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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, 1999
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 incorporation or organization) (I.R.S. Employer Identification No.)
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
------------------- -----------------------------------------
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 10, 2000, the aggregate market value of the voting stock
held by non-affiliates of the registrant was $522,578,682.
As of March 10, 2000, there were 54,778,810 shares of the Company's common
stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for the 2000 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 Texas Rate Stipulation
ANPP Participation Agreement.............. Arizona Nuclear Power Project Participation Agreement dated August 23,
1973, as amended
APS....................................... Arizona Public Service Company
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
Company................................... El Paso Electric Company
DOE....................................... United States Department of Energy
DSM....................................... Demand-Side Management
ESBG...................................... The Company's Energy Services Business Group
FERC...................................... Federal Energy Regulatory Commission
Four Corners.............................. Four Corners Generating Station
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 Texas Rate Stipulation
IID....................................... Imperial Irrigation District, an irrigation district in southern
California
IRP....................................... Integrated Resource Plan
kV........................................ Kilovolt(s)
kW........................................ Kilowatt(s)
kWh....................................... Kilowatt-hour(s)
Las Cruces................................ City of Las Cruces, New Mexico
MW........................................ Megawatt(s)
MWh....................................... Megawatt-hour(s)
New Mexico Commission..................... New Mexico Public Utility Commission or its successor, New Mexico
Public Regulation Commission
New Mexico Restructuring Law.............. New Mexico Electric Utility Industry Restructuring Act of 1999
New Mexico Settlement Agreement........... Stipulation and Settlement Agreement in Case No. 2722, between the
Company, the New Mexico Attorney General, the New Mexico Commission
staff and most other parties to the Company's rate proceedings,
excluding Las Cruces, before the New Mexico Commission providing for
a 30-month moratorium on rate increases or decreases and other
matters
NRC....................................... Nuclear Regulatory Commission
OPC....................................... Texas Office of Public Utility Counsel
Palo Verde................................ Palo Verde Nuclear Generating Station
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
PNM....................................... Public Service Company of New Mexico
SFAS...................................... Statement of Financial Accounting Standards
SPS....................................... Southwestern Public Service Company
TEP....................................... Tucson Electric Power Company
Texas Commission.......................... Public Utility Commission of Texas
Texas Rate Stipulation.................... Stipulation and Settlement Agreement in Texas Docket 12700, between the
Company, the City of El Paso, the 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
Texas Restructuring Law................... Texas Public Utility Regulatory Act Chapter 39, Restructuring of the
Electric Utility Industry
Texas Settlement Agreement................ Settlement Agreement in Texas Docket 20450, between the Company, the
City of El Paso and various parties providing for a reduction of the
Company's jurisdictional base revenue and other matters
TNP....................................... Texas-New Mexico Power Company
(i)
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.............. 22
PART II
5 Market for Registrant's Common Equity and Related Stockholder
Matters....................................................... 23
6 Selected Financial Data.......................................... 25
7 Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 26
7A Quantitative and Qualitative Disclosures About Market Risk....... 33
8 Financial Statements and Supplementary Data...................... 35
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure....................................... 77
PART III
10 Directors and Executive Officers of the Registrant............... 77
11 Executive Compensation........................................... 77
12 Security Ownership of Certain Beneficial Owners and Management... 77
13 Certain Relationships and Related Transactions................... 77
PART IV
14 Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 77
(ii)
PART I
Item 1. Business
General
El Paso Electric 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 MW. For the
year ended December 31, 1999, the Company's energy sources consisted of
approximately 55% nuclear fuel, 33% natural gas, 8% coal and 4% purchased power.
The Company serves approximately 298,000 residential, commercial,
industrial and wholesale customers. The Company distributes electricity to
retail customers principally in El Paso, Texas and Las Cruces, New Mexico
(representing approximately 58% and 8%, respectively, of the Company's revenues
for the year ended December 31, 1999). In addition, the Company sells
electricity to wholesale customers, including Texas-New Mexico Power Company and
the Imperial Irrigation District. Through 1998, the Company also made wholesale
sales to the Comision Federal de Electricidad de 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 Energy Services Business Group began developing energy
efficient products and services in 1997. The ESBG offers customers value-added
products and services that give them greater value for the kWh purchased from
the Company.
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 February 25, 2000, the Company had
approximately 1,000 employees, 30% of whom are covered by a collective
bargaining agreement. The collective bargaining agreement between the Company
and the International Brotherhood of Electrical Workers Local 960 ("Local 960")
expires on June 15, 2000. Local 960 represents approximately 300 of the
Company's employees working primarily in the power plants, substations and line
crews. The parties will exchange proposals as early as April 15, 2000 and will
begin contract negotiations in May 2000. The Company cannot predict the outcome
of these negotiations.
Facilities
The Company's net installed generating capacity of approximately 1,500 MW
consists of approximately 600 MW from Palo Verde Units 1, 2 and 3, 482 MW from
its Newman Power Station, 246 MW from its Rio Grande Power Station, 104 MW from
Four Corners Units 4 and 5, and 68 MW from its Copper Power Station.
1
Palo Verde Station
The Company owns a 15.8% interest in each of the three nuclear generating
units and Common Facilities at Palo Verde, located west of Phoenix, Arizona. The
Palo Verde Participants include the Company and six other utilities: APS,
Southern California Edison Company, PNM, Southern California Public Power
Authority, Salt River Project Agricultural Improvement and Power District 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 Palo Verde Units 1, 2 and 3, which expire in 2024, 2025 and 2027,
respectively. 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 participant is required
to fund its proportionate share of fuel, other operations, maintenance and
capital costs. The Company's total monthly share of these costs was
approximately $6.9 million in 1999. 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 and federal
law, the Company must fund its share of the estimated costs to decommission Palo
Verde Units 1, 2 and 3, including the Common Facilities, over their estimated
useful lives of 40 years (to 2024, 2025 and 2027, respectively). The Company's
funding requirements are determined periodically based upon engineering cost
estimates performed by outside engineers retained by APS.
In December 1998, the Palo Verde Participants approved an updated
decommissioning study. The 1998 study determined that the Company will have to
fund approximately $280.5 million (stated in 1998 dollars) to cover its share of
decommissioning costs. Cost estimates for decommissioning have increased with
each study. The previous cost estimate from a 1995 study determined that the
Company would have to fund approximately $229 million (stated in 1995 dollars).
The 1998 estimate reflects a 22% increase from the 1995 estimate primarily due
to increases in estimated costs for spent fuel storage after operations have
ceased. See "Spent Fuel Storage" below.
Although the 1998 study was 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 are subject to significant uncertainty. The decommissioning study is
updated every three years and a new study is expected to be completed in 2001.
See "Disposal of Low-Level Radioactive Waste" below.
The Company will recover its current decommissioning cost estimates through
its existing rates during the Freeze Period, and thereafter under the provisions
of the Texas Restructuring Law. The rate freeze under the Texas Rate Stipulation
and the rate reduction under the Texas Settlement Agreement preclude the Company
from seeking a rate increase in Texas to recover increases in decommissioning
cost estimates during the Freeze Period. See "Regulation - Texas Regulatory
Matters - Deregulation" for further discussion.
2
Prior to the start of competition in New Mexico, the Company will continue
to collect 100% of its decommissioning cost estimates under the New Mexico
Settlement Agreement. Under the New Mexico Restructuring Law, however, the New
Mexico Commission could effectively reduce the Company's recovery of its
decommissioning costs. See " Regulation - New Mexico Regulatory Matters -
Deregulation" for further discussion.
Steam Generators. Palo Verde has experienced degradation in the steam
generator tubes of each unit. 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.
The projected service lives of the units' steam generators are reassessed
by APS periodically in conjunction with inspections made during scheduled
outages of the Palo Verde units. In 1997, the Palo Verde Participants
unanimously approved the purchase of one set of spare steam generators for
delivery in September 2002. In December 1999, the Palo Verde Participants
unanimously approved installation of the new steam generators in Unit 2. The
Company's portion of total costs associated with construction and installation
of new steam generators in Unit 2, including replacement power costs, is
currently estimated not to exceed $44 million. APS has also stated that, based
on the latest available data, it estimates that the steam generators in Units 1
and 3 should operate for their designated lives of 40 years. However, APS is
reassessing whether it is economically desirable to replace the steam generators
in Units 1 and 3. Such replacements would also require the unanimous approval
of the Palo Verde Participants.
The Texas Rate Stipulation precludes the Company from seeking a rate
increase during the Freeze Period to recover additional capital costs associated
with the replacement of steam generators. The Company cannot recover these costs
through regulated rates in New Mexico since generation and power supply are
currently scheduled to become a competitive function in January 2001 under the
New Mexico Restructuring Law. Finally, the Company cannot assure that it will
be able to recover these capital costs through its wholesale power rates or its
competitive retail rates that become applicable after the start of competition.
See also Part II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Overview."
Spent Fuel Storage. In June 1999, APS requested approval from the NRC to
use more of the space in the existing spent fuel storage facilities at Palo
Verde. The NRC approved this request on March 2, 2000. As a result, the spent
fuel storage facilities will have sufficient capacity to store all fuel expected
to be discharged from normal operation of all three Palo Verde units through
2003. Alternative on-site storage facilities are currently being constructed to
supplement existing facilities. Spent fuel will be removed from the original
facilities as necessary and placed in special storage casks which will be stored
at the new facilities until accepted by the DOE for permanent disposal. The
alternative facilities will be built in stages to accommodate casks on an as
needed basis and are expected to be available for use by the end of 2002.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the
"Waste Act"), the DOE is legally obligated to accept and dispose of all spent
nuclear fuel and other high-level radioactive wastes generated by all domestic
power reactors. In accordance with the Waste Act, the DOE entered into a spent
nuclear fuel contract with the Company and all other Palo Verde Participants. In
3
November 1989, the DOE reported that its spent nuclear fuel disposal facilities
would not be in operation until 2010. Subsequent judicial decisions required the
DOE to start accepting spent nuclear fuel by January 31, 1998. The DOE did not
meet that deadline, and the Company cannot currently predict when spent fuel
shipments to the DOE's permanent disposal site will commence. The 1998
decommissioning study assumes that only 14 of 333 spent fuel casks will have
been removed from Palo Verde by 2037 when title to the remaining spent fuel is
assumed to be transferred to the DOE. In January 1997, the Texas Commission
established a project to evaluate what, if any, action it should take with
regard to payments made to the DOE for funding of the DOE's obligation to start
accepting spent nuclear fuel by January 31, 1998. After receiving initial
comments, no further action has been taken on the project.
In July 1998, APS filed, on behalf of all Palo Verde Participants, a
petition for review with the United States Court of Appeals for the District of
Columbia Circuit seeking confirmation that findings by the Circuit Court in a
prior case brought by Northern States Power regarding the DOE's failure to
comply with its obligation to begin accepting spent nuclear fuel would apply to
all spent nuclear fuel contract holders. The Circuit Court held APS' petition
in abeyance pending the United States Supreme Court's decision to review the
Northern States Power case. In November 1998, the Supreme Court denied review
of this case. The Circuit Court subsequently dismissed APS' petition after the
Circuit Court issued clarifying orders essentially granting the relief sought by
APS. APS is monitoring pending litigation between the DOE and other nuclear
operators before initiating further legal proceedings or other procedural
measures on behalf of the Palo Verde Participants to enforce the DOE's statutory
and contractual obligations. The Company is unable to predict the outcome of
these matters at this time.
The Company expects to incur significant spent fuel storage costs during
the life of Palo Verde that it believes are the responsibility of the DOE.
These costs will be expensed as incurred until an agreement is reached with the
DOE for recovery of these costs. However, the Company cannot predict when, if
ever, these additional costs will be recovered from the DOE.
Disposal of Low-Level Radioactive Waste. Congress has established
requirements for the disposal by each state of low-level radioactive waste
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. Palo Verde is projected to undergo decommissioning during the period in
which Arizona will act as host for the Southwestern Compact. However, the
opposition, delays, uncertainty and costs experienced in California demonstrate
possible roadblocks that may be encountered 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 under federal law. The insurance consists of $200 million of primary
liability insurance provided by commercial insurance carriers, with the balance
being provided by an industry-wide retrospective assessment program, pursuant to
which industry participants would be required to pay an assessment to cover any
loss in excess of $200 million. Effective August 1998, the maximum assessment
per reactor for each nuclear incident is approximately $90.7 million, subject to
an annual limit of $10 million per incident. Based upon the Company's 15.8%
4
interest in Palo Verde, the Company's maximum potential assessment per incident
is approximately $43.0 million for all three units with an annual payment
limitation of approximately $4.7 million.
The Palo Verde Participants maintain "all risk" (including nuclear hazards)
insurance for damage to, and decontamination of, property at Palo Verde in the
aggregate amount of $2.75 billion, a substantial portion of which must first be
applied to stabilization and decontamination. Finally, the Company has obtained
insurance against a portion of any increased cost of generation or purchased
power which may result from an accidental outage of any of the three Palo Verde
units if the outage exceeds 12 weeks.
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 can also operate 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 can also operate on fuel oil.
Four Corners Station
The Company owns 7% of 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 on 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 can also operate on fuel oil. The
Company leases the combustion turbine and other generation equipment at the
station under a lease that expires in July 2005, with an extension option for
two additional years.
Transmission and Distribution Lines and Agreements
The Company owns or has significant ownership interests in four major 345
kV transmission lines, three 500 kV lines in Arizona, 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
5
generation sources at Palo Verde and Four Corners. Pursuant to standards
established by the North American Electric Reliability Council, the Company
operates its transmission system in a way that allows it to maintain complete
system integrity in the event of any one of these transmission lines being out
of service.
Springerville-Diablo Line. The Company owns a 310-mile, 345 kV
transmission line from TEP's 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 primary
delivery point for the Company's generation entitlement from Four Corners, which
is transmitted to the West Mesa Substation over approximately 150 miles of
transmission lines owned by PNM.
Greenlee-Newman Line. As a participant in the Southwest New Mexico
Transmission Project Participation Agreement, the Company owns 40% of a 60-mile,
345 kV transmission line from TEP's Greenlee Substation in Arizona to the
Hidalgo Substation near Lordsburg, New Mexico, 57.2% of a 50-mile, 345 kV
transmission line between the Hidalgo Substation and the Luna Substation near
Deming, New Mexico, and 100% of an 86-mile, 345 kV transmission line between the
Luna Substation and the Newman Power Station. These lines provide 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 66.7% of 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 SPS, providing the Company with
access to emergency power from SPS and power markets to the east.
Palo Verde Transmission. The Company owns 18.7% of two 45-mile, 500 kV
lines from Palo Verde to the Westwing Substation and a 75-mile, 500 kV line from
Palo Verde to the Kyrene Substation. These lines provide the Company with a
transmission path for delivery of power from Palo Verde.
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. Substantial
expenditures may be required to comply with these 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, unforeseen expenses
associated with compliance could have a material adverse effect on the future
operations and financial condition of the Company.
6
Construction Program
The Company has no current plans to construct any new generating facilities
to serve retail customers through at least 2004. Utility construction
expenditures reflected in the following table consist primarily of expanding and
updating the electric transmission and distribution systems, and the cost of
improvements at and the purchase and installation of new steam generators for
Palo Verde. The Company's estimated cash construction costs for 2000 through
2003 are approximately $252 million. Actual costs may vary from the construction
program estimates shown. Such estimates are reviewed and updated periodically to
reflect changed conditions.
By Year (1) By Function
(In millions) (In millions)
------------------------------- -----------------------------
2000..................... $ 60 Production (1)......... $ 90
2001..................... 63 Transmission........... 16
2002..................... 64 Distribution........... 101
2003..................... 65 General................ 45
---- ----
Total.................. $252 Total................ $252
==== ====
_____________
(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 fuel,
natural gas, coal and purchased power to the total kWh energy mix of the
Company:
Years Ended December 31,
-------------------------------
Power Source 1999 1998 1997
-------- -------- --------
Nuclear fuel....................................... 55% 52% 53%
Natural gas........................................ 33 35 34
Coal............................................... 8 7 6
Purchased power.................................... 4 6 7
----- ----- -----
Total............................................ 100% 100% 100%
===== ===== =====
Allocated fuel and purchased power costs are generally passed through
directly to customers in Texas pursuant to applicable regulations. Historical
fuel costs and revenues are reconciled periodically in proceedings before the
Texas Commission to determine whether a refund or surcharge based on such
historical costs and revenues is necessary. Prior to the New Mexico Settlement
Agreement, the Company was required to make annual filings reconciling the
revenues collected under its New Mexico fixed fuel factor with its New Mexico
fuel and purchased power expenses. As a result of the New Mexico Settlement
Agreement, the fixed fuel factor has been incorporated into base rates. See
"Regulation - Texas Regulatory Matters" and "- New Mexico Regulatory Matters."
7
Nuclear Fuel
The Company has contracts for uranium concentrates which should be
sufficient to meet the Company's share of Palo Verde's operational requirements
through 2002. The Palo Verde Participants have contracted for sufficient
conversion services to provide for plant needs through 2000, but need to
contract for additional conversion services for 2001 and beyond. APS, as
operating agent for Palo Verde, expects that these services will be available on
the spot market or, alternatively, through long-term contract arrangements. The
Palo Verde Participants have an enrichment services contract which runs through
2002, with an option for five additional years.
Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the
Company owns an undivided interest in nuclear fuel purchased in connection with
Palo Verde. The Company has available a total of $100 million under a revolving
credit facility that provides for both working capital and up to $70 million for
the financing of nuclear fuel. At December 31, 1999, approximately $48.3
million had been drawn to finance nuclear fuel. This financing is accomplished
through a trust that borrows under the facility to acquire and process the
nuclear fuel. The Company is obligated to repay the trust's borrowings with
interest and has secured this obligation with First Mortgage Collateral Series
Bonds. In the Company's financial statements, the assets and liabilities of the
trust are reported as assets and liabilities of the Company.
Natural Gas
In 1999, the Company's natural gas requirements at the Rio Grande Power
Station were met with both short-term and long-term natural gas purchases from
various suppliers. Interstate gas is delivered under a firm ten-year
transportation agreement, which expires in 2001 with extension provisions
through 2005. Based on the current availability of economical and reliable
market natural gas supplies, the Company anticipates it will continue to
purchase natural gas at market prices on a monthly basis for a portion of the
fuel needs for the Rio Grande Power Station for the near term. To complement
these monthly purchases in 2000, the Company has entered into a one-year fixed-
price gas supply contract. The Company will continue to evaluate the
availability of short-term natural gas supplies versus long-term supplies to
maintain a reliable and economical supply for the Rio Grande Power Station.
In 1999, natural gas for the Newman and Copper Power Stations was supplied
primarily pursuant to a five-year intrastate natural gas contract which became
effective January 1, 1997 and expires December 31, 2001. Natural gas was also
provided to the Newman and Copper Power Stations pursuant to a similar long-term
interstate natural gas contract which supplements the intrastate contract and
also expires on December 31, 2001. To complement these long-term contracts, the
Company also evaluates and procures short-term natural gas supplies at market
prices to maintain a reliable and economical supply for the Newman and Copper
Power Stations.
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. Based upon information from APS, the Company believes that
Four Corners has sufficient reserves of coal to meet the plant's operational
requirements for its useful life.
8
In 1999, upon final review of a study conducted by an outside engineering
firm, the Company reduced its estimated final reclamation and coal mine closure
liability related to the Company's interest in Four Corners from $14.8 million
to $8.2 million. The $6.6 million adjustment was recorded as a reduction of
energy expenses in the fourth quarter of 1999.
Purchased Power
To supplement its own generation and operating reserves, the Company
engages in firm and non-firm power purchase arrangements which may vary in
duration and amount based on evaluation of the Company's resource needs and
economics of the transactions.
9
Operating Statistics
Years Ended December 31,
-----------------------------------------
1999 1998 1997
---------- ---------- ----------
Operating revenues (In thousands):
Retail:
Residential................................................. $ 164,524 $ 173,215 $ 172,917
Commercial and industrial, small............................ 175,924 174,729 173,318
Commercial and industrial, large............................ 59,497 62,450 64,468
Sales to public authorities................................. 80,393 82,360 82,278
---------- ---------- ----------
Total retail.............................................. 480,338 492,754 492,981
---------- ---------- ----------
Wholesale:
Sales for resale............................................ 49,441 82,396 83,448
Economy sales............................................... 32,523 20,167 10,612
---------- ---------- ----------
Total wholesale........................................... 81,964 102,563 94,060
---------- ---------- ----------
Other......................................................... 8,167 6,506 4,980
---------- ---------- ----------
Total operating revenues................................ $ 570,469 $ 601,823 $ 592,021
========== ========== ==========
Number of customers (End of year):
Residential................................................... 266,627 260,356 254,348
Commercial and industrial, small.............................. 27,274 26,396 25,900
Commercial and industrial, large.............................. 124 117 115
Other......................................................... 3,957 3,867 3,811
---------- ---------- ----------
Total................................................... 297,982 290,736 284,174
========== ========== ==========
Average annual kWh use per residential customer................. 6,268 6,291 6,285
========== ========== ==========
Energy supplied, net, kWh (In thousands):
Generated..................................................... 8,392,890 8,586,098 8,186,187
Purchased and interchanged.................................... 328,225 478,396 617,651
---------- ---------- ----------
Total................................................... 8,721,115 9,064,494 8,803,838
========== ========== ==========
Energy sales, kWh (In thousands):
Retail:
Residential................................................. 1,653,859 1,621,436 1,587,733
Commercial and industrial, small............................ 1,943,120 1,891,703 1,834,953
Commercial and industrial, large............................ 1,133,751 1,314,428 1,271,449
Sales to public authorities................................. 1,135,438 1,120,654 1,090,312
---------- ---------- ----------
Total retail.............................................. 5,866,168 5,948,221 5,784,447
---------- ---------- ----------
Wholesale:
Sales for resale............................................ 905,975 1,757,880 1,897,885
Economy sales............................................... 1,497,880 888,708 640,017
---------- ---------- ----------
Total wholesale........................................... 2,403,855 2,646,588 2,537,902
---------- ---------- ----------
Total energy sales...................................... 8,270,023 8,594,809 8,322,349
Losses and Company use........................................ 451,092 469,685 481,489
---------- ---------- ----------
Total................................................... 8,721,115 9,064,494 8,803,838
========== ========== ==========
Native system:
Peak load, kW................................................. 1,159,000 1,167,000 1,122,000
Net generating capacity for peak, kW.......................... 1,500,000 1,500,000 1,500,000
Load factor................................................... 62.5% 63.1% 64.0%
========== ========== ==========
Total system:
Peak load, kW................................................. 1,287,000 1,439,000 1,442,000
Net generating capacity for peak, kW.......................... 1,500,000 1,500,000 1,500,000
Load factor................................................... 62.9% 64.3% 64.0%
========== ========== ==========
10
Regulation
General
In 1999, both Texas and New Mexico enacted electric utility industry
restructuring laws requiring competition in certain functions of the industry
and ultimately in the Company's service area. The New Mexico Restructuring Law
currently requires competition to begin on January 1, 2001. The Company
believes the New Mexico Commission may delay the start of competition, but
cannot predict the length of such delay, if any. Under the Texas Restructuring
Law, the Company's Texas service area is exempt from competition until the
expiration of the Freeze Period, currently scheduled to terminate in August
2005.
The Company is working to become more competitive in response to these new
restructuring laws as well as other regulatory, economic and technological
changes occurring throughout the industry. Deregulation of the production of
electricity and related services and increasing customer demand for lower priced
electricity and other energy services have accelerated the industry's movement
toward more competitive pricing and cost structures. These competitive
pressures could result in the loss of customers and diminish the ability of the
Company to fully recover its investment in generation assets. This issue is
particularly important to the Company because its rates are significantly higher
than national and regional averages. As a result of the initiation of
deregulation in New Mexico and other portions of Texas, the Company may face
increasing pressure on its retail rates and its rate freeze under the Texas Rate
Stipulation. The Company's results of operations and cash flows may be
adversely affected if it cannot maintain its current retail rates.
The Company is particularly concerned with the ultimate recoverability of
"stranded costs," or costs previously found by regulatory authorities to be
reasonable and prudent, but which are higher than would be recovered under
immediate, full competition. 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. The Texas Restructuring Law exempts the Company's Texas service area
from retail competition, and preserves rates at their current levels, until the
end of its Freeze Period. The Company is prohibited from recovering stranded
costs or costs of transition to competition beyond the Freeze Period.
Under the New Mexico Restructuring Law, the New Mexico Commission may limit
the Company's recovery of its stranded costs. The New Mexico Restructuring Law
also allows for recovery of prudent costs related to transition to competition.
See "New Mexico Regulatory Matters - Deregulation" below.
Texas Regulatory 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 other activities of the Company. The decisions of the Texas
Commission are subject to judicial review.
11
Deregulation. The Texas Restructuring Law requires an electric utility to
separate its business activities into a power generation company, a retail
electric provider, and a transmission and distribution utility by January 1,
2002. The Texas Restructuring Law also requires a utility to separate its
customer energy services business from its regulated utility activities by
September 1, 2000. A utility may accomplish this separation through creation of
nonaffiliated companies, separate affiliated companies owned by a common holding
company, or through the sale of assets to third parties. Although the Company is
not subject to the Texas restructuring requirements until the expiration of the
Freeze Period, the Company is subject to the restructuring requirements of the
New Mexico Restructuring Law. See "New Mexico Regulatory Matters - Deregulation"
below.
The Texas Restructuring Law specifically recognizes and preserves the
substantial benefits the Company bargained for in its Texas Rate Stipulation and
Texas Settlement Agreement. The Texas Restructuring Law exempts the Company's
Texas service area from retail competition, and preserves rates at their current
levels until the end of its Freeze Period. At the end of the Freeze Period, the
Company will be subject to retail competition and will have no further claim for
recovery of stranded costs or costs of transition to competition. The Company
believes that its continued ability to provide bundled electric service at
current rates in its Texas service area will allow the Company to collect its
Texas jurisdictional stranded costs and costs of transition to competition.
Texas Rate Stipulation and Texas Settlement Agreement. The Company's rates
for its Texas customers are governed by a rate order entered by the Texas
Commission adopting the Texas Rate Stipulation and Agreed Order. The Agreed
Order implemented certain provisions of the Texas Rate Stipulation and set rates
consistent with the Texas Rate Stipulation. Among other things, under the Texas
Rate Stipulation: (i) the Company's base rates for most customers in Texas were
fixed for the ten-year Freeze Period which began in August 1995; (ii) the City
of El Paso granted the Company a new franchise that extends through the Freeze
Period; (iii) the Company retains 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; (iv) the Company's reacquisition of the
Palo Verde leased assets was deemed to be in the public interest; and (v) all
appeals of Texas Commission orders concerning the Company and all outstanding
Texas Commission dockets concerning the Company's rates were resolved.
Neither the Texas 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 Texas Rate Stipulation (other than the OPC and
the State of Texas) agreed to not 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 Texas Rate
Stipulation retain all rights provided in the Texas Rate Stipulation, the right
to participate as a party in any proceeding related to the merger, and the right
to pursue a reduction in rates below the freeze level to the extent of post-
merger synergy savings.
12
Following the New Mexico Settlement Agreement (see "New Mexico Regulatory
Matters - New Mexico Settlement Agreement" below), the Company offered to enter
into a comparable agreement in Texas. Based upon that offer, the Company entered
into the Texas Settlement Agreement providing for: (i) a total annual
jurisdictional base rate reduction of approximately $15.4 million; (ii)
reconciliation of approximately $221.2 million of fuel revenues to fuel expenses
for the 42-month period ended December 31, 1998, with no disallowance; and (iii)
an agreement to use 50% of all Palo Verde performance rewards related to
evaluation periods after 1997, when collected, for low-income assistance and for
DSM programs, primarily focused on small business customers, through the end of
the Freeze Period. The Texas Settlement Agreement was filed with the Texas
Commission, the City of El Paso and all other municipalities having
jurisdiction. The Texas Commission approved the Texas Settlement Agreement in
June 1999.
Fuel. Pursuant to Texas Commission rules, the Company must periodically
make a filing to reconcile the revenues collected from Texas customers under its
fixed fuel factor with the actual fuel and purchased power expenses incurred.
Differences between revenues collected and expenses incurred during the
reconciliation period are subject to a refund (in the case of an overrecovery of
fuel costs) or surcharge (in the case of an underrecovery of fuel costs). The
Texas Commission staff, local regulatory authorities such as the City of El
Paso, and customers are entitled to intervene in a fuel reconciliation
proceeding and to challenge the prudence of fuel and purchased power expenses.
The Company's fuel expenses for its most recent reconciliation period of July
1995 through December 1998 were approved, with no disallowance, as part of the
Texas Settlement Agreement.
Palo Verde Performance Standards. The Texas Commission established
performance standards for the operation of Palo Verde, pursuant to which each
Palo Verde unit 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 Texas Rate Stipulation and the Texas
Settlement Agreement. The removal of Palo Verde from rate base could have a
significant negative impact on the Company's revenues and financial condition.
Performance rewards and penalties for the evaluation periods ending in 1997,
1996 and 1995, as well as an agreement regarding disposition of half of any
future rewards, were resolved in the Texas Settlement Agreement and the IRP
stipulation. The Company has calculated significant performance rewards for the
three-year periods ended December 31, 1999 and 1998. However, the ultimate
disposition of these rewards is subject to Texas Commission review during the
periodic fuel reconciliation proceedings discussed above. Performance rewards
are not recorded on the Company's books until a final determination has been
ordered by the Texas Commission in a fuel reconciliation proceeding. Performance
penalties are recorded when assessed as probable by the Company.
Integrated Resource Plan. Under Texas law and regulations of the Texas
Commission, the Company was required to file an IRP in June 1998. The Company's
IRP was the culmination of a lengthy planning process involving the Company, its
customers, the Texas Commission, consumer advocates and various special interest
groups. The purpose of integrated resource planning was to ensure acquisition of
the lowest cost, adequate resources necessary to meet the varied needs of the
Company and its customers, and to ensure the equitable allocation and
distribution of the benefits of such resource acquisitions and other system
benefits to all customer classes. The Company entered into an agreement with all
parties with respect to all IRP issues, and a Texas Commission order adopting
the agreement
13
was issued in January 1999. Pursuant to the agreement, the Company will meet its
resource needs through a combination of short-term purchased power and a DSM
program. Pursuant to the IRP, the Company expects to incur DSM expenditures
annually of approximately $1.0 million through 2001. Additionally, the Company
committed a total of approximately $1.0 million to fund a low-income
weatherization and energy efficiency program over a three-year period beginning
in 1999. Finally, in response to interest expressed by its customers and
encouragement from the Texas Commission and environmental advocates, the Company
has committed to the development of renewable resources. Pursuant to the
stipulation settling the IRP, the Company has pledged $3.6 million of prior Palo
Verde performance rewards, including related interest, collected by the Company
as a result of the Texas Settlement Agreement as initial financing for the
development of renewable resources. The Company does not believe the IRP
agreement will cause it to incur net costs materially in excess of those that
would have been incurred in the absence of its IRP. Nevertheless, because of the
Texas Rate Stipulation and the Texas Settlement Agreement, the Company will not
be able to increase its rates to recover any increase in net costs actually
experienced as a result of its IRP. Going forward, the Texas Restructuring Law
abolished the requirement for utilities to develop IRPs; therefore, the Company
will have no further IRP obligation after December 31, 2001.
New Mexico Regulatory Matters
The New Mexico Commission has jurisdiction over the Company's rates and
services in New Mexico and over certain other 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. In January
1999, pursuant to a state constitutional amendment passed in 1996, the three-
member appointed commission was replaced by an elected commission from five
single-member districts, with regulatory responsibility for electricity, gas,
water, telecommunications, insurance and securities activities within the state.
The Company's New Mexico service area falls entirely within one district. The
largest city in the Company's New Mexico service territory is Las Cruces, which
in 1999 accounted for approximately 8% of the Company's total revenue.
Deregulation. The New Mexico Restructuring Law requires the Company to
reorganize its present corporate structure, separating its power generation and
energy services businesses, which will become competitive, from its transmission
and distribution business, which will remain regulated. Originally, utilities
were required to file transition plans addressing the various restructuring
issues, including the recovery of stranded costs, by March 1, 2000, which was
subsequently extended to June 1, 2000. On March 1, 2000, the Company filed the
first phase of its transition plan ("Transition Plan-Phase I") with the New
Mexico Commission, requesting approval of the Company's proposed corporate
reorganization under the New Mexico Restructuring Law. The Company filed its
Transition Plan-Phase I early to allow the Company to obtain regulatory and
other approvals necessary to complete its corporate separation by the January 1,
2001 deadline under the New Mexico Restructuring Law. The Company proposed to
separate its current operations into a power generation subsidiary, a
transmission and distribution subsidiary, and an energy services subsidiary, all
owned and controlled by a common holding company. The Company will file its
Transition Plan-Phase II by June 1, 2000, detailing the Company's proposed
processes and procedures to implement customer choice in New Mexico.
Under the New Mexico Restructuring Law, retail customer choice is currently
scheduled to begin January 1, 2001 for public post-secondary educational
institutions, public schools and residential and small business customers.
Retail customer choice is currently scheduled to begin January 1, 2002 for all
other customers. The New Mexico Restructuring Law allows a utility to recover at
least 50% of
14
its stranded costs with up to 100% recovery allowed if the New Mexico Commission
determines that additional recovery (i) is in the public interest, (ii) is
necessary to maintain the utility's financial integrity, (iii) is necessary to
continue adequate and reliable service, and (iv) will not cause an increase in
rates to residential and small business customers. The New Mexico Restructuring
Law, however, includes decommissioning costs as part of stranded costs. Because
the New Mexico Restructuring Law defines decommissioning costs as a stranded
cost, it is possible that the New Mexico Commission may allow only 50% recovery
of decommissioning costs. However, the New Mexico Restructuring Law also
specifically provides that nothing in the law should be interpreted as requiring
the New Mexico Commission to issue an order which would jeopardize the exclusive
use of the external sinking fund method for meeting decommissioning obligations
pursuant to federal guidelines. The Company believes this provision requires the
full recovery of New Mexico decommissioning requirements over the life of the
nuclear asset through a separate non-bypassable wires charge. The Company cannot
predict how the New Mexico Commission will ultimately treat this matter.
The New Mexico Restructuring Law allows the Company to recover reasonable,
prudent and unmitigated costs that the Company would not have incurred but for
its compliance with the New Mexico Restructuring Law. These transition costs do
not include stranded costs, costs the Company can collect under federally
approved rates or rates approved by the New Mexico Commission, or any costs the
Company would have incurred regardless of the New Mexico Restructuring Law. The
Company cannot predict whether the New Mexico Commission will allow the Company
to recover all of its transition costs.
The New Mexico Restructuring Law also allowed the New Mexico Commission to
review and either confirm, reject or modify the Company's New Mexico Settlement
Agreement. On November 30, 1999, the New Mexico Commission issued a final order
finding that the Company's New Mexico Settlement Agreement did not, under the
terms of the New Mexico Restructuring Law, constitute a plan or approval for
recovery of stranded costs. On December 30, 1999, the Company filed a motion for
rehearing requesting the New Mexico Commission to confirm that it would
determine the Company's stranded costs by using either (i) the stranded cost
recovery formula contained in the New Mexico Restructuring Law, applied to the
Company's generation asset values in effect prior to the rate base write-downs
contained in the New Mexico Settlement Agreement, or (ii) the Company's stranded
costs contained in the New Mexico Settlement Agreement. This would allow the
Company to either (i) preserve the stranded cost benefits obtained in the New
Mexico Settlement Agreement or (ii) be subject to the same stranded cost
provisions of the New Mexico Restructuring Law as every other electric utility
in New Mexico. On January 18, 2000, the New Mexico Commission issued an order
granting the Company's request.
New Mexico Settlement Agreement. In July 1998, the Company entered into
the New Mexico Settlement Agreement with certain parties, including the New
Mexico Commission staff and the New Mexico Attorney General, but not Las Cruces.
In September 1998, the New Mexico Commission issued an order adopting, with some
modification, the New Mexico Settlement Agreement. The New Mexico Settlement
Agreement became effective on October 26, 1998 and provides for (i) a total
annual jurisdictional base revenue reduction of $4.6 million; (ii) a 30-month
moratorium on rate increases or decreases in New Mexico; (iii) the elimination
of the need for future fuel reconciliations in New Mexico by incorporating the
existing fixed fuel factor into base rates; (iv) an increased degree of
ratemaking certainty for the future achieved by an agreement among the
signatories reducing the net value of certain assets by approximately $56
million on a New Mexico jurisdictional basis for ratemaking purposes (but with
no effect on book values), while establishing the signatories' agreement that
the
15
Company is entitled to 100% recovery of such revalued assets; and (v) the
ability to enter into long-term rate contracts with commercial and industrial
customers in New Mexico. Additionally, as a result of the New Mexico Settlement
Agreement, the Company will contribute $0.4 million annually ($1.0 million over
the term of the moratorium period) to a social services agency in Dona Ana
County providing assistance to low-income individuals. Although the New Mexico
Settlement Agreement was structured to allow recovery of previously
underrecovered fuel balances, the order adopting the New Mexico Settlement
Agreement does not support the recognition of this asset in the Company's
financial statements under existing accounting standards. The Company wrote off
the book value of undercollected fuel revenues in its New Mexico jurisdiction as
of September 30, 1998, which amounted to $3.8 million, net of tax, although the
Company believes that, based on current estimates of future fuel prices and
operating costs, it will recover 100% of these amounts.
Fuel. Prior to the New Mexico Settlement Agreement, the Company was
required to file annual reports reconciling the revenues collected under its New
Mexico fixed fuel factor with its New Mexico fuel and purchased power expenses,
along with the results of the application of Palo Verde performance standards.
As a result of the New Mexico Settlement Agreement, outstanding fuel issues from
filings in 1998 and 1997 were satisfactorily resolved with no disallowance of
fuel and purchased power costs or the performance rewards, and the existing
fixed fuel factor was incorporated into base rates.
Palo Verde Performance Standards. As a result of the New Mexico Settlement
Agreement, the Palo Verde performance standards, which had been in place since
1986, were eliminated. Consequently, the Company is no longer entitled to a
reward or exposed to a penalty in New Mexico resulting from the operations of
Palo Verde. The performance standards report filed with the New Mexico
Commission in January 1998 was the final such report and entitled the Company to
a reward of $1.1 million.
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.
On December 15, 1999, the FERC approved its final rule ("Order 2000") on
Regional Transmission Organizations ("RTOs"). Order 2000 strongly encourages,
but does not require, public utilities to form and join RTOs. Order 2000
establishes (i) the minimum characteristics and functions an RTO must satisfy to
obtain FERC acceptance; (ii) a collaborative process allowing public utilities
and non-public utilities that own, operate or control interstate transmission
facilities, consulting with state officials as appropriate, to consider and
develop RTOs; (iii) a proposal to consider transmission ratemaking returns on a
case-specific basis; (iv) opportunities for non-monetary regulatory benefits for
RTOs, including deference in dispute resolution and streamlined filing and
approval procedures; and (v) a time line for public utilities to make
appropriate filings with the FERC to initiate operation of RTOs. All public
utilities that own, operate or control interstate transmission facilities must
file, by October 15, 2000, either a proposal to participate in an RTO or an
alternative filing describing efforts and plans to participate in an RTO. Order
2000 also proposes RTO startup by December 15, 2001.
The Company is an active participant in the development of the Desert
Southwest Transmission and Reliability Operator ("Desert Star"). The Company
believes Desert Star will qualify as an RTO under Order 2000. The Company
intends, subject to the resolution of outstanding issues, to participate in
Desert Star. As a participating transmission owner, the Company will transfer
operations of its
16
transmission system to Desert Star. The Company believes the Desert Star
proposal will be submitted to the FERC by October 15, 2000. Desert Star is
currently scheduled to become operational by January 1, 2002. If Desert Star
fails to become operational, the Company intends to participate in another RTO
similar to Desert Star.
In April 1996, the FERC issued its Order No. 888, requiring all public
utilities owning, operating or controlling facilities used for transmitting
electricity in interstate commerce to allow access to their transmission
facilities under minimum terms and conditions of non-discriminatory service,
including transmission service for their own new wholesale sales and purchases
of electric energy. 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.
In April 1996, the FERC also issued Order No. 889, which 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
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 adopt
standards of conduct ensuring that all open access transmission customers are
treated in a non-discriminatory manner.
Pursuant to Order No. 888, the Company filed its non-discriminatory open
access transmission tariffs with the FERC in July 1996. The Company reached a
settlement with the various parties regarding rates for transmission and
ancillary services under these tariffs. However, the settlement, which was filed
with the FERC in March 1997 and approved by the FERC in June 1998, did not
resolve issues that had been raised with respect to the manner in which the
Company will determine the amount of transmission capacity that is available for
use by third parties desiring to use its transmission system.
In May 1999, the FERC issued its opinion in a proceeding brought by SPS
regarding the use of the Company's transmission system to serve Las Cruces,
holding that once the Company's calculation of available transmission capacity
was adjusted to reflect the assumed discontinuation of service to Las Cruces and
CFE, the Company would have sufficient transmission capacity over the Eddy
County tie to meet SPS' request for firm transmission service. Although the
Company has filed a compliance filing as required by the FERC's order, the
filing reflects that the Company does not have sufficient transmission capacity
over the Eddy County tie to meet SPS' request for firm transmission service. The
Company filed a motion for rehearing of the FERC's decision. The FERC has
extended its time limit for ruling on this motion. The Company does not expect a
material financial impact from this FERC ruling. However, the Company is
concerned that of an adverse FERC ruling would result in impaired the
reliability of service to the Company's retail customers and increased costs.
This case will not be automatically dismissed under the settlement agreement
with Las Cruces because SPS, not Las Cruces, was the original complainant.
Although the SPS complaint was based upon the creation of a Las Cruces municipal
utility, the Company cannot predict whether the case will be dismissed as a
result of its settlement with Las Cruces.
On February 24, 2000, the Company and Las Cruces entered into a settlement
agreement ending Las Cruces' efforts to municipalize the Company's distribution
system in Las Cruces. Under the terms of the settlement agreement, all existing
litigation between the Company and Las Cruces,
17
including all litigation pending before the FERC, will be dismissed. For a
discussion of this settlement agreement, see Item 3, "Legal Proceedings -
Litigation with Las Cruces."
Department of Energy. The DOE regulates the Company's exports of power to
CFE in Mexico pursuant to a license granted by the DOE and a presidential
permit. The DOE has determined that all such exports over international
transmission lines shall be made in accordance with Order No. 888. The DOE is
authorized to assess operators of nuclear generating facilities for a share of
the costs of decommissioning the DOE's uranium enrichment facilities and for the
ultimate costs of disposal of spent nuclear fuel. See "Facilities - Palo Verde
Station - Spent Fuel Storage" for discussion of spent fuel storage and disposal
costs.
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.
The NRC also has the authority to conduct environmental reviews pursuant to the
National Environmental Policy Act.
Wholesale Customers
The Company provides IID with 100 MW of firm capacity and associated energy
and 50 MW of system contingent capacity and associated energy pursuant to a 17-
year agreement which expires April 30, 2002. The Company also provides TNP with
up to 75 MW of firm power and associated energy pursuant to an agreement which
expires December 31, 2002. The contract allows TNP to specify a maximum annual
amount with one year's notice. TNP elected to receive up to 25 MW for 2000.
18
Executive Officers of the Company
Name Age Current Position and Business Experience
---- --- ----------------------------------------
James Haines.................. 53 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.......... 44 Senior Vice President - Energy Services since January 1999; Senior
Vice President - Customer and Corporate Services from August 1996
to January 1999; Senior Vice President since January 1994; General
Counsel from 1988 to August 1996.
Terry Bassham................. 39 Vice President and General Counsel since January 1999; General
Counsel since August 1996; Shareholder with Clark, Thomas &
Winters, P.C. from May 1993 to August 1996.
J. Frank Bates................ 49 Vice President - Transmission and Distribution since August 1996;
Vice President - Operations from May 1994 to August 1996.
Michael L. Blough............. 44 Vice President - Administration since August 1996; Vice President
since May 1995; Controller and Chief Accounting Officer from
November 1994 to August 1996.
Gary R. Hedrick............... 45 Vice President, Chief Financial Officer and Treasurer since August
1996; Treasurer since March 1996; Vice President - Financial
Planning and Rate Administration from September 1990 to August
1996.
John C. Horne................. 51 Vice President - Power Generation since August 1996; Vice President -
Power Supply from May 1994 to August 1996.
Helen Knopp................... 57 Vice President - Customer and Public Affairs since April 1999;
Executive Director of the Rio Grande Girl Scout Council from
September 1991 to April 1999.
Earnest A. Lehman............. 47 Vice President - Energy Services Business Group since January 1999;
Director of Rates of Western Resources, Inc. from January 1998 to
January 1999; Director of Wholesale Rates of Western Resources,
Inc. from January 1997 to January 1998; Vice President - Consumer
Sales of Westar Consumer Services from March 1996 to January 1997;
Executive Director of Marketing of Western Resources, Inc. from
December 1994 to March 1996.
Robert C. McNiel.............. 53 Vice President - New Mexico Affairs since December 1997; Vice
President -Public Affairs and Marketing from August 1996 to
December 1997; Vice President - New Mexico Division from December
1989 to August 1996.
Guillermo Silva, Jr........... 46 Secretary since 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 F of Notes to Financial Statements" for
information regarding encumbrances against the principal properties of the
Company.
Item 3. Legal Proceedings
Litigation with Las Cruces
On February 24, 2000, the Company and Las Cruces entered into a settlement
agreement ending Las Cruces' efforts to municipalize the Company's distribution
assets and other facilities used to provide electric service to customers in Las
Cruces. Under the settlement agreement the Company will pay Las Cruces a one-
time lump sum payment of up to $21 million, $16.5 million of which was expensed
in the fourth quarter of 1999. The remaining $4.5 million relates to the
transfer of Las Cruces' West Mesa Substation and related facilities to the
Company. Las Cruces must substantiate the costs of building the West Mesa
Substation and related transmission and distribution facilities, subject to a
dollar for dollar offset against the $4.5 million purchase price for any amounts
not substantiated.
The settlement agreement also provides for Las Cruces and the Company to
enter into a seven-year franchise agreement with a 2% annual franchise fee
(approximately $0.8 million per year currently) for the provision of electric
distribution service. Las Cruces is prohibited during this seven-year period
from taking any action to condemn or otherwise attempt to acquire the Company's
distribution system, or attempt to operate or build its own electric
distribution system. Las Cruces will have a 90-day non-assignable option at the
end of the Company's seven-year franchise agreement to purchase the portion of
the Company's distribution system that serves Las Cruces at a purchase price of
130% of the Company's book value at that time. If Las Cruces exercises this
option, it is prohibited from reselling the distribution assets for two years.
If Las Cruces fails to exercise this option, the franchise and standstill
agreements will be extended for an additional two years.
Las Cruces also agreed that it will not contest the calculation of the
Company's stranded costs in New Mexico, provided the stranded costs charged to
Las Cruces customers do not exceed $52.9 million declining over time, which is
the amount initially ordered by the FERC in the Las Cruces stranded cost
proceeding. Las Cruces also agreed to assign all of its existing customer
contracts to the Company.
Under the terms of the settlement agreement, all existing litigation
between the Company and Las Cruces, including all litigation pending before the
FERC and the Federal District Court of New Mexico, will be dismissed. The
Company and Las Cruces are finalizing the written settlement agreement and
obtaining final approvals. The Company anticipates signing a definitive
agreement by the end of the first quarter of 2000.
20
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. In October 1995, the Navajo Nation and the Four Corners
participants agreed to stay the proceedings indefinitely so the parties may
attempt to resolve the dispute without litigation. This matter remains inactive
and the Company is unable to predict the outcome of this case.
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
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. An agreement reached with the Navajo
Nation in 1985 provides that if Four Corners loses a portion of its water rights
in the adjudication, the tribe will provide sufficient water from its allocation
to offset the loss. The case has been inactive for many years and the Company is
unable to 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 this 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 November 1999, the Arizona
Supreme Court issued a decision confirming that certain groundwater rights may
be available to the federal government and Indian tribes. APS and other parties
have petitioned the United States Supreme Court for review of this decision. The
Company is unable to predict the outcome of this case.
21
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, the Company believes that none of these claims
will have a material adverse effect on the financial position, results of
operations and cash flows of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
22
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Company's common stock trades on the American Stock Exchange 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
---------- -----------
1999
----
First Quarter........................ $ 8 15/16 $ 7
Second Quarter....................... 9 3/16 7 5/16
Third Quarter........................ 9 3/8 8 1/2
Fourth Quarter....................... 9 13/16 8 9/16
1998
----
First Quarter........................ $ 8 13/16 $ 6 3/8
Second Quarter....................... 10 3/8 8 9/16
Third Quarter........................ 9 15/16 7 9/16
Fourth Quarter....................... 9 3/4 8
As of March 13, 2000, there were 5,505 holders of record of the Company's
common stock.
Prior to September 1999, the Company's First and Second Supplemental
Indentures restricted the Company's ability to pay dividends on its common
stock. So long as the Company's First Mortgage Bonds are outstanding and the
series with the longest maturity was not rated "investment grade" by either
Standard & Poor's Rating Service ("S&P") or Moody's Investors Service, Inc.
("Moody's"), the Company was significantly limited in its ability to declare any
dividend on the common stock, other than in additional shares of common stock.
The Company's First Mortgage Bonds were upgraded to investment grade by S&P in
September 1999 and by Moody's in November 1999. While the First and Second
Supplemental Indentures do not currently restrict the Company's ability to pay
dividends on its common stock, the Company does not currently anticipate paying
dividends on its common stock in the near-term. The Company intends to continue
its deleveraging and stock repurchase programs with the goals of improving its
capital structure and using free cash flow to its highest economic advantage.
In May 1999, the Company's Board of Directors approved a stock repurchase
program allowing the Company to purchase outstanding shares of its common stock
from time to time, up to a total of six million shares. The Company will make
purchases primarily in the open market at prevailing prices and will also engage
in private transactions, if appropriate. The shares that the Company acquires
will be available for issuance under employee benefit and stock option plans or
may be retired. As of March 10, 2000, the Company had repurchased 5,747,995
shares of common stock at a cost of approximately $51.9 million, including
commissions.
23
In March 1999, after obtaining required consents of holders of certain of
the Company's outstanding debt securities, the Company redeemed its Series A
Preferred Stock. The Company paid the redemption price of approximately $139.6
million, accrued cash dividends of $1.3 million and premium, fees and costs of
securing the consents aggregating $9.6 million. See Part II, Item 8, "Financial
Statements and Supplementary Data - Note E of Notes to Financial Statements" for
additional information regarding preferred stock.
24
Item 6. Selected Financial Data
As of and for the following periods (In thousands except for share data):
Period From Period From
February 12 January 1
to to Year Ended
Years Ended December 31, December 31, February 11, December 31,
---------------------------------------
1999 1998 1997 1996 | 1996 1995
----------- ----------- ----------- ----------- | ----------- ------------
|
Operating revenues.......................... $ 570,469 $ 601,823 $ 592,021 $ 521,921 | $ 54,672 $ 502,213
Operating income............................ 157,336 159,717 159,636 142,438 | 1,362 47,470
Income (loss) before extraordinary items.... 43,809 57,073 54,568 41,919 | 118,198 (33,319)
Extraordinary loss on repurchases of debt, |
net of income tax benefit.................. (3,336) - (2,775) - | - -
Extraordinary gain on discharge of debt, |
net of income tax expense.................. - 3,343 - - | 264,273 -
Net income (loss) applicable to common |
stock...................................... 28,276 45,709 38,649 31,431 | 382,471 (33,319)
Basic earnings (loss) per common share: |
Income (loss) before extraordinary items... 0.533 0.704 0.689 0.523 | 3.325 (0.937)
Extraordinary loss on repurchases of debt, |
net of income tax benefit................. (0.057) - (0.046) - | - -
Extraordinary gain on discharge of debt, |
net of income tax expense................. - 0.056 - - | 7.435 -
Net income (loss).......................... 0.476 0.760 0.643 0.523 | 10.760 (0.937)
Weighted average number of common |
shares outstanding......................... 59,349,468 60,168,234 60,128,505 60,073,808 | 35,544,330 35,544,330
Diluted earnings (loss) per common share: |
Income (loss) before extraordinary items... 0.529 0.699 0.685 0.523 | 3.325 (0.937)
Extraordinary loss on repurchases of debt, |
net of income tax benefit................. (0.056) - (0.046) - | - -
Extraordinary gain on discharge of debt, |
net of income tax expense................. - 0.055 - - | 7.435 -
Net income (loss).......................... 0.473 0.754 0.639 0.523 | 10.760 (0.937)
Weighted average number of common shares |
and dilutive potential common shares |
outstanding................................ 59,731,649 60,633,298 60,437,632 60,116,709 | 35,544,330 35,544,330
Cash additions to utility property, plant |
and equipment.............................. 53,705 49,787 46,467 33,926 | 4,724 68,453
Total assets................................ 1,625,891 1,891,219 1,812,613 1,846,190 1,910,354 | 1,809,891
Long-term debt and financing and capital |
lease obligations.......................... 811,607 897,062 966,810 1,046,173 1,164,328 | -
Debt and obligations subject to compromise.. - - - - - | 1,608,091
Preferred stock............................. - 135,744 121,319 108,426 100,000 | 81,464
Common stock equity (deficit)............... 421,258 417,278 369,640 331,257 300,000 | (418,763)
=========== =========== =========== =========== =========== |============
On February 12, 1996, the Company emerged from a bankruptcy proceeding
which it instituted in January 1992. The Company's financial statements for
periods after February 12, 1996 are not comparable to the Company's financial
statements for periods before February 12, 1996 due to the application of
"fresh-start" reporting at that date. A vertical line is shown in the above
selected financial data to separate the respective financial information and
indicate that it has not been prepared on a consistent basis of accounting.
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."
25
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. 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 shareholders, 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 "Overview" and "Liquidity and Capital Resources," as
well as 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 risks and
factors discussed below and in such filings are 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.
Overview
El Paso Electric Company is an electric utility that serves retail
customers in west Texas and southern New Mexico and wholesale customers in
Texas, New Mexico, California and Mexico. The Company owns or has substantial
ownership interests in five electrical generating facilities providing it with a
total capacity of approximately 1,500 MW. The Company's energy sources consist
of nuclear fuel, natural gas, coal and purchased power. The Company owns or has
significant ownership interests in four major 345 kV transmission lines and
three 500 kV lines to provide power from Palo Verde, and owns the distribution
network within its retail service territory. The Company is subject to extensive
regulation by the Texas and New Mexico Commissions and, with respect to
wholesale power sales, transmission of electric power and the issuance of
securities, by the FERC.
The Company faces a number of risks and challenges that could negatively
impact its operations and financial results. The most significant of these risks
and challenges arise from the deregulation of the electric utility industry, the
possibility of increased costs, especially from Palo Verde, and the Company's
high level of debt.
The electric utility industry in general and the Company in particular are
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 changes in state laws and regulatory
provisions relating to wholesale and retail service. Both Texas and New Mexico
recently passed legislation that requires the Company to separate its
transmission and distribution functions from its generation business and
mandates competition in the Company's retail service territory in the future.
The Company faces certain risks inherent in separating the Company into
affiliates, including the possible loss of operational and administrative
efficiencies. In addition to the operational challenges created by separating
functions that have historically operated within a single entity, there is
substantial uncertainty as to whether the New Mexico legislation will
effectively permit the Company to recover its stranded costs, including the
costs of decommissioning, in full. The potential effects of deregulation are
particularly important to the Company because its rates are significantly higher
than the national and
26
regional averages. In the face of increased competition, there can be no
assurance that this competition will not adversely affect the future operations,
cash flows and financial condition of the Company.
The changing regulatory environment and the advent of customer choice have
created a substantial risk that the Company will lose important customers. For
several years, the Company has been engaged in litigation with Las Cruces, which
accounted for approximately 8% of the Company's revenues in 1999, over Las
Cruces' attempts to create a municipal utility. The parties have settled the
litigation, but the risk of loss of customers remains. The Company's wholesale
and large retail customers already have, in varying degrees, additional
alternate sources of economical power, including co-generation of electric
power. For example, a 504 MW combined-cycle generating plant located in
Samalayuca, Chihuahua, Mexico, which became fully operational at the end of
1998, gave CFE the current capacity to supply electricity to portions of
northern Chihuahua and allowed CFE to eliminate substantially all purchases of
power from the Company in 1999. Additionally, American National Power, Inc., a
wholly-owned subsidiary of National Power PLC, has announced it is exploring the
possibility of building a generation plant in El Paso, Texas. 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.
Another risk to the Company is potential increased costs, including the
risk of additional or unanticipated costs at Palo Verde resulting from (i)
increases in operation and maintenance expenses; (ii) the 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. At the same time, the
Company's rates, which have been reduced from previous levels as a result of the
New Mexico Settlement Agreement and the Texas Settlement Agreement, are
effectively capped through the rate freeze periods. Additionally, upon
initiation of competition, there will be competitive pressure on the Company's
power generation rates. There can be no assurance that the Company's revenues
will be sufficient to recover any increased costs, including any 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.
Liquidity and Capital Resources
The Company's principal liquidity requirements in the near-term are
expected to consist of interest and principal payments on the Company's
indebtedness, capital expenditures related to the Company's generating
facilities and transmission and distribution systems and the $21 million payment
required under the settlement agreement with Las Cruces. The Company expects
that cash flows from operations will be sufficient for such purposes, except
that it may be necessary to finance a portion of the Las Cruces payment in the
short-term by drawing on its line of credit.
Long-term capital requirements of the Company will consist primarily of
construction of electric utility plant and payment of interest on and retirement
of debt. The Company has no current plans to construct any new generating
capacity to serve retail load through at least 2004. Utility construction
expenditures will consist primarily of expanding and updating the transmission
and distribution systems and the cost of capital improvements and replacements
at Palo Verde and other generating facilities, including the replacement of the
Palo Verde Unit 2 steam generators.
27
At December 31, 1999, the Company had approximately $37.2 million in cash
and cash equivalents. In February 1999, the Company renewed its $100 million
revolving credit facility, which now provides up to $70 million for nuclear fuel
purchases and up to $50 million (depending on the amount of borrowings
outstanding for nuclear fuel purchases) for working capital needs. At December
31, 1999, approximately $48.3 million had been drawn for nuclear fuel purchases.
No amounts have been drawn on this facility for working capital needs.
The Company has a high debt to capitalization ratio and significant debt
service obligations. Due to the Texas Rate Stipulation, the Texas Settlement
Agreement, the New Mexico Settlement Agreement and competitive pressures, the
Company does not expect to be able to raise its base rates in the event of
increases in non-fuel costs, increases in fuel costs in New Mexico or loss of
revenues. Accordingly, as described below, debt reduction continues to be a high
priority for the Company in order to gain additional financial flexibility to
address the evolving competitive market. In March 1999, the Company used cash on
hand to pay for the early redemption of its Series A Preferred Stock, which
resulted in the avoidance of additional cash dividends of approximately $2.7
million that would have been payable through May 1, 1999, and $4.0 million
quarterly thereafter until mandatory redemption in 2008. The preferred stock had
an annual dividend rate of 11.40%, which was paid through the issuance of
additional shares of preferred stock for the first three years of the issue.
The Company has significantly reduced its long-term debt since its
emergence from bankruptcy in 1996. From June 1, 1996 through March 10, 2000, the
Company repurchased approximately $327.8 million of first mortgage bonds as part
of an aggressive deleveraging program and repaid the remaining $36.0 million of
Series A First Mortgage Bonds at their maturity in February 1999. The foregoing,
together with the early redemption of Series A Preferred Stock, have reduced the
Company's annual interest expense and annual cash dividend requirements by
approximately $28.9 million and $15.9 million, respectively. Common stock equity
as a percentage of capitalization, excluding current maturities of long-term
debt, has increased from 19% at June 30, 1996 to 34% at December 31, 1999. In
addition, the Company's bonds are now rated investment grade by all four major
credit rating agencies.
In May 1999, the Company's Board of Directors approved a stock repurchase
program allowing the Company to purchase outstanding shares of its common stock
from time to time, up to a total of six million shares. The Company will make
purchases primarily in the open market at prevailing prices and will also engage
in private transactions, if appropriate. The shares that the Company acquires
will be available for issuance under employee benefit and stock option plans or
may be retired. As of March 10, 2000, the Company had repurchased 5,747,995
shares of common stock at a cost of approximately $51.9 million, including
commissions.
The Company continues to believe that the orderly reduction of debt with a
goal of achieving a capital structure that is more typical in the electric
utility industry is a significant component of long-term shareholder value
creation. Accordingly, the Company will regularly evaluate market conditions
and, when appropriate, use a portion of its available cash to reduce its fixed
obligations through open market purchases of first mortgage bonds.
The degree to which the Company is leveraged could have important
consequences on the Company's liquidity, including (i) the Company's ability to
obtain additional financing for working capital, capital expenditures,
acquisitions, general corporate or other purposes could be limited in the
28
future and (ii) the Company's higher than average leverage may place the Company
at a competitive disadvantage by limiting its financial flexibility to respond
to the demands of the competitive market and make it more vulnerable to adverse
economic or business changes.
Historical Results of Operations
Years Ended December 31,
------------------------------------------
1999 1998 1997
------- ------ -------
Net income applicable to common stock
before extraordinary items (In thousands)............ $31,612 $42,366 $41,424
Diluted earnings per common share
before extraordinary items........................... 0.529 0.699 0.685
Results of operations for the year ended December 31, 1999 were affected by
unusual or infrequent items including (i) the recognition of certain items
arising from the Texas Settlement Agreement; (ii) a change in estimated fuel
cost reserves; (iii) an adjustment reducing fuel expense based on a reduction of
the Company's estimated coal mine reclamation liability; (iv) a charge to
earnings of $10.1 million, net of tax, as a result of the settlement agreement
with Las Cruces; (v) a one-time charge to earnings of $2.5 million, net of tax,
resulting from the write-off of interest capitalized prior to 1999 on postload
nuclear fuel; and (vi) the early redemption of the Company's 11.40% Series A
Preferred Stock. Results of operations for 1998 reflect a charge to earnings of
$3.8 million, net of tax, as a result of the New Mexico Settlement Agreement,
and 1997 results reflect a favorable litigation settlement of $4.6 million, net
of legal fees, expenses and tax.
Operating revenues net of energy expenses decreased $11.1 million in 1999,
compared to 1998 as follows (In thousands):
Years Ended December 31: 1999 1998 Increase/(Decrease)
- ------------------------ -------------- -------------- --------------------
Total operating revenues net of energy expenses. $ 460,672 $ 471,763 $ (11,091)
Less:
Texas Settlement Agreement:
Palo Verde performance reward................ 3,453 - 3,453
Retroactive base rate decrease............... (2,343) - (2,343)
Change in estimated fuel cost reserves......... 3,754 895 2,859
Coal mine reclamation adjustment............... 6,601 - 6,601
----------- ------------ -----------------
$ 449,207 $ 470,868 $ (21,661)
=========== ============ =================
Excluding the effects of the unusual or infrequent items shown above, the
decrease of $21.7 million was primarily due to the rate reductions in Texas and
New Mexico and the loss of sales to CFE. These decreases were partially offset
by increased economy sales.
Operating revenues net of energy expenses increased $13.3 million in 1998
compared to 1997 primarily due to increased economy sales at higher margins and
a $1.3 million increase in ESBG revenues.
29
Operating revenues from retail customers shown below include the effects of
the retroactive base rate decrease, the recognition of the Palo Verde
performance reward and the changes in estimated fuel cost reserves for the years
ended December 31, 1999 and 1998, as applicable. Comparisons of kWh sales and
operating revenues are shown below (In thousands):
Increase/(Decrease)
-------------------------
Years Ended December 31: 1999 1998 Amount Percent
- ------------------------ ------------- ------------- ----------- -----------
Electric kWh sales:
Retail.................................. 5,866,168 5,948,221 (82,053) (1.4)%
Sales for resale........................ 905,975 1,757,880 (851,905) (48.5) (1)
Economy sales........................... 1,497,880 888,708 609,172 68.5
---------- ---------- ---------
Total.................................. 8,270,023 8,594,809 (324,786) (3.8)
========== ========== =========
Operating revenues:
Retail.................................. $ 488,505 $ 499,260 $ (10,755) (2.2)%
Sales for resale........................ 49,441 82,396 (32,955) (40.0) (1)
Economy sales........................... 32,523 20,167 12,356 61.3
---------- ---------- ---------
Total.................................. $ 570,469 $ 601,823 $ (31,354) (5.2)
========== ========== =========
________________________
(1) The Company's one-year sales agreement for firm capacity and associated
energy sales to CFE terminated on December 31, 1998.
Increase/(Decrease)
-------------------------
Years Ended December 31: 1998 1997 Amount Percent
- ------------------------ ------------- ------------- ----------- -----------
Electric kWh sales:
Retail.................................. 5,948,221 5,784,447 163,774 2.8%
Sales for resale........................ 1,757,880 1,897,885 (140,005) (7.4)
Economy sales........................... 888,708 640,017 248,691 38.9
---------- ---------- ---------
Total.................................. 8,594,809 8,322,349 272,460 3.3
========== ========== =========
Operating revenues:
Retail.................................. $ 499,260 $ 497,961 $ 1,299 0.3%
Sales for resale........................ 82,396 83,448 (1,052) (1.3)
Economy sales........................... 20,167 10,612 9,555 90.0
---------- ---------- ---------
Total.................................. $ 601,823 $ 592,021 $ 9,802 1.7
========== ========== =========
30
Other operations and maintenance expense decreased $0.7 million in 1999
compared to 1998 due to decreased other operations expense of $2.1 million
partially offset by increased maintenance expense of $1.4 million, as follows
(In thousands):
Years Ended December 31: 1999 1998 Increase/(Decrease)
- ------------------------ -------------- -------------- ---------------------
Regulatory expense........................ $ 1,578 $ 6,043 $ (4,465)
Pensions and benefits expense............. 15,596 19,940 (4,344)
Customer accounts expense................. 5,014 3,132 1,882
Outside services expense.................. 9,790 8,008 1,782
Non-nuclear generation expense............ 5,199 3,672 1,527
Other..................................... 97,419 95,879 1,540
----------- ----------- ------------
Total other operations expense......... 134,596 136,674 (2,078)
Total maintenance expense................. 36,307 34,955 1,352