331,257 | 300,000 (418,763) (385,966) (357,463) (220,508)
|
=========== | =========== =========== =========== =========== ===========
______________________
(1) Reflects the change in accounting for income taxes due to the
implementation of SFAS No. 109, "Accounting for Income Taxes" ("SFAS No.
109").
The selected financial data should be read in conjunction with Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," and Item 8, "Financial Statements and Supplementary Data," below.
27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Statements in this document, other than statements of historical
information, are forward-looking statements that are made pursuant to the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995 (the
"1995 Act"). Such forward-looking statements, as well as other oral and written
forward-looking statements made by or on behalf of the Company from time to
time, including statements contained in the Company's filings with the
Securities and Exchange Commission and its reports to stockholders, involve
known and unknown risks and other factors which may cause the Company's actual
results in future periods to differ materially from those expressed in any
forward-looking statements. Any such statement is qualified by reference to the
risks and factors discussed below under the headings "Operational Prospects and
Challenges" and "Liquidity and Capital Resources" and in the Company's filings
with the Securities and Exchange Commission, which are available from the
Securities and Exchange Commission or which may be obtained upon request from
the Company. The Company cautions that the foregoing list of important factors
is not exclusive. The Company does not undertake to update any forward-looking
statement that may be made from time to time by or on behalf of the Company.
OPERATIONAL PROSPECTS AND CHALLENGES
While the Company prepares for a new era of deregulation and competition in
the electric utility industry, the Rate Stipulation provides a certain level of
stability in the rates that the Company currently charges the majority of its
customers. The Company intends to enhance its position during the Freeze Period
by (i) serving the growing need for electricity within its retail service
territory; (ii) continuing to focus on its strategic location on the border with
Mexico; (iii) executing long-term contracts to provide electricity to its
largest retail customers; and (iv) implementing operating cost reduction
programs.
The Company faces a number of challenges which could negatively impact its
operations during the Freeze Period. The primary challenge is the risk of
increased costs, including the risk of additional or unanticipated costs, at
Palo Verde resulting from (i) increases in operation and maintenance expenses;
(ii) the potential replacement of steam generators; (iii) an extended outage of
any of the Palo Verde units; (iv) increases in estimates of decommissioning
costs; (v) the storage of radioactive materials; and (vi) compliance with the
various requirements and regulations governing commercial nuclear generating
stations. There can be no assurance that the Company's revenues will be
sufficient to recover any increased costs incurred during the Freeze Period,
including any such increased costs in connection with Palo Verde or increases in
other costs of operation, whether as a result of higher than anticipated levels
of inflation, changes in tax laws or regulatory requirements, or other causes.
In recent months, rapid escalation in fuel prices have increased concern
over price levels for energy, including electricity. The Company's recovery of
fuel expense is subject to challenges regarding reasonableness and prudence
through periodic fuel reconciliation proceedings. See Part I, Item 1, "Business
- - Regulation - Texas Rate Matters - Fuel" and "- Regulation - New Mexico Rate
Matters - Fuel."
Another risk to the Company's operations is the potential loss of
customers. The Company's wholesale and large retail customers currently have,
in varying degrees, and, in the future may have, additional alternate sources of
economical power, including co-generation of electric power. If the Company
loses a significant portion of its retail customer base or wholesale sales, the
Company may not be able to replace such revenues through either the addition of
new customers or an increase in rates to remaining customers. Las Cruces has
begun litigation and the New Mexico State Legislature has passed
28
legislation which, if signed by the Governor, would give Las Cruces the legal
authority to condemn the Company's distribution system and related assets
located within its city limits. If Las Cruces succeeds in its efforts, the
Company could lose its Las Cruces customer base, although the Company would
receive "just compensation" as established by the court. See Item 8,
"Financial Statements and Supplementary Data - Note K of Notes to Financial
Statements." Further, there are state and federal legislative initiatives
related to deregulation which could affect Company operations.
In recent years, the United States has closed a large number of military
bases and there can be no assurance that Holloman Air Force Base ("Holloman"),
White Sands Missile Range ("White Sands") or the United States Army Air Defense
Center at Fort Bliss ("Ft. Bliss") will not be closed in the future or that the
Company will not lose all or some of its military base sales. The Company's
sales to the military bases represented approximately $20.0 million or 3% of
operating revenues for the year ended December 31, 1996. The Company signed a
new contract with Ft. Bliss in August 1996, which provides that Ft. Bliss will
take service from the Company through 1999, with the right thereafter to
continue service on a year to year basis for two years. The Company has a
contract for service to Holloman for a ten-year term beginning in December 1995.
In August 1996, the Army advised the Company that White Sands would continue to
purchase retail electric service from the Company pursuant to the retail service
contract which was set to expire on December 31, 1993, but which had previously
been unilaterally extended by the Army for an indefinite period, until written
termination of such contract by the Army not less than one year in advance of
the termination date.
The Company does not currently have an agreement with New Mexico regulatory
authorities or parties to past New Mexico regulatory proceedings comparable to
the Rate Stipulation. Pursuant to an order from the New Mexico Commission, the
Company filed rate data with the Commission on March 3, 1997. Although the
Company's filing demonstrates a revenue deficiency of approximately $8.6 million
under current rates, the Company did not request a rate change to recover the
deficiency. The Company cannot predict what action the New Mexico Commission
may take in this proceeding.
Finally, the electric utility industry in general is facing significant
challenges and increased competition as a result of changes in federal
provisions relating to third-party transmission services and independent power
production, as well as potential changes in state regulatory provisions relating
to wholesale and retail service. Both the Texas and New Mexico Commissions are
conducting proceedings related to industry restructuring and stranded cost
recovery. See Part I, Item 1, "Business - Regulation - Recent Changes in
Utility Regulation." The Company cannot predict the outcome of these
proceedings. The potential effects of deregulation are particularly important to
the Company because its rates are significantly higher than the national and
regional averages. In the face of increased competition, there can be no
assurance that such competition will not adversely affect the future operations,
cash flow and financial condition of the Company.
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal liquidity requirements through the end of the
decade are expected to consist of the payment of interest on the Company's
indebtedness and capital expenditures related to the Company's generating
facilities and transmission and distribution systems. The Company expects that
cash flows from operations will be sufficient for such purposes.
29
Long-term capital requirements of the Company will consist primarily of
maintenance and construction of electric utility plant, payment of interest on
and retirement of debt and payment of dividends on and redemption of preferred
stock. The Company has no current plans to construct any new generating
capacity through at least 2004. Utility construction expenditures will consist
primarily of expanding and updating the transmission and dist