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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2000 Commission File Number 1-6986
PUBLIC SERVICE COMPANY OF NEW MEXICO
(Exact name of Registrant as specified in its charter)
New Mexico 85-0019030
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Alvarado Square 87158
Albuquerque, New Mexico (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (505) 241-2700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $5.00 Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
(Title of Class)
--------------
1965 Series, 4.58% Cumulative Preferred Stock ($100 stated
value and without sinking fund)
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 and (2) has been subject to such filing
requirements for the past 90 days. YES |X| NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. |X|
The total number of shares of the Company's Common Stock outstanding as of
January 31, 2001 was 39,117,799. On such date, the aggregate market value of the
voting stock held by non-affiliates of the Company, as computed by reference to
the New York Stock Exchange composite transaction closing price of $24.70 per
share reported by The Wall Street Journal, was $966,209,635.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following document are incorporated by reference into the
indicated part of this report:
Proxy Statement to be filed with the Securities and Exchange
Commission pursuant to Regulation 14A relating to the annual meeting
of stockholders to be held on July 3, 2001 - PART III.
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TABLE OF CONTENTS
Page
----
GLOSSARY................................................................... iv
PART I
ITEM 1. BUSINESS.......................................................... 1
THE COMPANY..................................................... 1
UTILITY OPERATIONS.............................................. 1
Electric Product Offering................................... 1
Natural Gas Product Offering................................ 2
GENERATION AND TRADING OPERATIONS............................... 4
Sources of Power............................................ 7
Fuel and Water Supply....................................... 8
UNREGULATED OPERATIONS.......................................... 10
DEREGULATION AND FORMATION OF HOLDING COMPANY................... 11
PROPOSED RULEMAKINGS RELATED TO DEREGULATION.................... 12
COMPETITION UNDER DEREGULATION.................................. 12
RATES AND REGULATION............................................ 13
Electric Rates and Regulation............................... 13
Federal Electric Initiatives................................ 14
Gas Rates and Regulation.................................... 15
ENVIRONMENTAL MATTERS........................................... 16
ITEM 2. PROPERTIES........................................................ 19
ELECTRIC........................................................ 19
Fossil-Fueled Plants........................................ 19
Nuclear Plant............................................... 20
Other Electric Properties................................... 24
NATURAL GAS..................................................... 25
OTHER INFORMATION............................................... 25
ITEM 3. LEGAL PROCEEDINGS................................................. 25
PVNGS Water Supply Litigation................................... 25
San Juan River Adjudication..................................... 25
Republic Savings Bank Litigation................................ 26
Purported Navajo Environmental Regulation....................... 26
Royalty Claims.................................................. 27
KAFB Contract................................................... 28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............... 29
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE COMPANY....................... 30
ii
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS............................... 32
ITEM 6. SELECTED FINANCIAL DATA......................................... 33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS........................... 34
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
MARKET RISK .................................................. 73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..................... F-1
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE........................... E-1
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY................. E-1
ITEM 11. EXECUTIVE COMPENSATION.......................................... E-1
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................... E-1
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................. E-1
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K................................................... E-1
SIGNATURES.................................................................E-24
iii
GLOSSARY
Act.......................... The Clean Air Act - Amendments of 1990
Avistar...................... Avistar, Inc., an unregulated subsidiary of
Public Service Company of New Mexico
AG........................... New Mexico Attorney General
AMDAX........................ AMDAX.com, an equity investee of Avistar
Anaheim...................... City of Anaheim, California
APPA......................... Arizona Power Pooling Association
APS.......................... Arizona Public Service Company
BHP.......................... BHP Minerals International, Inc.
BLM.......................... Bureau of Land Management
BTU.......................... British Thermal Unit
COA.......................... City of Albuquerque, New Mexico
Decatherm.................... 1,000,000 BTUs
Delta........................ Delta-Person Limited Partnership, a New Mexico
limited partnership
DOE.......................... United States Department of Energy
EIP.......................... Eastern Interconnection Project
El Paso...................... El Paso Electric Company
EPA.......................... United States Environmental Protection Agency
EPNG......................... El Paso Natural Gas Company
FERC......................... Federal Energy Regulatory Commission
FASB......................... Financial Accounting Standards Board
Farmington................... City of Farmington, New Mexico
FIP.......................... Federal Implementation Plan
Four Corners................. Four Corners Power Plant
FPPCAC....................... Fuel and Purchased Power Cost Adjustment Clause
Gallup....................... City of Gallup, New Mexico
Gathering Company............ Sunterra Gas Gathering Company, a wholly-owned
subsidiary of Public Service Company of
New Mexico
ISO.......................... Independent System Operator
KAFB......................... Kirtland Air Force Base
Kv........................... Kilovolt
KW........................... Kilowatt
KWh.......................... Kilowatt Hour
Los Alamos................... The County of Los Alamos, New Mexico
mcf.......................... Thousand cubic feet
Meadows...................... Meadows Resources, Inc., a wholly-owned
subsidiary of Public Service Company of
New Mexico
M-S-R........................ M-S-R Public Power Agency, a California public
power agency
MW........................... Megawatt
MWh.......................... Megawatt Hour
NMED......................... New Mexico Environment Department
NMPUC........................ New Mexico Public Utility Commission
NRC.......................... United States Nuclear Regulatory Commission
iv
NSPS......................... New Source Performance Standards
NSR.......................... New Source Review
OCD.......................... New Mexico Oil Conservation Division
PGAC......................... The Company's Purchased Gas Adjustment Clause
PG&E......................... Pacific Gas and Electric Company
PLP.......................... Cobisa-Person Limited Partnership
PPA.......................... Power Purchase Agreement
PRC.......................... New Mexico Public Regulation Commission,
successor of the NMPUC
Processing Company........... Sunterra Gas Processing Company, a wholly-owned
subsidiary of Public Service Company of
New Mexico
PSD.......................... Prevention of Significance Determination
PVNGS........................ Palo Verde Nuclear Generating Station
RCRA......................... Resource Conservation and Recovery Act
RHC.......................... Republic Holding Company
RSB.......................... Republic Savings Bank
RTO.......................... Regional Transmission Organization
Reeves Station............... Reeves Generating Station
Salt River Project........... Salt River Project Agricultural Improvement and
Power District
SCE.......................... Southern California Edison Company
SCPPA........................ Southern California Public Power Authority
SDG&E........................ San Diego Gas and Electric Company
SEC.......................... Securities and Exchange Commission
SJCC......................... San Juan Coal Company
SJGS......................... San Juan Generating Station
SPS.......................... Southwestern Public Service Company
TNP.......................... Texas-New Mexico Power Company
Throughput................... Volumes of gas delivered, whether or not owned
by the Company
Tri-State.................... Tri-State Generation and Transmission
Association, Inc.
Tucson....................... Tucson Electric Power Company
UAMPS........................ Utah Associated Municipal Power Systems
USBR......................... United States Bureau of Reclamation
USEC......................... United States Enrichment Corporation
WGA.......................... Western Governors Association
WRAP......................... Western Regional Air Partnership
Waste Act.................... Nuclear Waste Policy Act of 1982, as amended
in 1987
WAPA......................... Western Area Power Administration
Williams..................... Williams Gas Processing-Blanco, Inc., a
subsidiary of the Williams Field Services
Group, Inc., of Tulsa, Oklahoma
v
PART I
ITEM 1. BUSINESS
THE COMPANY
Public Service Company of New Mexico (the "Company") was incorporated in
the State of New Mexico in 1917 and has its principal offices at Alvarado
Square, Albuquerque, New Mexico 87158 (telephone number 505-241-2700). The
Company is a public utility primarily engaged in the generation, transmission,
distribution, sale and trading of electricity and in the transmission,
distribution and sale of natural gas within the State of New Mexico. In
addition, in pursuing new business opportunities, the Company is focusing on
energy and utility related services under Avistar, its wholly-owned unregulated
subsidiary.
On November 9, 2000, the Company and Western Resources, Inc. ("Western
Resources") announced that both companies' boards of directors approved an
agreement under which the Company will acquire the Western Resources electric
utility operations in a tax-free, stock-for-stock transaction. The transaction
is expected to close promptly after all of the conditions to its consummation
are fulfilled, including the spin off to Western Resources' shareholders of
Western Resources' non-utility assets, approval from both companies'
shareholders and customary regulatory approvals. (See Part II, Item 7. -
"Management's Discussion And Analysis Of Financial Condition and Results Of
Operations - Acquisition Of Western Resources Electric Operations").
As of December 31, 2000, the Company employed 2,667 persons.
In response to the changes in the utility industry, the Company has
reorganized its management structure. In 2000, the Company began operating as
three distinct business units: (1) Utility Operations, (2) Generation and
Trading Operations and (3) Unregulated Operations. Utility Operations include
the Electric Product Offering ("Electric") and the Natural Gas Product Offering
("Gas"). Electric consists of the distribution of electricity, as well as all
activities related to the Company's electric transmission operations. Gas
includes the transportation and distribution of natural gas to end-users. Both
offerings include related activities such as marketing and customer service. The
Generation and Trading Operations include all production and purchase of energy,
the sale of wholesale energy to Utility Operations and third parties as well as
energy trading activities. Unregulated Operations provide energy related
services.
Financial information relating to amounts of revenue, net income and
total assets of the Company's business units or reportable segments is contained
in note 1 of the notes to consolidated financial statements.
UTILITY OPERATIONS
Electric
The Company provides jurisdictional retail electric service to a large
area of north central New Mexico, including the COA and the City of Santa Fe,
and certain other areas of New Mexico. For the twelve months ended December 31,
2000, 1999, 1998, 1997 and 1996, retail sales revenues, which include
distribution and transmission sales, were $518.7 million, $522.5 million, $536.4
million, $519.5 million and $507.8 million, respectively, and approximately
1
369,000, 361,000, 358,000, 349,000 and 342,000 retail electric customers,
respectively, were served by the Company. The largest retail electric customer
served by the Company accounted for approximately 4.1% of the Company's total
retail electric revenues for the year ended December 31, 2000.
For the years 1996 through 2000, retail KWh sales have grown at a
compound annual rate of approximately 2.87%. The Albuquerque Chamber of Commerce
forecasts that the COA's population growth will be 5.95% over the next five
years. The Company's system peak demands in summer and winter are shown in the
following table:
SYSTEM PEAK DEMAND
(Megawatts)
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Summer ............... 1,368 1,291 1,313 1,209 1,217
Winter ............... 1,211 1,161 1,135 1,142 1,111
The Company holds long-term, non-exclusive franchise agreements for its
electric retail operations, expiring between July 2001, and November 2028. These
franchise agreements provide the Company access to public rights-of-way for
placement of the Company's electric facilities. The COA, City of Santa Fe, Town
of Cochiti Lake, Bernalillo County, Luna County, Sandoval County and San Miguel
County franchises have expired. Customers in the areas covered by the expired
franchises represent in the aggregate approximately 73.13% of the Company's 2000
total electric operating revenues, and no other franchise area represents more
than 8.35%. The Company continues to collect and pay franchise fees to the COA,
City of Santa Fe and the Town of Cochiti Lake. The Company currently does not
pay franchise fees to Bernalillo County, Luna County, Sandoval County and San
Miguel County. The Company remains obligated under state law to provide service
to customers in the franchise area even in the absence of a franchise agreement.
Electric procures all of its electric power needs from the Company's
Generation and Trading Operations. These intersegment sales are priced using
internally developed transfer pricing and are not based on market rates.
Customer electric rates are regulated by the PRC and determined on a basis that
includes the recovery of the cost of power production by the Company's
Generation and Trading Operations and a return on the related assets, among
other things.
The Company owns or leases 2,781 circuit miles of transmission lines,
interconnected with other utilities east into Texas, west into Arizona, and
north into Colorado and Utah. Due to rapid load growth in the Company's service
territory in recent years, most of the capacity on this transmission system is
fully committed and there is no additional access available on a firm commitment
basis. These factors, together with significant physical constraints in the
system, limit the ability to wheel power into the Company's service area from
outside the state.
Gas
Service Area and Customers
The Company's Gas operations distribute natural gas to most of the major
communities in New Mexico, including the COA and the city of Santa Fe, serving
2
approximately 435,000, 426,000, 419,000, 410,000 and 401,000 customers as of
December 31, 2000, 1999, 1998, 1997 and 1996, respectively. The COA metropolitan
area accounts for approximately 52% of the total sales-service customers. The
Company holds long-term, non-exclusive franchises with varying expiration dates
in all incorporated communities requiring franchise agreements except for the
COA, the franchise agreement for which expired on January 28, 1998. The
Company's customer base includes both sales-service customers and
transportation-service customers.
Sales-service customers purchase natural gas and receive transportation
and delivery services from the Company for which the Company receives both
cost-of-gas and cost-of-service revenues. Cost-of-gas revenues collected from
on-system sales-service customers are recovered in accordance with PRC rules and
regulations and represent a pass-through of the Company's cost of natural gas to
the customer. Since the Company obtains its natural gas supply on the open
market from non-affiliated third-party producers, the Company's operating
results are not affected by an increase or decrease in natural gas prices.
Additionally, the Company makes occasional gas sales to off-system customers.
Off-system sales deliveries generally occur at interstate pipeline interconnects
with the Company's system.
Transportation-service customers, who procure gas independently of the
Company and contract with the Company for transportation and related services,
provide the Company with cost-of-service revenues only. Transportation services
are provided to gas marketers, producers and end users for delivery to locations
throughout the Company's distribution systems, as well as for delivery to
interstate pipelines. The Company provided gas transportation deliveries to
approximately 1,251 gas marketers, producers and end users during 2000.
For the twelve months ended December 31, 2000, the Company's Gas
operations had throughput of approximately 95.0 million decatherms, including
sales of 50.1 million decatherms to both sales-service customers and off-system
customers. No single sales-service customer accounted for more than 5.8% of the
Company's therm sales in 2000. During 2000, approximately 47% of the Company's
total gas throughput was related to transportation gas deliveries. The Company's
transportation rates are unbundled, and transportation customers only pay for
the service they receive. The Company's total gas operating revenues for the
year ended December 31, 2000, were approximately $320 million. Cost-of-gas
revenues, received from sales-service and off-system customers, and other PGAC
related revenues accounted for approximately 59.9% of the Company's total gas
operating revenues. Since a major portion of the Company's load is related to
heating, levels of therm sales are affected by weather. Approximately 52% of the
Company's total therm sales in 2000 occurred in the months of January, February,
November and December.
Natural Gas Supply
The Company obtains its supply of natural gas primarily from sources
within New Mexico pursuant to contracts with third party producers and
marketers. These contracts are generally sufficient to meet the Company's
peak-day demand. The Company serves certain cities which depend on EPNG or
Transwestern Pipeline Company for transportation of gas supplies. Because these
cities are not directly connected to the Company's transmission facilities, gas
transported by these companies is the sole supply source for those cities. Such
transportation is regulated by FERC. As a result of FERC Order 636, the
Company's options for transporting gas to such cities and other portions of its
distribution system have increased.
3
Natural Gas Sales
The following table shows gas throughput by customer class:
GAS THROUGHPUT
(Millions of decatherms)
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Residential .................. 29.1 29.3 30.3 30.7 27.4
Commercial ................... 10.0 10.1 10.4 10.6 9.3
Industrial ................... 5.0 2.3 1.5 1.3 2.1
Public authorities ........... 3.0 2.9 3.4 4.2 2.6
Irrigation ................... 1.8 1.4 1.9 1.6 1.4
Sales for resale ............. 0.1 1.2 1.2 1.2 0.8
Unbilled ..................... (0.5) 3.8 (1.3) (0.2) 1.4
Transportation* .............. 45.0 40.2 36.4 34.0 47.1
Off-system sales ............. 1.5 1.1 1.9 1.2 8.0
---- ---- ---- ---- -----
95.0 92.3 85.7 84.6 100.1
==== ==== ==== ==== =====
The following table shows gas revenues by customer class:
GAS REVENUES
(Thousands of dollars)
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Residential ........... $191,095 $148,968 $161,153 $187,563 $129,911
Commercial ............ 52,926 36,528 42,680 50,502 33,022
Industrial ............ 24,208 8,550 4,887 4,536 5,179
Public authorities .... 13,704 9,782 12,610 17,577 8,018
Irrigation ............ 8,016 4,229 5,780 5,041 3,252
Sales for resale ...... 381 2,530 3,596 4,465 2,106
Unbilled .............. 174 4,107 (955) (2,172) 2,678
Transportation* ....... 14,163 12,390 13,464 14,172 17,215
Liquids ............... 4,513 1,867 1,463 4,451 7,608
Off-system sales ...... 5,291 2,357 3,816 1,926 14,352
Other ................. 5,453 5,403 7,481 6,708 3,960
-------- -------- -------- -------- --------
$319,924 $236,711 $255,975 $294,769 $227,301
======== ======== ======== ======== ========
* Customer owned gas
GENERATION AND TRADING OPERATIONS
The Company's Generation and Trading Operations serve four principal
markets. Sales to the Company's Utility Operations to cover jurisdictional
electric demand and sales to firm-requirements wholesale customers, sometimes
referred to collectively as "system" sales, comprise two of these markets.
Intersegment sales to the Utility Operations are priced using internally
developed transfer pricing and are not based on market rates. The third market
4
consists of other contracted sales to third parties for which the Generation and
Trading Operations commit to deliver a specified amount of capacity (measured in
megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of
time. The fourth market consists of energy sales from excess capacity made on an
hourly basis at fluctuating, spot-market rates. Sales to the third and fourth
markets are sometimes referred to collectively as "off-system" sales. These
sales include the Company's wholesale power trading activities. The Company is
connected to the Western area power grid, which includes California and the
surrounding states, and therefore its wholesale power sales are into this
market. The Western United States power market in 2000 and 2001 has been
extremely volatile due to a power supply shortage and other constraints
associated with the Western United States electricity market. (See Part II, Item
7 - Management's Discussion and Analysis of Financial Condition and Results of
Operations - Other issues facing the Company - Western United States Wholesale
Power Market.)
Power Sales
A significant portion of the Company's earnings is derived from its
off-system sales. The Company has been very successful in developing its
wholesale power trading activities in the Western United States. Management
believes this success is due to its business strategy of providing electric
power customized to meet the needs of large customers who by their size are
unable to develop special products to meet unique size, timing, or transmission
needs. This niche marketing strategy is based on the Company's strategic
transmission capabilities and an asset-backed trading methodology whereby the
Company's net open position is always supported by its generation capacity
excluded from its jurisdictional rates or by its excess capacity. This
asset-backed trading methodology helps to mitigate the risks inherent in the
Company's trading activities. The Company also utilizes long-term transactions
to enhance its product offering.
A significant portion of the Company's growth strategy is based on growth
in off-system sales. The Company's business plan calls for the expansion of its
wholesale power trading operation and the acquisition or development of
additional generating capacity to support this growth under the Company's
asset-backed trading methodology. This growth strategy provided the basis for
the proposed acquisition of Western's utility assets.
The following table shows electric sales by customer class:
GENERATION AND TRADING SALES BY MARKET
(Megawatt hours)
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Intersegment sales ................. 7,088,943 6,803,583 6,739,874 6,534,899 6,406,296
Firm-requirements wholesale ........ 193,853 179,249 278,615 278,727 282,534
Other contracted off-system sales .. 7,385,266 6,196,499 4,033,931 3,790,081 2,928,321
Hourly energy sales ................ 4,773,009 4,795,873 4,469,769 2,716,835 1,364,365
---------- ---------- ---------- ---------- ----------
19,441,071 17,975,204 15,522,189 13,320,542 10,981,516
========== ========== ========== ========== ==========
5
The following table shows revenues by customer class:
GENERATION AND TRADING REVENUES BY MARKET
(Thousands of dollars)
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Intersegment sales ................. $ 324,744 $ 318,872 $ 362,722 $ 370,019 $ 380,000
Firm-requirements wholesale ........ 6,568 7,046 10,708 10,690 12,359
Other contracted off-system sales .. 371,900 226,773 142,115 118,876 86,689
Hourly energy sales ................ 369,724 131,549 122,156 55,768 22,281
Other .............................. 2,242 5,741 4,657 14,269 13,374
---------- ---------- ---------- ---------- ----------
$1,075,178 $ 689,981 $ 642,358 $ 569,622 $ 514,703
========== ========== ========== ========== ==========
Certain of the Company's generation assets are excluded from
jurisdictional electric rates. In 1988, the NMPUC excluded 130MW of San Juan
Unit 4, all of PVNGS Unit 3 and a power purchase contract, which expired in
1995. As a result, the Company developed a bulk power marketing and trading
operation to sell the generation from its excluded assets that no longer
generated a return in rate base. These activities include the forward purchase
and sale of electricity to take advantage of market price opportunities in the
electric wholesale market. The Company's wholesale power marketing area
continues to increase its scope of trading activities. During 2000, 1999 and
1998, the Company's sales in the off-system markets accounted for approximately
63%, 61% and 55%, respectively, of its total KWh sales and approximately 69%,
52% and 41%, respectively, of its total revenues from Generation and Trading
sales. Of the total off-system sales made in 2000 and 1999, 78% were transacted
through purchases for resale.
In 1990, the NMPUC established an off-system sales methodology that
provided for a sharing mechanism between the included and excluded generation
assets and power purchase contracts. Subsequent rate cases to the present
continued to utilize this methodology. As a result, since 1990 electric
customers have received over $300 million in rate benefits from the Company's
wholesale power marketing activities. This is without consideration of the
benefits inherent in the jurisdictional load growth. As of December 31, 1998,
the assets included in the electric customer rate base no longer had any excess
capacity for purposes of certain portions of the sharing mechanism. The last
rate case (see Rates and Regulation - Electric Rates and Regulation - Electric
Rate Case) froze rates, without possibility of change in rates prior to January
1, 2003.
The Company has entered into various firm off-system sales contracts.
These contracts contain fixed capacity charges in addition to energy charges.
The SDG&E contract requires SDG&E to purchase 100 MW from the Company through
April 2001. The APPA contract requires APPA to purchase varying amounts of power
from the Company through May 2008 and allows APPA to make adjustments to the
purchase amounts subject to certain notice provisions. APPA invoked its option
to reduce its peak demand in 2000 from 74 MW to 68 MW. For 2001, APPA has
invoked its option to increase its peak demand to 92 MW. The Company furnished
firm-requirements wholesale power in New Mexico in 2000 to the City of Gallup.
The Company is committed to provide service to the City of Gallup through April
2003. Average monthly demands under the City of Gallup contract for 2000 were
approximately 27 MW. Beginning July 2000, the Company began serving Navopache
Electric Cooperative firm requirements service under the provisions of a 10 year
contract. Average monthly demand for Navopache is expected to be 50 MW. No firm
requirements wholesale customer accounted for more than 0.9% of the Company's
total electric sales for resale revenues for the year ended December 31, 2000.
6
Sources of Power
As of December 31, 2000, the total net generation capacity of facilities
owned or leased by the Company was 1,521 MW, excluding the PPA discussed below
which would bring the total to 1,653 MW. The Company is committed to increasing
its utilization of its major generation capacity at SJGS, Four Corners and
PVNGS. SJGS is directly operated by the Company. In 2000, the plant's equivalent
availability and capacity factor performance ranked in the 95th percentile of
the 403 coal-fired power plants in the nation. SJGS's equivalent availability
and capacity factor were 88.9% and 85.6%, respectively, for the twelve months
ended December 31, 2000 and 95.1% and 92.6% for the third quarter of 2000 when
demand in the Western United States was at its highest. Capacity factors for
Four Corners and PVNGS were 84.2% and 92.7%, respectively, in 2000, as compared
to 86.9% and 93.2%, respectively, in 1999. Four Corners and PVNGS are operated
by APS. (See Item 2. Properties).
In addition to generation capacity, the Company purchases power in the
market. The Company has a power purchase contract with SPS which originally
provided for the purchase of up to 200 MW and expires in May 2011. The Company
may reduce its purchases from SPS by 25 MW annually upon three years notice. The
Company provided such notice to reduce its 1999 and 2000 purchases by 25 MW. The
Company has 70 MW of contingent capacity obtained from El Paso under a
transmission capacity for generation capacity trade arrangement through May
2004. Beginning June 2004 and continuing through June 2005 the capacity amount
is 39 MW. In addition, the Company is interconnected with various utilities for
economy interchanges and mutual assistance in emergencies. The Company actively
trades in the wholesale power market and has entered into and anticipates that
it will continue to enter into power purchases to accommodate its trading
activity.
In 1996, the Company entered into a long-term PPA for the rights to all
the output of a new gas-fired generating plant. The plant has received FERC
approval for "exempt wholesale generator" status with respect to the gas turbine
generating unit. The PPA's maximum dependable capacity is 132 MW. In July 2000,
the plant went into operation. The gas turbine generating unit is operated by
Delta and is located on the Company's retired Person Generating Station site in
COA. The site for the generating unit was chosen, in part, to provide needed
benefits to the Company's constrained transmission system. Primary fuel for the
gas turbine generating unit is natural gas, which is provided by the Company. In
addition, the unit has the capability to utilize low sulfur fuel oil in the
event natural gas is not available or cost effective. For accounting purposes,
the PPA is treated as an operating lease.
7
Fuel and Water Supply
The percentages of the Company's generation of electricity (on the basis
of KWh) fueled by coal, nuclear fuel and gas and oil, and the average costs to
the Company of those fuels (in cents per million BTU), during the past five
years were as follows:
Coal Nuclear Gas and Oil
--------------------- -------------------- --------------------
Percent of Average Percent of Average Percent of Average
---------- ------- ---------- ------- ---------- -------
1996......... 68.9 159.3 30.4 49.7 0.7 238.2
1997......... 68.1 152.7 31.1 48.3 0.8 326.6
1998......... 68.2 155.3 30.8 46.5 1.0 324.6
1999......... 67.6 165.3 31.0 47.4 1.4 331.9
2000......... 68.0 165.3 29.8 45.4 2.2 482.6
The estimated generation mix for 2001 is 67.3% coal, 29.6% nuclear and
3.1% gas and oil. Due to locally available natural gas and oil supplies, the
utilization of locally available coal deposits and the generally abundant supply
of nuclear fuel, the Company believes that adequate sources of fuel are
available for its generating stations into the foreseeable future.
Coal
The coal requirements for the SJGS are being supplied by SJCC, a
wholly-owned subsidiary of BHP, who holds certain Federal, state and private
coal leases under a Coal Sales Agreement, pursuant to which SJCC will supply
processed coal for operation of the SJGS until 2017. BHP guaranteed the
obligations of SJCC under the agreement, which contemplates the delivery of
approximately 87 million tons of coal during its remaining term. That amount
would supply substantially all the requirements of the SJGS through
approximately 2017.
The revised coal contract is expected to save the Company between $400
million and $500 million in fuel costs over the next 17 years. Besides saving on
fuel costs, the cleaner-burning, less abrasive coal is expected to reduce the
Company's share of the plant's maintenance and operating expenses by
approximately $2 million per year. The plant is expected to realize some of the
benefits of the higher quality coal next year, as the existing surface mines are
phased out and the underground mine is developed. The underground mine is
scheduled to be in full production by November 2002.
The Company has reached an agreement with SJCC and Tucson to replace
these two surface mining operations with a single underground mine located
adjacent to the plant. Underground mining is expected to provide a higher
quality coal at a lower cost per ton. The new mine will use the longwall mining
technique and is expected to ramp to full station supply by the end of 2002.
Four Corners is supplied with coal under a fuel agreement between the
owners and BHP, under which BHP agreed to supply all the coal requirements for
the life of the plant. The current fuel agreement expires December 31, 2004. It
is anticipated that negotiations for an extension will be initiated in the near
future. BHP holds a long-term coal mining lease, with options for renewal, from
the Navajo Nation and operates a surface mine adjacent to Four Corners with the
coal supply expected to be sufficient to supply the units for their estimated
useful lives.
8
Natural Gas
The natural gas used as fuel for the Company's COA electric generating
plant (Reeves Station and the PPA) is delivered by the Company's Natural Gas
Product Offering. (See "Natural Gas Product Offering"). In addition to rate
changes under filed tariffs, the Company's cost of gas increases or decreases
according to the average cost of the available gas supply. The Company's
Generation and Trading operations commenced a program to reduce its exposure to
fluctuations in prices for natural gas as a fuel source for its generation. The
2000 fuel hedge program ended in October 2000. In 2001, the fuel hedge season
will begin in April for 9 of 12 months. (See Footnote 5 to the Consolidated
Financial Statements).
Nuclear Fuel
The fuel cycle for PVNGS is comprised of the following stages:
o the mining and milling of uranium ore to produce uranium
concentrates,
o the conversion of uranium concentrates to uranium hexafluoride,
o the enrichment of uranium hexafluoride,
o the fabrication of fuel assemblies,
o the utilization of fuel assemblies in reactors, and
o the storage and disposal of spent fuel.
The PVNGS participants have made contractual arrangements to obtain
quantities of uranium concentrates anticipated to be sufficient to meet
operational requirements through 2002. Existing contracts and options could be
utilized to meet approximately 88% of requirements in 2003, 88% of requirements
in 2004, 49% of requirements in 2005, and 16% of requirements from 2006 and
beyond. Spot purchases on the uranium market will be made, as appropriate, in
lieu of any uranium that might be obtained through contractual options.
The PVNGS participants have contracted for uranium conversion services.
Existing contracts and options could be utilized to meet approximately 70% of
requirements in 2000, 75% of requirements in 2001, 80% of requirements in 2002
and zero percent of requirements thereafter. The PVNGS participants have an
enrichment services contract and an enriched uranium product contract that
furnish enrichment services required for the operation of the three PVNGS units
through 2003. In addition, existing contracts will provide fuel assembly
fabrication services through 2015 for each Palo Verde unit.
Water Supply
Water for Four Corners and SJGS is obtained from the San Juan River.
(See Item 3. - "Legal Proceedings- San Juan River Adjudication".) BHP holds
rights to San Juan River water and committed a portion of those rights to Four
Corners through the life of the plant. The Company and Tucson have a contract
with the USBR ("USBR Contract") for consumption of 16,200 acre feet of water per
year for the SJGS. The contract expires in 2005. In addition, the Company was
granted the authority to consume 8,000 acre feet of water per year under a state
permit that is held by BHP. The Company is of the opinion that sufficient water
is under contract for the SJGS through 2005.
In January 1993, the U.S. Fish and Wildlife Service proposed a portion
of the San Juan River as critical habitat for two fish species. This designation
may impact uses of the river and its flood plains and will require certain
analysis under the Endangered Species Act of 1973 of all significant Federal
9
actions. Renewal of the SJGS water contract would be considered a significant
Federal action for these purposes.
In June 1996, the Navajo Nation requested that the USBR withhold renewal
of the USBR Contract due to water shortages of the Navajo Indian Irrigation
Project. Other tribes in the Four Corners area also voiced concern to the USBR
about the renewal by the Company of the USBR Contract. Due to the tribal
concerns expressed, the Company began four-way discussions with the Jicarilla
Apache Nation ("Jicarilla"), the Navajo Nation and USBR in July 1999 to resolve
any outstanding issues related to the Company's proposed renewal of the USBR
Contract. Those discussions are ongoing but have resulted in the Company
pursuing an alternative water supply to replace the USBR Contract when it
expires in 2005.
In 2000, the Company signed a twenty-two year contract with Jicarilla,
beginning in 2006, for the full 16,200 acre feet of water from the Jicarilla
supply in Navajo Reservoir ("Jicarilla Contract"). The Jicarilla Contract is
essentially equivalent to a renewed USBR Contract, the only material difference
being that Jicarilla as opposed to USBR would be the contract supplier.
Jicarilla has contract water in Navajo Reservoir pursuant to a water rights
settlement approved by Congress in 1992 and a judicial decree that was entered
February 24, 1999. The contract must still be approved by the USBR and is also
subject to environmental approvals. Unlike a renewed USBR Contract, the Company
would not be required to seek Congressional approval of a Jicarilla Contract.
Additionally, the Company is in discussions with the Navajo Nation to
settle claims the tribe may assert in connection with any environmental
approvals that may be required for a Jicarilla Contract. The Jicarilla Contract
is considered a Federal action that will require National Environmental Policy
Act compliance as well as a Section 7 consultation under the Endangered Species
Act. At this time, although the Company cannot predict the outcome of these
discussions, it does not believe that a settlement with the Navajo Nation will
have a material adverse effect on the Company's financial position or its
results of operations.
The Company is actively involved in the San Juan River Recovery
Implementation Program ("Recovery Program") to mitigate any concerns with the
taking of the USBR Contract or proposed Jicarilla Contract water supply from a
river that contains endangered fish species and their critical habitat. In April
of 1999, the Recovery Program voted to fund modifications to the Company's weir
to accommodate fish travel in that area of the river. Funding is expected to be
supplied by USBR. Design studies are ongoing and the project is expected to
commence in 2001.
Sewage effluent used for cooling purposes in the operation of the PVNGS
units is obtained under contracts with certain municipalities in the area. The
contracted quantity of effluent exceeds the amount required for the three PVNGS
units. The validity of these effluent contracts is the subject of litigation in
state court. (See Item 3. - "Legal Proceedings - PVNGS Water Supply
Litigation".)
UNREGULATED OPERATIONS
The Company, through its wholly-owned subsidiary Avistar, has initiated
several unregulated service and information related business lines to serve
energy intensive customers. The business lines focus on energy efficient,
advanced metering solutions and emerging technology platforms that are related
10
to the Company's core energy businesses. In June 1999, the NMPUC issued a final
order approving the Company's request to form and invest in a wholly-owned
subsidiary, Avistar. Under the final order, the Company is permitted to invest a
maximum of $50 million in the subsidiary, subject to the availability of the
Company's retained earnings and to enter into reciprocal loan agreement for up
to $30 million. To date, the Company has invested $35 million into Avistar's
operations.
Avistar acquired approximately a 25% ownership interest in AMDAX.com in
January 2000. AMDAX has developed a proprietary auction platform designed to
efficiently bring together electricity buyers and sellers in the deregulated
natural gas and electricity markets. The rapidly evolving energy crisis in
California has adversely affected AMDAX's business prospects and expected
performance. Accordingly, the Company has recognized a valuation loss in 2000 to
reflect the change in business prospects and market values of e-business
entities.
In the second quarter of 2000, Avistar invested $1 million in Nth Power
Technologies ("Nth Power"), a venture capital firm focused on high-growth
opportunities arising from the restructuring of the global energy marketplace.
Avistar has a commitment to invest an additional $4 million. Nth Power has
invested in a broad range of companies that are well positioned to lead in the
emerging energy markets. The areas of investment include: distributed generation
and storage; communications, control and information technology; end-use
products; power quality; transmission and distribution automation; and
outsourcing and business services.
In December 2000, Avistar invested $10 million for a 5% ownership
interest in MainStreet Networks, an Internet Gateway Service Provider. Together
with local utilities, MainStreet Networks plans to provide low-cost,
Internet-based services to homes through an Internet gateway attached at the
customer's electric meter. The gateway captures meter reading data for the local
utility. The gateway, in connection with an internet appliance developed by
Mainstreet, allows customers to send and receive e-mail messages, shop online
and access national news and customized community news and content.
DEREGULATION AND FORMATION OF HOLDING COMPANY
Introduction of competitive market forces and restructuring of the
electric utility industry in New Mexico continue to be key issues facing the
Company. New Mexico's Electric Utility Industry Restructuring Act of 1999 (the
"Restructuring Act"), which was enacted into law in April 1999, would begin to
open the state's electric power market to customer choice beginning in 2002. The
Restructuring Act would give schools, residential and small business customers
the opportunity to choose among competing power suppliers beginning in January
2002. Competition would be expanded to include all customers starting in July
2002. Rural electric cooperatives and municipal electric systems have the option
not to participate in the competitive market.
Under the Restructuring Act, residential and small business customers who
do not select a power supplier in the open market would buy their electricity
through their local utility through "standard offer service" whereby the local
distribution utility would procure power supplies through a process approved by
the PRC. The local distribution utility system and related services such as
billing and metering would continue to be regulated by the PRC, while
transmission services and wholesale power sales would remain subject to Federal
regulation.
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The Restructuring Act does not require utilities to divest their
generating plants, but requires certain deregulated activities to be separated
from activities regulated by the PRC through creation of at least two separate
corporations. The Company plans to reorganize its operations by forming a
holding company structure as a means of achieving the corporate and asset
separation required by the Restructuring Act. The Company's plan for a holding
company structure would separate the Company into two subsidiaries. In June
2000, shareholders approved the mandatory share exchange necessary to implement
the holding company structure. If the Company receives all necessary regulatory
and other approvals, all of the Company's electric and gas distribution and
transmission assets and certain related liabilities would be transferred to a
newly created subsidiary. After this asset transfer, this subsidiary will
acquire the name "Public Service Company of New Mexico" (for purposes of this
discussion, the subsidiary is referred to as "UtilityCo") and the corporation
formerly named Public Service Company of New Mexico will be renamed Manzano
Energy Corporation (for purposes of this discussion, the subsidiary is referred
to as "PowerCo"). PowerCo would continue to own the Company's existing electric
generation and certain other unregulated, competitive assets after completion of
the transfer of the regulated business to the newly created utility subsidiary.
UtilityCo, PowerCo and Avistar would be wholly-owned subsidiaries of the holding
company.
The New Mexico Legislature is currently considering various legislation
that could delay open access for "customer choice" and other activities under
the Restructuring Act, including corporate separation. For a discussion on the
status of the formation of the holding company and corporate separation, see
Part II, Item 7. - "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Other Issues Facing the Company - The Restructuring
Act, The Formation of the Holding Company and Corporate Separation".
PROPOSED RULEMAKINGS RELATED TO DEREGULATION
In 1999, the PRC proposed certain rules that would apply to all
utilities in implementing the Restructuring Act. These included a Code of
Conduct that would govern relationships between a utility and its affiliate
providing competitive power supply service, a Standard Offer Service rule
governing utility procurement of generation service for certain customers who
choose not to shop for power supply, a Customer Protection rule to address
certain customer service procedures and potential problems associated with open
access and a Competitive Power Supplier Licensing rule to provide PRC licensure
of power supply merchants and brokers in the state. The Code of Conduct rule and
the Standard Offer Service rule have been approved by the PRC, although it is
considering whether to modify them due to turmoil in the California energy
market. The Customer Protection and Competitive Power Supplier Licensing rules
are awaiting final PRC action finalization.
COMPETITION UNDER DEREGULATION
Under current law, the Company is not in any direct retail competition
with any other regulated electric and gas utility. Nevertheless, the Company is
subject to varying degrees of competition in certain territories adjacent by or
within areas it serves that are also currently served by other utilities in its
region as well as cooperatives, municipalities, electric districts and similar
types of government organizations.
12
As a result of the Restructuring Act in New Mexico, the Company may face
competition from companies with greater financial and other resources in 2002.
There can be no assurance that the Company will not face competition in the
future that would adversely affect its results.
The New Mexico Legislature is currently considering legislation that
could delay open access and other activities under the Restructuring Act,
including corporate separation. A delay without providing business flexibility
could have a negative effect on the Company's ability to compete in the
wholesale power market. Under the current regulatory environment in New Mexico,
the Company may be unable to achieve the necessary business flexibility it
requires to take advantage of business opportunities to execute its growth
strategy. There can be no assurance that the Company can successfully compete in
the wholesale power marketplace and continue to execute its growth strategy if
implementation of the Restructuring Act is rolled back. This legislation; Senate
Bill 266, as originally introduced, simply delayed restructuring for five years.
However, during the course of committee hearings and floor debate, the bill was
amended so as to provide significant business flexibility to utilities despite
the delay. As amended, Senate Bill 266 passed the Senate 39-0 and is now pending
in the House of Representatives. The final outcome of the legislative process is
currently unknown, however, a final resolution is expected in the spring of
2001.
RATES AND REGULATION
The Company is subject to the jurisdiction of the PRC, the successor of
the NMPUC effective January 1, 1999, with respect to its retail electric and gas
rates, service, accounting, issuance of securities, construction of major new
generation and transmission facilities and other matters. The FERC has
jurisdiction over rates and other matters related to wholesale electric sales
and cost recovery of its transmission network.
Electric Rates and Regulation
Electric Rate Case
In November 1998, the NMPUC issued a final order in the Company's
electric rate case, requiring the Company to reduce rates in 1999 by $60.2
million, by $25.6 million in 2000 and by an additional $25.6 million in 2001.
The rate reduction order reflected, among other things, the revaluation of the
Company's generation resources based on a so-called "market-based price" and the
finding by the NMPUC that recovery of stranded costs is illegal. In December
1998, the Company appealed the rate case order to the New Mexico Supreme Court
("Supreme Court").
On March 15, 1999, the Supreme Court issued a ruling, vacating the NMPUC
order on the Company's electric rate case and remanding the case to the PRC for
further proceedings.
On August 25, 1999, the PRC issued an order approving a settlement. The
PRC ordered the Company to reduce its electric rates by $34.0 million
retroactive to July 30, 1999. In addition, the order included a rate freeze
until retail electric competition is fully implemented in New Mexico or until
January 1, 2003 whichever comes first. The settlement reduced operating revenues
in the years 2000 and 1999 by approximately $39 million and $19 million,
respectively.
As part of the settlement, the Company agreed that certain changes to
the language of the retail tariff under which Kirtland Air Force Base ("KAFB")
currently takes service would be considered in a separate proceeding before the
13
PRC. Hearings on this issue have not yet been scheduled. The PRC is considering
briefs submitted by the parties addressing the scope of the proceeding. KAFB has
not renewed its electric service contract with the Company that expired in
December 1999 but continues to purchase retail service from the Company. (See
Item 3 - Legal Proceedings "KAFB Contract".)
Federal Electric Initiatives
Beginning with the passage of the Public Utilities Regulatory Policy Act
of 1978 and, subsequently, the Energy Policy Act, there has been a significant
increase in the level of competition in the market for the generation and sale
of electricity. The Energy Policy Act reduced barriers to market entry for
companies wishing to build, own and operate electric generating facilities, and
it also promoted competition by authorizing the FERC to require transmission
service for wholesale power transactions. In this regard, in 1996, the FERC
issued Order 888. Among other things, Order 888 required electric utilities
controlling transmission facilities to file open access transmission tariffs
that would make the utility transmission systems available to wholesale sellers
and buyers of electric energy on a non-discriminatory basis.
Order 888 encouraged utilities to investigate the formation of
independent system operators, or ISOs, to operate transmission assets and
provided criteria under which the formation, operation and governance of ISOs
would be reviewed. On December 20, 1999, the FERC issued its Order 2000 on
Regional Transmission Organizations, or RTOs. In this order, the FERC
established timelines for transmission owning entities to join an RTO and
defined the minimum characteristics and functions that an RTO must satisfy.
In January 1998, the Company entered into a development agreement with
other transmission service providers and users to form an ISO in the southwest.
As a result, Desert STAR, Inc. was incorporated as a non-profit organization in
the State of Arizona on September 21, 1999. Desert STAR, Inc. is being developed
to satisfy the FERC functions and characteristics for an approved RTO. The
functions of Desert STAR RTO are envisioned to include the following: (1) tariff
administration and design; (2) congestion management; (3) parallel flow
internalization; (4) ancillary services; (5) total transmission capability and
available transmission capability estimation; (6) market monitoring; (7)
planning and expansion; and (8) inter-regional coordination.
Desert STAR and the FERC jurisdictional transmission owners made an
October 16, 2000 progress report filing with the FERC in compliance with Order
2000. At the time of the progress filing it was anticipated that a complete RTO
filing would be made by Desert STAR on December 29, 2000. On December 28, 2000,
Desert STAR made an additional filing with the FERC stating that a complete
December 29, 2000 filing was no longer possible and that March 31, 2001 would be
a more realistic deadline. The FERC was also informed that operations would not
commence until late 2002.
A significant number of stakeholder, advisory and Desert STAR Board of
Director meetings are on-going with the goal of resolving remaining issues and
preparing a complete FERC filing at the earliest possible date.
14
Gas Rates and Regulation
Gas Rate Case Appeals
In 1995, the Company filed a request for a $13.3 million increase in its
retail natural gas sales and transportation rates. In 1997, the NMPUC issued a
final order in the gas rate case, ordering a rate decrease. The Company filed an
appeal to the Supreme Court, which ultimately ruled in favor of the Company on
some of these issues. In October 1997, the Company filed a gas rate case in
compliance with an NMPUC order which resulted in a settlement. After a hearing
on the settlement held in May 1998, the NMPUC issued a final order in August
1998, accepting the settlement with certain modifications. The AG appealed the
order to the Supreme Court in October 1998. In March 2000, the Supreme Court
specifically rejected portions of the final order requiring the Company to offer
residential customers a choice of utility access fees.
On October 24, 2000, the PRC issued a final order approving the
stipulation negotiated in the third quarter between the Company and the PRC
staff which resolved all issues raised by the two gas rate cases. The final
order added approximately $1.2 million to the Company's revenues in the final
quarter of 2000 and is expected to add approximately $4.7 million in 2001 and
$3.9 million in 2002. The Company has reversed certain reserves against costs
recovered in the settlement that were recorded against earnings at the time of
the original regulatory orders, resulting in a one-time pre-tax gain of $4.6
million. This amount will be collected from customers in rates over the next 12
years.
PGAC Continuation Filing
The Company's retail gas rate tariffs contain a PGAC that provides
timely recovery for the cost of gas purchased for resale to its sales-service
customers. In a NMPUC order issued in November 1997, the Company was required to
file its next PGAC continuation filing no later than November 23, 1999. In
November 1999, the Company requested a variance to the filing requirement, which
was granted by the PRC that deferred the filing until the issuance of a final
order in the two related cases concerning an investigation into the Company's
gas hedging practices (see "Gas Hedging Investigation" below) and a notice of
proposed rulemaking issued by the PRC that would rewrite the PGAC rule (see "PRC
PGAC Rule Rewrite" below).
Gas Hedging Investigation
In May 1999, the PRC staff and the AG filed a petition, requesting a
review by the PRC of the Company's gas hedging program for the 1998-1999 heating
season and consideration of whether specific guidelines should be established.
For the winter of 1998-1999, the Company had entered into both financial and
physical hedges for a cost of $7.6 million, or 7.5% of total annual purchased
gas costs, to levelize gas costs and protect against spikes. The review centered
on an order from the former NMPUC, in the 1997 PGAC prudence case, in which the
Company was ordered to engage in gas hedging in an effort to levelize and/or
stabilize gas prices without detailed guidelines as to how to do so. A series of
hearings and public workshops was held throughout 1999 and 2000 regarding this
matter.
As a result, the PRC issued an order on November 7, 2000, allowing but not
requiring the Company to implement a financial hedging strategy. The Company
contracted for gas price caps, a type of hedge, to protect its natural gas
customers from price risk during the 2000-2001 heating season. The Company
15
recovered its cost of $5 million during the months of October and November 2000
in equal $2.5 million allotments as a component of the PGAC. The Company
estimates that its hedging strategy has saved its sales-service customers
approximately $27 million for the cost of natural gas, net of the cost of the
price caps.
PRC PGAC Rule Rewrite
Throughout 1999 and continuing through the present, the Company has
worked in a cooperative effort with the Commission staff, the AG, Zia Natural
Gas and Raton Natural Gas to develop a proposed revision to the PRC PGAC rule.
After considerable debate over the proposed new PGAC rule, a revised rule was
proposed in which all parties, including the AG, are in agreement to include the
phrase "lowest reasonable cost" in the proposed rule so long as that phrase is
adequately defined, providing clear direction to the gas utilities in their gas
cost recovery efforts. Should this rule be adopted as proposed, the requirement
that gas utilities make a biannual PGAC continuation filing would be replaced
with a more timely and informative annual supply and demand forecast, planning,
true-up reporting process, and a simplified PGAC continuation filing every four
years. After a hearing and a workshop to discuss minor revisions, a recommended
decision was issued May 15, 2000 by a hearing examiner that supported the rule
as revised. The PRC has not yet rendered a decision accepting the recommended
decision.
ENVIRONMENTAL MATTERS
The Company, in common with other electric and gas utilities, is subject
to stringent laws and regulations for protection of the environment by local,
state, Federal and tribal authorities. In addition, PVNGS is subject to the
jurisdiction of the NRC, which has authority to issue permits and licenses and
to regulate nuclear facilities in order to protect the health and safety of the
public from radioactive hazards and to conduct environmental reviews pursuant to
the National Environmental Policy Act. Liabilities under these laws and
regulations can be material and, in some instances, may be imposed without
regard to fault, or may be imposed for past acts, even though such acts may have
been lawful at the time they occurred.
The Clean Air Act
On July 1, 1999, the EPA published its final regional haze regulations.
The purpose of the regional haze regulations is to address regional haze
visibility impairment in the 156 Class 1 areas in the nation, which consist of
National Parks, wilderness areas and other similar areas. The final rule calls
for all states to establish goals and emission reduction strategies for
improving visibility in all the Class 1 areas. The Company cannot predict at
this time what the impact of the implementation of the regional haze rule will
be on the Company's coal-fired power plant operations. Potentially, additional
SO2 emission reductions could be required in the 2013-2018 timeframe. The nature
and cost of the impacts of these requirements cannot be determined at this time.
However, the Company does not anticipate any material adverse impact on the
Company's financial condition or results of operations.
New Source Review Rules
The EPA has proposed changes to its New Source Review ("NSR") rules that
could result in many actions at power plants that have previously been
considered routine repair and maintenance activities (and hence not subject to
the application of NSR requirements) as now being subject to NSR. In November
16
1999, the Department of Justice, at the request of the EPA, filed complaints
against seven companies alleging the companies over the past 25 years had made
modifications to their plants in violation of the NSR requirements, and in some
cases the New Source Performance Standards ("NSPS") regulations. Whether or not
the EPA will prevail is unclear at this time. The EPA has reached a settlement
with one of the companies sued by the Justice Department and is in the process
of attempting to negotiate settlements with another of those companies. No
complaint has been filed against the Company, and the Company believes that all
of the routine maintenance, repair, and replacement work undertaken at its power
plants was and continues to be in accordance with the requirements of NSR and
NSPS. However, by letter dated October 23, 2000, the NMED made an information
request of the Company, advising the Company that the NMED was in the process of
assisting the EPA in the EPA's nationwide effort "of verifying that changes made
at the country's utilities have not inadvertently triggered a modification under
the Clean Air Act's Prevention of Significant Determination ("PSD") policies."
The Company has responded to the NMED information request.
The nature and cost of the impacts of EPA's changed interpretation of
the application of the NSR and NSPS, together with proposed changes to these
regulations, may be significant to the power production industry. However, the
Company cannot quantify these impacts with regard to its power plants. It is
also unknown what changes in EPA policy, if any, may occur in the NSR area as a
result of the change in administrations in Washington. If the EPA should prevail
with its current interpretation of the NSR and NSPS rules, the Company may be
required to make significant capital expenditures which could have a material
adverse effect on the Company's financial position and results of operations.
Santa Fe Generating Station ("Santa Fe Station")
The Company and the NMED conducted investigations of the gasoline and
chlorinated solvent groundwater contamination detected beneath the Company's
former Santa Fe Station site to determine the source of the contamination
pursuant to a 1992 Settlement Agreement ("Settlement Agreement") between the
Company and the NMED. No source of groundwater contamination was identified as
originating from the site. However, in June 1996, the Company received a letter
from the NMED, indicating that the NMED believed the Company is the source of
gasoline contamination in a City of Santa Fe municipal supply well and of
groundwater underlying the Santa Fe Station site. Further, the NMED letter
stated that the Company was required to proceed with interim remediation of the
contamination pursuant to the New Mexico Water Quality Control Commission
regulations.
In October 1996, the Company and the NMED signed an amendment to the
Settlement Agreement concerning the groundwater contamination underlying the
site. As part of the amendment, the Company agreed to spend approximately $1.2
million for certain costs related to sampling, monitoring and the development
and implementation of a remediation plan.
The amended Settlement Agreement does not, however, provide the Company
with a full and complete release from potential further liability for
remediation of the groundwater contamination. After the Company has expended the
settlement amount, if the NMED can establish through binding arbitration that
the Santa Fe Station is the source of the contamination, the Company could be
required to perform further remediation that is determined to be necessary. The
Company continues to dispute any contention that the Santa Fe Station is the
source of the groundwater contamination and believes that insufficient data
exists to identify the sources of groundwater contamination. The Company's
17
aquifer characterization and groundwater quality reports compiled from 1996
through 2000 strongly suggest groundwater contamination has been drawn under the
site by the pumping of the Santa Fe supply well.
The Company and the NMED, with the cooperation of the City of Santa Fe,
jointly selected a 3 to 4 year remediation plan proposed by a remediation
contractor. The City of Santa Fe, the Company and the NMED entered into a
memorandum of understanding concerning the selected remediation plan and the
operation of the municipal well adjacent to the Santa Fe Station site in
connection with carrying out the plan. On October 5, 1998, a new system began
operation to treat groundwater produced by the Santa Fe well to drinking water
standards for municipal distribution and bioremediation of groundwater
contamination beneath the Santa Fe Station site. Since the reactivation of the
Santa Fe well, the groundwater treatment and bioremediation systems have
resulted in a marked reduction in contaminant concentrations at the wellhead.
However, contaminant concentrations at the property boundary remain high.
Person Station
The Company, in compliance with a Corrective Action Directive issued by
the NMED, determined that groundwater contamination exists in the deep and
shallow groundwater at the Company's Person Station site. The Company is
required to delineate the extent of the contamination and remediate the
contaminants in the groundwater at the Person Station site. The extent of
shallow and deep groundwater contamination was assessed and the results were
reported to the NMED. The Company has received the renewal of the RCRA
post-closure care permit for the facility. Remedial actions for the shallow and
deep groundwater were incorporated into the new permit. The Company has
installed and is operating a pump and treat system for the shallow groundwater.
The renewed RCRA post-closure care permit allows remediation of the deep
groundwater contamination through natural attenuation. The Company's current
estimate to decommission its retired fossil-fueled plants (discussed below)
includes approximately $4.6 million in additional expenses to complete the
groundwater remediation program at Person Station. As part of the financial
assurance requirement of the Person Station Hazardous Waste Permit, the Company
established a trust fund. The current value of the trust fund at December 31,
2000, was approximately $4.8 million. The remediation program continues on
schedule.
Fossil-Fueled Plant Decommissioning Costs
The Company's six owned or partially owned, in service and retired,
fossil-fueled generating stations are expected to incur dismantling and
reclamation costs as they are decommissioned. The Company's share of
decommissioning costs for all of its fossil-fueled generating stations is
projected to be approximately $144.6 million stated in 2000 dollars, including
approximately $24.0 million (of which $16.8 million has already been expended)
for Person, Prager and Santa Fe Stations which have been retired. The Company is
currently recovering estimated decommissioning costs for its in-service
fossil-fueled generating facilities through rates charged to its retail
customers.
18
ITEM 2. PROPERTIES
ELECTRIC
The Company's ownership and capacity in electric generating stations in
commercial service as of December 31, 2000, were as follows:
Total Net
Generation
Capacity
Type Name Location (MW)
- --------------- ----------------- ------------------------- -----------
Coal........... SJGS (b) Waterflow, New Mexico 765
Coal........... Four Corners (c) Fruitland, New Mexico 192
Gas/Oil........ Reeves Albuquerque, New Mexico 154
Gas/Oil........ Las Vegas Las Vegas, New Mexico 20
Nuclear........ PVNGS (a) Wintersburg, Arizona 390 *
-----
1,521
PPA** 132
-----
1,653
=====
- ----------
* For load and resource purposes, the Company has notified the PRC that it
recognizes the maximum dependable capacity rating for PVNGS to be 381 MW.
** The Company entered into a long term PPA for the rights to all output of
a new gas fired generating plant with maximum dependable capacity of 132
MW.
(a) SJGS Units 1, 2 and 3 are 50% owned by the Company; SJGS Unit 4 is
38.5% owned by the Company.
(b) Four Corners Units 4 and 5 are 13% owned by the Company.
(c) The Company is entitled to 10.2% of the power and energy generated
by PVNGS. The Company has a 10.2% ownership interest in Unit 3 and
has leasehold interests in approximately 7.9% of Units 1 and 2 and
an ownership interest in approximately 2.3% of Units 1 and 2.
The Company's owned interests in PVNGS are mortgaged to secure its
remaining first mortgage bonds.
Fossil-Fueled Plants
SJGS is located in northwestern New Mexico, and consists of four units
operated by the Company. Units 1, 2, 3 and 4 at SJGS have net rated capacities
of 327 MW, 316 MW, 497 MW and 507 MW, respectively. SJGS Units 1 and 2 are owned
on a 50% shared basis with Tucson. Unit 3 is owned 50% by the Company, 41.8% by
SCPPA and 8.2% by Tri-State. Unit 4 is owned 38.457% by the Company, 28.8% by
M-S-R, 10.04% by Anaheim, 8.475% by Farmington, 7.2% by Los Alamos and 7.028% by
UAMPS.
In July 1996, the Company and other SJGS participants signed an
agreement to convert the flue gas desulfurization (SO2 removal) system at the
SJGS into a much simpler and cost effective limestone system. The conversion
project was completed in January 1999 and cost the Company approximately $35
million.
19
In March 2000, SJGS received ISO14001 certification for its
environmental management system by the International Standards Organization. In
addition, in December 2000, SJGS was selected for charter membership in the
EPA's national environmental achievement track program. SJGS is the only coal
fired electric generation plant to be recognized by this program for
environmental excellence.
The Company also owns 192 MW of net rated capacity derived from its 13%
interest in Units 4 and 5 of Four Corners located in northwestern New Mexico on
land leased from the Navajo Nation and adjacent to available coal deposits.
Units 4 and 5 at Four Corners are jointly owned with SCE, APS, Salt River
Project, Tucson and El Paso and are operated by APS.
Four Corners and a portion of the facilities adjacent to SJGS are located
on land held under easements from the United States and also under leases from
the Navajo Nation. The enforcement of these leases could require Congressional
consent. The Company does not deem the risk with respect to the enforcement of
these easements and leases to be material. However, the Company is dependent in
some measure upon the willingness and ability of the Navajo Nation to protect
these properties.
The Company owns 154 MW of generation capacity at Reeves Station in COA,
New Mexico, and 20 MW of generation capacity at Las Vegas Station in Las Vegas,
New Mexico. In addition, the Company has 132 MW of generation capacity in COA,
New Mexico under a PPA. These stations and PPA are used primarily for peaking,
transmission support and during times of excess capacity, augmentation of the
Company's power trading activities.
Nuclear Plant
The Company's Interest in PVNGS
The Company is participating in the three 1,270 MW units of PVNGS, also
known as the Arizona Nuclear Power Project, with APS (the operating agent), Salt
River Project, El Paso, SCE, SCPPA and the Department of Water and Power of the
City of Los Angeles. The Company has a 10.2% undivided interest in PVNGS, with
portions of its interests in Units 1 and 2 held under leases.
Nuclear Safety Performance Rating on PVNGS
In 2000, the NRC began using a new, objective oversight process that is
more focused on safety. The new process includes objective performance
thresholds based on insights from safety studies and 30 years of plant operating
experience in the United States. It is more timely, moving from the 18 to 24
month time lag of the previous oversight process for assessing plant performance
to a quarterly review. The NRC also hopes the process will be more accessible
to, and readily understood by, the public. PVNGS has 37 of 38 indicators green
(the best possible) with the remaining indicator being white (the second best of
the four indicator levels).
Steam Generator Tubes
APS, as the operating agent of PVNGS, has encountered tube cracking in
the steam generators and has taken, and will continue to take, remedial actions
that it believes have slowed the rate of tube degradation. The projected service
20
life of steam generators is reassessed periodically and these analyses indicate
that it will be economically desirable to replace the Unit 2 steam generators in
2003. In 1997, the PVNGS participants, including the Company, entered into a
contract for the fabrication of two replacement steam generators for delivery in
2002. The cost of the new steam generators was updated in late 1999. The
Company's share of the fabrication and installation costs will be approximately
$23 million. In December 1999, the PVNGS participants unanimously approved
installation of the new steam generators in Unit 2.
Based on the latest available data, APS estimates that the Unit 1 and
Unit 3 steam generators could operate for the license periods (until 2025 and
2027, respectively), although APS will continue its normal periodic assessment
of these generators. The Company expects that some tube degradation will occur
through the licensed period. APS is reassessing whether it is economically
desirable to replace the steam generators in Units 1 and 3. Such replacement
would require the unanimous approval of the PVNGS participants.
Sale and Leaseback Transactions of PVNGS Units 1 and 2
In 1985 and 1986, the Company entered into a total of eleven sale and
lease back transactions with a owner trust under which it sold and leased back
its entire 10.2% interest in PVNGS Units 1 and 2, together with portions of the
Company's undivided interest in certain PVNGS common facilities. The leases
under each of the sale and leaseback transactions have initial lease terms
expiring January 15, 2015 (with respect to the Unit 1 leases) or January 15,
2016 (with respect to the Unit 2 leases). Each of the leases allows the Company
to extend the term of the lease as well as containing a repurchase option. The
lease expense for the Company's PVNGS leases is approximately $66.3 million per
year. Throughout the terms of the leases, the Company continues to have full and
exclusive authority and responsibility to exercise and perform all of the rights
and duties of a participant in PVNGS under the Arizona Nuclear Power Project
Participation Agreement and retains the exclusive right to sell and dispose of
its 10.2% share of the power and energy generated by PVNGS Units 1 and 2. The
Company also retains responsibility for payment of its share of all taxes,
insurance premiums, operating and maintenance costs, costs related to capital
improvements and decommissioning and all other similar costs and expenses
associated with the leased facilities. In 1992, the Company purchased
approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases
through the purchase of an ownership interest in the trust which held the
leases. The related ownership interests were subsequently reacquired by the
Company when the Company's trust ownership was collapsed and the Company assumed
direct ownership. In connection with the $30 million retail rate reduction
stipulated with the NMPUC in 1994, the Company wrote down the purchased
beneficial interests in PVNGS Units 1 and 2 leases to $46.7 million.
Each lease describes certain events, "Events of Loss" or "Deemed Loss
Events", the occurrence of which could require the Company to, among other
things, (i) pay the lessor and the equity investor, in return for such
investor's interest in PVNGS, cash in the amount provided in the lease and (ii)
assume debt obligations relating to the PVNGS lease. The "Events of Loss"
generally relate to casualties, accidents and other events at PVNGS, which would
severely, adversely affect the ability of the operating agent, APS, to operate,
and the ability of the Company to earn a return on its interests in, PVNGS. The
"Deemed Loss Events" consist mostly of legal and regulatory changes (such as
changes in law making the sale and leaseback transactions illegal, or changes in
law making the lessors liable for nuclear decommissioning obligations). The
Company believes the probability of such "Events of Loss" or "Deemed Loss
21
Events" occurring is remote for the following reasons: (i) to a large extent,
prevention of "Events of Loss" and some "Deemed Loss Events" is within the
control of the PVNGS participants, including the Company, and the PVNGS
operating agent, through the general PVNGS operational and safety oversight
process and (ii) with respect to other "Deemed Loss Events", which would involve
a significant change in current law and policy, the Company is unaware of any
pending proposals or proposals being considered for introduction in Congress,
except as described below under "PVNGS Liability and Insurance Matters", or any
state legislative or regulatory body that, if adopted, would cause any such
events.
PVNGS Decommissioning Funding
The Company has a program for funding its share of decommissioning costs
for PVNGS. (See Item 3 - "Legal Proceedings - Nuclear Decommissioning Trust".)
The nuclear decommissioning funding program is invested in equities and fixed
income investments in qualified and non-qualified trusts. The results of the
1998 triannual decommissioning cost study indicated that the Company's share of
the PVNGS decommissioning costs excluding spent fuel disposal will be
approximately $171.3 million (in 2000 dollars).
The Company funded an additional $3.9 million, $3.1 million and $3.0
million in 2000, 1999 and 1998, respectively, into the qualified and
non-qualified trust funds. The estimated market value of the trusts at the end
of 2000 was approximately $55 million.
The NRC amended its rules on financial assurance requirements for the
decommissioning of nuclear power plants. The amended rules became effective on
November 23, 1998. The NRC has indicated that the amendments respond to the
potential rate deregulation in the power generating industry and NRC concerns
regarding whether decommissioning funding assurance requirements will need to be
modified. The amended rules provide that a licensee may use an external sinking
fund as the exclusive financial assurance mechanism if the licensee recovers
amounts equal to estimated total decommissioning costs through cost of service
rates or through a "non-bypassable charge". Other mechanisms are prescribed,
such as prepayment, surety methods, insurance and other guarantees, if the
requirements for exclusive reliance on the external sinking fund mechanism are
not met. The Company currently relies on the external sinking fund mechanism to
meet the NRC financial assurance requirements for its interests in PVNGS Units
1, 2 and 3. The costs of PVNGS Units 1 and 2 are currently included in PRC
jurisdictional rates, but the costs of PVNGS Unit 3 are excluded from PRC
jurisdictional rates. The Company will file a report with the NRC through APS,
the operating agent of PVNGS, in March 2001, concerning decommissioning funding
assurance, and will continue to use the external sinking fund method as the sole
financial assurance method for Unit 3 (see Item 7. "Management's Discussion And
Analysis Of Financial Condition And Results Of Operations - The Restructuring
Act and the Formation of a Holding Company - NRC Prefunding").
Nuclear Spent Fuel and Waste Disposal
Pursuant to the Waste Act, the DOE is obligated to accept and dispose of
all spent nuclear fuel and other high-level radioactive wastes generated by
domestic power reactors. The NRC, pursuant to the Waste Act, requires operators
of nuclear power reactors to enter into spent fuel disposal contracts with DOE.
Under the Waste Act, DOE was to develop the facilities necessary for the storage
and disposal of spent nuclear fuel and to have the first facility in operation
by 1998. That facility was to be a permanent repository. The DOE has announced
that such a repository now cannot be completed before 2010. In July 1996, the
United States Court of Appeals for the District of Columbia Circuit (D. C.
Circuit) ruled that the DOE has an obligation to start disposing of spent
nuclear fuel no later than January 31, 1998. By way of letter dated December 17,
1996, the DOE informed the Company and other contract holders that the DOE
anticipates that it would be unable to begin acceptance of nuclear spent fuel
22
for disposal in a repository or interim storage facility by January 31, 1998. In
November 1997, the D. C. Circuit issued a Writ of Mandamus precluding the DOE
from excusing its own delay on the grounds that the DOE has not yet prepared a
permanent repository or interim storage facility. On May 5, 1998, the D. C.
Circuit issued a ruling refusing to order the DOE to begin moving spent nuclear
fuel. See note 12 of Notes to the Consolidated Financial Statements in Item 8
for a discussion of interim spent fuel storage costs.
Facility funding is a further complication. While all nuclear utilities
pay into a so-called nuclear waste fund, an amount calculated on the basis of
the output of their respective plants, the annual Congressional appropriations
for the permanent repository have been for amounts less than the amounts paid
into the waste fund (the balance of which is being used for other purposes). The
DOE has stated the fund may now be at a level less than needed to achieve a 2010
operational date for a permanent repository. No funding will be available for a
central interim facility until one is authorized by Congress.
APS has storage capacity in existing fuel storage pools at PVNGS which,
with certain modifications, could accommodate all fuel expected to be discharged
from normal operation of PVNGS through about 2002. Construction of a new
facility for on-site dry storage of spent fuel is underway. Once this facility
is completed and approvals are granted, APS believes that spent fuel storage or
disposal methods will be available for use by PVNGS to allow its continued
operation beyond 2002.
A new low-level waste facility was built in 1995 on site, which could
store an amount of waste equivalent to ten years of normal operation at PVNGS.
Although some low-level waste has been stored on site, APS is currently shipping
low-level waste to off-site facilities. APS currently believes that interim
low-level waste storage methods are or will be available for use by PVNGS to
allow its continued operation and to safely store low-level waste until a
permanent disposal facility is available.
The Company believes that scientific and financial aspects of the issues
of spent fuel and low-level waste storage and disposal can be resolved
satisfactorily. However, the Company also acknowledges that their ultimate
resolution in a timely fashion will require political resolve and action on
national and regional scales which the Company is unable to predict at this
time.
PVNGS Liability and Insurance Matters
The PVNGS participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under Federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the program exceed the primary liability insurance limit,
the Company could be assessed retrospective adjustments. The maximum assessment
per reactor under the program for each nuclear incident is approximately $88
million, subject to an annual limit of $10 million per reactor per incident.
Based upon the Company's 10.2% interest in the three PVNGS units, the Company's
maximum potential assessment per incident for all three units is approximately
$27 million, with an annual payment limitation of $3 million per incident. The
insureds under this liability insurance include the PVNGS participants and "any
23
other person or organization with respect to his legal responsibility for damage
caused by the nuclear energy hazard". If the funds provided by this
retrospective assessment program prove to be insufficient, Congress could impose
revenue raising measures on the nuclear industry to pay claims.
The NRC announced that it had provided a report to Congress, making
certain recommendations, with respect to the Federal law referred to above,
which provides for payment of public liability claims in case of a catastrophic
accident involving a nuclear power plant. One of the recommendations by the NRC
would be that Congress consider amending the law to provide that the maximum a
nuclear utility can be assessed per reactor per incident per year be doubled to
$20 million. The $88 million maximum retrospective assessment per reactor per
incident would be unchanged under the NRC proposal. The NRC also recommended
that Congress investigate whether the $200 million now available from the
private insurance market for liability claims per reactor can be increased to
keep pace with inflation. The Company cannot predict whether or not Congress
will act on the NRC's recommendations. However, if adopted, certain of the
recommendations could possibly trigger "Deemed Loss Events" under the Company's
PVNGS leases, absent waiver by the lessors.
The PVNGS participants maintain "all-risk" (including nuclear hazards)
insurance for nuclear property damage to, and decontamination of, property at
PVNGS in the aggregate amount of $2.75 billion as of January 1, 2001, a
substantial portion of which must be applied to stabilization and
decontamination. The Company has also secured insurance against portions of the
increased cost of generation or purchased power and business interruption
resulting from certain accidental outages of any of the three units if the
outages exceed 12 weeks. The insurance coverage discussed in this section is
subject to certain policy conditions and exclusions. The Company is a member of
an industry mutual insurer. This mutual insurer provides both the "all-risk" and
increased cost of generation insurance to the Company. In the event of adverse
losses experienced by this insurer, the Company is subject to an assessment. The
Company's maximum share of any assessment is approximately $2.3 million per
year.
Other Electric Properties
As of December 31, 2000, the Company owned, jointly owned or leased
2,552 circuit miles of electric transmission lines, 4,205 miles of distribution
overhead lines, 3,389 cable miles of underground distribution lines (excluding
street lighting) and 210 substations.
The Company and Tri-State Generation and Transmission Association, Inc.
("Tri-State") entered into an asset sale agreement dated September 9, 1999,
pursuant to which Tri-State agreed to sell the Company certain assets acquired
by Tri-State's merger with Plains Electric Generation and Transmission
Cooperative, Inc., consisting primarily of transmission assets, a fifty percent
interest in an inactive power plant located near Albuquerque, and an office
building in Albuquerque. The purchase price is $13.2 million, subject to
adjustment at the time of closing with the transaction to close in two phases.
The asset sale agreement contains standard covenants and conditions for this
type of agreement. On July 1, 2000, the first phase was completed, and the
Company acquired the 50 percent ownership in the inactive power plant and the
office building. The second phase relating to the transmission assets is
expected to close in the first quarter of 2001.
24
NATURAL GAS
The natural gas properties as of December 31, 2000, consisted primarily
of natural gas storage, transmission and distribution systems. Provisions for
storage made by the Company include ownership and operation of an underground
storage facility located near Albuquerque, New Mexico. The transmission systems
consisted of approximately 1,464 miles of pipe with appurtenant compression
facilities. The distribution systems consisted of approximately 10,693 miles of
pipe.
OTHER INFORMATION
The electric and gas transmission and distribution lines are generally
located within easements and rights-of-way on public, private and Indian lands.
The Company leases interests in PVNGS Units 1 and 2 and related property, EIP
and associated equipment, data processing, communication, office and other
equipment, office space, utility poles (joint use), vehicles and real estate.
The Company also owns and leases service and office facilities in Albuquerque
and in other operating divisions throughout its service territory.
ITEM 3. LEGAL PROCEEDINGS
PVNGS Water Supply Litigation
The Company understands that a summons served on APS in 1986 required
all water claimants in the Lower Gila River Watershed of Arizona to assert any
claims to water on or before January 20, 1987, in an action pending in the
Maricopa County Superior Court. PVNGS is located within the geographic area
subject to the summons and the rights of the PVNGS participants, including the
Company, to the use of groundwater and effluent at PVNGS are potentially at
issue in this action. APS, as the PVNGS project manager, filed claims that
dispute the court's jurisdiction over the PVNGS participants' groundwater rights
and their contractual rights to effluent relating to PVNGS 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.
San Juan River Adjudication
In 1975, the State of New Mexico filed an action entitled State of New
Mexico v. United States, et al., in the District Court of San Juan County, New
Mexico, to adjudicate all water rights in the "San Juan River Stream System".
The Company was made a defendant in the litigation in 1976. The action is
expected to adjudicate water rights used at Four Corners and at SJGS. (See Item
1. "Business - Generation and Trading Operations - Fuel and Water Supply - Water
Supply".) The Company cannot at this time anticipate the effect, if any, of any
water rights adjudication on the present arrangements for water at SJGS and Four
Corners. It is the Company's understanding that final resolution of the case
cannot be expected for several years. The Company is unable to predict the
ultimate outcome.
25
Republic Savings Bank Litigation
In 1992, Meadows and its subsidiary RHC filed suit against the Federal
government in the United States Court of Claims, alleging breach of contract
arising from the seizure of RSB, a wholly-owned subsidiary of RHC. RSB was
seized and liquidated after the Financial Institutions Reform, Recovery and
Enforcement Act prohibited certain accounting practices authorized by contracts
with the Federal government. The Federal government filed a counterclaim
alleging breach by RHC of its obligation to maintain RSB's net worth and moved
to dismiss Meadows' claims for lack of standing.
RSB filed a motion for partial summary judgment on the issue of
liability based on the United States Supreme Court's decision in United States
v. Winstar Corporation, decided in 1996. The Federal government filed a cross
motion for summary judgment and opposed RSB's motion. Decision on those motions
is still pending. The parties completed fact based discovery in 1999. Discovery
of expert witnesses has not been completed. No trial date has been established.
RSB amended its summary judgment motion in December 1999, to seek summary
judgment on the issue of damages. The Federal government opposes RSB's amended
motion. Oral argument on this motion was conducted in September 2000. The judge
requested additional briefing, which has been submitted. Decision on this motion
is still pending. It is premature to estimate the amount of recovery, if any, by
Meadows and RHC.
Purported Navajo Environmental Regulation
Four Corners is located on the Navajo Reservation and is held under
easement granted by the Federal government as well as leases from the Navajo
Nation. APS is the operating agent and the Company owns a 13% ownership interest
in Units 4 and 5 of 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"). Pursuant to the Acts, the Navajo Nation Environmental Protection Agency
is authorized to promulgate regulations covering air quality, drinking water and
pesticide activities, including those that occur at Four Corners. By letter
dated October 12, 1995, the Four Corners participants requested the United
States Secretary of the Interior (the "Secretary") to resolve their dispute with
the Navajo Nation regarding whether or not the Acts apply to operation of Four
Corners. The Four Corners participants subsequently filed a lawsuit in the
District Court of the Navajo Nation (the "Court"), Window Rock District, seeking
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 indefinitely
stay the proceedings so that the parties may attempt to resolve the dispute
without litigation, and the Secretary and the Court stayed these proceedings
pursuant to a request by the parties. During the pendency of the stay, APS filed
an additional declaratory judgment action in the Court to challenge implementing
regulations under the Navajo Nation Air Pollution Prevention and Control Act.
The Company is unable to predict the outcome of these matters.
In February 1998, the EPA issued regulations specifying provisions of the
Clean Air Act for which it is appropriate to treat Indian tribes in the same
manner as states. The EPA indicated that it believes that the Clean Air Act
generally would supersede pre-existing binding agreements that may limit the
26
scope of tribal authority over reservations. APS and the Company have filed
appeals, which have been consolidated, in the United States Circuit Court of
Appeals for the District of Columbia ("D. C. Circuit") to contest EPA's
authority under the regulations. The Navajo Nation has intervened in the
consolidated appeal. The Navajo Nation is a tribe which could potentially assert
its status as a state under the Act pursuant to the EPA rule in question. The
consolidated appeal involves the Company's interests as operator and joint owner
of the SJGS, as owner of other facilities located on reservations located in New
Mexico, and as joint owner of Four Corners.
In February 1999, the EPA issued regulations under which Federal
operating permits for stationary sources in Indian country can be issued
pursuant to Title V of the Clean Air Act. The regulations rely on authority
contained in an earlier rule in which the EPA outlined treatment of tribes as
states under the Clean Air Act. That rule is the subject of an appeal as
described above. APS and the Company have filed appeals, which have also been
consolidated in the D. C. Circuit to contest the EPA's authority under the
regulations. The consolidated appeal also involves the Company's interests as
operator and as joint owner of the SJGS, owner of other facilities located on
reservations located in New Mexico, and joint owner of Four Corners are
involved. This appeal is pending.
On July 14, 2000, the DC Circuit issued its opinion denying the Company's
motion for rehearing of the decision denying claims concerning the
interpretation by EPA of tribal authority under the Clean Air Act. The Company
has a petition for writ of certiorari to the United States Supreme Court filed
by the State of Michigan and other parties.
The Company cannot predict the outcome of these proceedings or any
subsequent determinations by the EPA. There can be no assurance that the outcome
of these matters will not have a material impact on the results of operations
and financial position of the Company.
Royalty Claims
Natural Gas Royalties Qui Tam Litigation
On June 28, 1999, a complaint was served on the Company alleging
violations of the False Claims Act by the Company and its subsidiaries,
Gathering Company and Processing Company (collectively called Company, for
purposes of this discussion), by purportedly failing to properly measure natural
gas from Federal and tribal properties in New Mexico, and consequently,
underpaid royalties owed to the Federal government. A private relator is
pursuing the lawsuit. The complaint was served after the United States
Department of Justice declined to intervene to pursue the lawsuit. The complaint
seeks actual damages, treble damages, costs and attorneys fees, among other
relief.
This case was consolidated with approximately 70 others, asserting
similar claims against other defendants in other jurisdictions, and transferred
to Federal District Court for the District of Wyoming by the Federal
Multi-District Litigation panel (MDL Panel), recaptioned as In re: Natural Gas
Royalties Qui Tam Litigation, MDL Docket No. 1293. The Company joined 250 other
defendants in a motion to dismiss the complaint for failure to plead properly in
November 1999. Oral argument on the motion was held on March 17, 2000. Decision
on the motion is still pending.
The Company is vigorously defending this lawsuit and is unable to
estimate the potential liability, if any, or to predict the ultimate outcome of
this lawsuit.
27
Quinque Operating Co. et al. v. Gas Pipelines, et al
A class action lawsuit against 233 defendants, including the Company,
captioned Quinque Operating Co. et al. v. Gas Pipelines, et al., C.A. No.
99-CV-30, was filed in the state district court for Stevens County, Kansas by
representatives of classes of gas producers, royalty owners, overriding royalty
owners and working interest owners, alleging that the defendants, all engaged in
various aspects of the natural gas industry, mismeasured natural gas and
underpaid royalties for gas produced on non-federal and non-tribal lands. The
claims for relief are based on Kansas state law, including a breach of contract
claim. They are factually similar, however, to the allegations of In re: Natural
Gas Royalties Qui Tam Litigation, described above. The Quinque complaint seeks
actual damages, treble damages, costs and attorneys fees, among other relief.
The Quinque case was removed to the United States District Court for the
District of Kansas and transferred to the United States District Court for
Wyoming ("Wyoming Court") to consolidate it with the In re: Natural Gas
Royalties Qui Tam Litigation. Plaintiffs have filed objections to the motions to
consolidate and transfer and have moved to remand the case to state court. On
January 12, 2001, the Wyoming Court granted Plaintiffs motion to remand the case
back to Kansas State Court. Subsequently, some defendants filed a motion to
reconsider that decision. The Wyoming Court has not yet decided the motion to
reconsider.
The Company is vigorously defending this lawsuit and is unable to
estimate the potential liability, if any, or to predict the ultimate outcome of
this lawsuit.
KAFB Contract
The Company was informed that the DOE had entered into an agency
agreement with WAPA on behalf of KAFB, one of the Company's largest retail
electric customers, by which WAPA would competitively procure power for KAFB.
The proposed wholesale power procurement was to begin at the expiration of
KAFB's power service contract with the Company in December 1999. On May 4, 1999,
the Company received a request for network transmission service from WAPA
pursuant to Section 211 of the Federal Power Act to facilitate the delivery of
wholesale power to KAFB over the Company's transmission system. The Company
denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB
is and will continue to be a retail customer until the effective date KAFB can
elect customer choice service under the provisions of the Restructuring Act of
1999. The Company also cited several provisions of Federal law that prohibit the
provision of such service to WAPA. On September 30, 1999, DOE/WAPA filed a
petition at the FERC requesting the FERC to consider, on an expedited basis,
ordering the Company to provide network transmission service to WAPA under the
Company's Open Access Transmission Tariff on behalf of DOE and several other
entities located on KAFB. The petition claimed KAFB is a wholesale customer of
the Company, not a retail customer. In a separate but related proceeding, the
Company and the United States Executive Agencies on behalf of KAFB are involved
in a PRC case regarding a dispute over the specific Company tariff language
under which the Company provides retail service to KAFB. The Company agreed to
continue to provide service to KAFB after expiration of the contract, pending
resolution of all relevant issues. The Company has attempted to pursue a
negotiated resolution of the issues regarding the provision of electric service
to KAFB, but has been unsuccessful. The Company is currently unable to predict
the ultimate outcome of these matters, and intends to continue to vigorously
defend its position.
28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
29
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE COMPANY
Executive officers, their ages, offices held with the Company in the past
five years and initial effective dates thereof, were as follows on December 31,
2000, except as otherwise noted:
Name Age Office Initial Effective Date
---- --- ------ ----------------------
J. E. Sterba............... 45 Chairman, President and Chief Executive
Officer October 1, 2000
President and Chief Executive Officer June 6, 2000
President March 1, 2000
Executive Vice President, USEC, Inc. December 31, 1998
Executive Vice President and Chief
Operating Officer (of the Company) March 11, 1997
Senior Vice President, Bulk Power Services
(of the Company) December 6, 1994
R. J. Flynn................ 58 Executive Vice President, Electric and Gas
Services January 18, 1999
Senior Vice President, Electric Services December 1, 1994
W. J. Real................. 52 Executive Vice President, Energy Services and
Power Production January 18, 1999
Senior Vice President, Gas Services December 6, 1994
Senior Vice President, Utility Operations December 7,1993
Senior Vice President, Customer Service and
Operations March 2, 1993
Executive Vice President, Gas Operations June 19, 1990
B. L. Barsky............... 56 Senior Vice President, Corporate Strategy and
Investor Relations February 19, 2000
Senior Vice President, Planning and
Investor Services August 10, 1999
Senior Vice President and Corporate Secretary January 18, 1999
Vice President, Strategy, Analysis and Investor
Relations December 10, 1996
Director, Investor Relations and Financial Analysis July 19, 1993
M. D. Christensen.......... 52 Senior Vice President, Enterprise Solutions March 7, 2000
Senior Vice President, Shared Services October 1, 1999
Senior Vice President, New Mexico Retail Services November 3, 1997
Senior Vice President, Customer Service and
Public Affairs January 9, 1996
Vice President, Public Affairs December 7, 1993
Vice President, Communications July 22, 1991
30
Name Age Office Initial Effective Date
---- --- ------ ----------------------
M. H. Maerki............... 60 Senior Vice President and Chief Financial Officer December 7, 1993
Senior Vice President, Administration and Chief
Financial Officer March 2, 1993
Senior Vice President and Chief Financial
Officer June 1, 1988
P. T. Ortiz................ 50 Senior Vice President, General Counsel and Secretary August 10, 1999
Senior Vice President and General Counsel January 18, 1999
Senior Vice President, Regulatory Policy, General
Counsel and Secretary December 7, 1993
Senior Vice President, Public Policy, General
Counsel and Secretary March 2, 1993
Senior Vice President, General Counsel and
Corporate Secretary February 4, 1992
E. Padilla, Jr............. 47 Senior Vice President, Bulk Power Marketing and
Development February 8, 2000
Vice President, Bulk Power Marketing and
Development December 14, 1996
Director, Marketing and Power Contracts January 14, 1991
R. B. Ridgeway............. 42 Senior Vice President, Energy Services December 14, 1996
Vice President, Corporate Planning August 10, 1996
Director, Corporate Strategy July 2, 1994
Consultant, Competitive Analysis October 5, 1992
All officers are elected annually by the Board of Directors of the
Company.
31
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's common stock is traded on the New York Stock Exchange.
Ranges of sales prices of the Company's common stock, reported as composite
transactions (Symbol: PNM), and dividends declared on common stock for 2000 and
1999, by quarters, are as follows:
Range of
Sales Prices
------------------ Dividends
Quarter Ended High Low Per Share
------------- ---- --- ---------
2000
December 31 .................... 28 5/16 20 3/4 $0.20
September 30 ................... 26 11/25 15 3/8 0.20
June 30 ........................ 18 15 5/16 0.20
March 31 ....................... 16 11/16 14 5/8 0.20
-----
Fiscal Year .................. 28 5/16 14 5/8 $0.80
=====
1999
December 31 .................... 18 7/8 15 7/16 $0.20
September 30 ................... 21 1/2 16 3/4 0.20
June 30 ........................ 21 1/8 16 7/8 0.40
March 31 ....................... 20 5/8 14 27/32 0.20
-----
Fiscal Year .................. 21 1/2 14 27/32 $1.00
=====
On December 31, 2000, the Company's Board of Directors ("Board")
declared a quarterly cash dividend of 20 cents per share of common
stock payable February 16, 2001, to shareholders of record as of
February 2, 2001.
On January 31, 2001, there were 15,654 holders of record of the Company's
common stock.
The Board set the dividend payout ratio below the industry average to
allow for dividend growth in the future and to sustain financial flexibility for
the Company to respond to potential opportunities in the evolving energy
marketplace. In establishing its dividend policy, the Board weighed the
Company's current financial position and its future business plan, as well as
the regulatory and business climate in New Mexico. Future dividend declaration
will be reviewed for action by the Board. The payment of future dividends will
depend on a number of factors, including the extent to which cash flows will
support dividends, the availability of retained earnings, the financial
circumstances and performance of the Company, the PRC's decisions on the
Company's various regulatory cases currently pending, the effect of deregulating
generation markets and market economic conditions in general. In addition, the
ability to recover stranded costs in deregulation, future growth plans and the
related capital requirements and standard business considerations will also
affect the Company's ability to pay dividends.
32
Cumulative Preferred Stock
While isolated sales of the Company's cumulative preferred stock have
occurred in the past, the Company is not aware of any active trading market for
its cumulative preferred stock. Quarterly cash dividends were paid on the
Company's cumulative preferred stock at the stated rates during 2000 and 1999.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data should be read in conjunction with the
consolidated financial statements, the notes to consolidated financial
statements and Management's Discussion and Analysis of Financial Condition and
Results of Operations.
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts and ratios)
Total Operating Revenues.......................... $1,611,274 $1,157,543 $1,092,445 $1,020,521 $ 873,778
Earnings from Continuing Operations............... $ 100,946 $ 79,614 $ 95,119 $ 86,497 $ 72,969
Net Earnings...................................... $ 100,946 $ 83,155 $ 82,682 $ 80,995 $ 72,580
Earnings per Common Share:
Continuing Operations........................... $ 2.54 $ 1.93 $ 2.27 $ 2.05 $ 1.73
Basic........................................... $ 2.54 $ 2.01 $ 1.97 $ 1.92 $ 1.72
Diluted......................................... $ 2.53 $ 2.01 $ 1.95 $ 1.91 $ 1.71
Total Assets...................................... $2,894,233 $2,723,268 $2,668,603 $2,407,410 $2,313,334
Long-Term Debt, including Current Maturities...... $ 953,823 $ 988,489 $1,008,614 $ 714,345 $ 728,889
Common Stock Data:
Market price per common share at year end....... $ 26.813 $ 16.250 $ 20.438 $ 23.688 $ 19.625
Book value per common share at year end......... $ 23.64 $ 21.79 $ 20.63 $ 19.26 $ 18.06
Average number of common shares outstanding..... 39,487 41,038 41,774 41,774 41,774
Cash dividend declared per common share......... $ 0.80 $ 1.00 $ 0.60 $ 0.68 $ 0.48
Return on Average Common Equity................... 11.1% 9.5% 9.9% 10.2% 9.8%
Capitalization:
Common stock equity............................. 48.6% 46.7% 45.4% 52.6% 50.4%
Preferred stock without mandatory redemption
Requirements.................................. 0.7 0.7 0.7 0.8 0.9
Long-term debt, less current maturities......... 50.7 52.6 53.9 46.6 48.7
----------- ----------- ----------- ----------- -----------
100.00% 100.0% 100.0% 100.0% 100.0%
=========== =========== =========== =========== ===========
(See Comparative Operating Statistics which appear immediately following
the Consolidated Financial Statements for additional information regarding
operations.)
Due to the discontinuance of the natural gas trading operations of its
Energy Services Business Unit in 1998 (see Note 13 to the Consolidated Financial
Statements), certain prior year amounts have been reclassified as discontinued
operations.
33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is management's assessment of the Company's financial
condition and the significant factors affecting the results of operations. This
discussion should be read in conjunction with the Company's consolidated
financial statements and Part I, Item 3. - Legal Proceedings. Trends and
contingencies of a material nature are discussed to the extent known and
considered relevant.
OVERVIEW
The Company is a public utility primarily engaged in the generation,
transmission, distribution and sale of electricity and in the transmission,
distribution and sale of natural gas within the State of New Mexico. In
addition, in pursuing new business opportunities, the Company provides energy
and utility related product offerings through its wholly-owned subsidiary,
Avistar. As it currently operates, the Company's principal business segments are
Utility Operations, which include the Electric Product Offering ("Electric") and
the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations
("Generation and Trading"). The Electric Product Offering consists of two major
business lines that include distribution and transmission. The transmission
product offering does not meet the definition of a segment for accounting
purposes due to its immateriality, and for purposes of this discussion, it is
combined with the distribution product offering.
UTILITY OPERATIONS
Electric
The Company provides jurisdictional retail electric service to a large
area of north central New Mexico, including the COA and the City of Santa Fe,
and certain other areas of New Mexico. Retail sale revenues, which include
distribution and transmission, were $518.7 million, $522.5 million and $536.4
million for the year ended December 31, 2000, 1999 and 1998, respectively, and
approximately 369,000, 361,000 and 358,000, respectively, retail electric
customers were served by the Company.
The Company owns or leases 2,781 circuit miles of transmission lines,
interconnected with other utilities east into Texas, west into Arizona, and
north into Colorado and Utah. Due to rapid load growth in recent years, most of
the capacity on this transmission system is fully committed and there is no
additional access available on a firm commitment basis. These factors, together
with significant physical constraints in the system, limit the ability to wheel
power into the Company's service area from outside the state.
Gas
The Company's Gas operations distribute natural gas to most of the major
communities in New Mexico, including Albuquerque and Santa Fe, serving
approximately 435,000, 426,000 and 419,000 customers as of December 31, 2000,
1999 and 1998, respectively. The Company's gas customer base includes both
sales-service customers and transportation-service customers. Sales-service
customers purchase natural gas and receive transportation and delivery services
from the Company for which the Company receives both cost-of-gas and
cost-of-service revenues. Additionally, the Company makes occasional gas sales
34
to off-system customers. Off-system sales deliveries generally occur at
interstate pipeline interconnects with the Company's system.
Transportation-service customers, who procure gas independently of the Company
and contract with the Company for transportation and related services, provide
the Company with cost-of-service revenues only.
The Company obtains its supply of natural gas primarily from sources
within New Mexico pursuant to contracts with producers and marketers. These
contracts are generally sufficient to meet the Company peak-day demand.
The following table shows gas throughput by customer class:
GAS THROUGHPUT
(Millions of decatherms)
2000 1999 1998
------ ------ ------
Residential.............................. 28.8 32.1 29.3
Commercial............................... 9.9 10.8 10.1
Industrial............................... 5.0 2.4 1.5
Transportation*.......................... 44.9 40.2 36.5
Other.................................... 6.4 6.8 8.3
------ ------ ------
95.0 92.3 85.7
====== ====== ======
The following table shows gas revenues by customer:
GAS REVENUES
(Thousands of dollars)
2000 1999 1998
-------- -------- --------
Residential.............................. $191,221 $151,954 $160,459
Commercial............................... 52,959 37,300 42,500
Industrial............................... 24,208 8,595 4,876
Transportation*.......................... 14,163 12,390 13,464
Other.................................... 37,373 26,472 34,676
-------- -------- --------
$319,924 $236,711 $255,975
======== ======== ========
*Customer-owned gas.
GENERATION AND TRADING OPERATIONS
The Company's Generation and Trading Operations serve four principal
markets. Sales to the Company's Utility Operations to cover jurisdictional
electric demand and sales to firm-requirements wholesale customers, sometimes
referred to collectively as "system" sales, comprise two of these markets. The
third market consists of other contracted sales to third parties for which the
Generation and Trading Operations commit to deliver a specified amount of
capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh)
35
over a given period of time. The fourth market consists of economy energy sales
made on an hourly basis at fluctuating, spot-market rates. Sales to the third
and fourth markets are sometimes referred to collectively as "off-system" sales.
Off-system sales include the Company's energy trading activities.
The following table shows sales by customer class:
GENERATION AND TRADING SALES BY MARKET
(Megawatt hours)
2000 1999 1998
---------- ---------- ----------
Intersegment sales....................... 7,088,943 6,803,583 6,739,874
Firm-requirements wholesale.............. 193,853 179,249 278,615
Other contracted off-system sales........ 7,385,266 6,196,499 4,033,931
Economy energy sales..................... 4,773,009 4,795,873 4,469,769
---------- ---------- ----------
19,441,071 17,975,204 15,522,189
========== ========== ==========
The following table shows revenues by customer class:
GENERATION AND TRADING REVENUES BY MARKET
(Thousands of dollars)
2000 1999 1998
---------- ---------- ----------
Intersegment sales...................... $ 324,744 $ 318,872 $ 362,722
Firm-requirements wholesale............. 6,568 7,046 10,708
Other contracted off-system sales....... 371,900 226,773 142,115
Economy energy sales.................... 369,724 131,549 122,156
Other ................................ 2,242 5,741 4,657
---------- ---------- ----------
$1,075,178 $ 689,981 $ 642,358
========== ========== ==========
The Generation and Trading Operations have ownership interest in certain
generating facilities located in New Mexico, including the San Juan Generating
Station, a coal fired unit, and the Four Corners Power Plant, a coal fired unit.
In addition, the Company has ownership and leasehold interests in Palo Verde
Nuclear Generating Station ("PVNGS") located in Arizona. These generation assets
are used to supply retail and wholesale customers. The Generation and Trading
Operations also own Reeves Generating Station, a gas and oil fired unit and Las
Vegas Generating Station, a gas and oil fired unit, that are used solely for
reliability purposes or to generate electricity for the wholesale market during
peak demand periods in the Generation and Trading Operations' wholesale power
markets.
As of December 31, 2000, the total net generation capacity of facilities
owned or leased by the Generation and Trading Operations was 1,521 MW. On July
13, 2000, the Company commenced a 20 year power purchase agreement for an
additional 132 MW for the rights to all output of a new gas fired generating
plant. In addition to its generation capacity, the Generation and Trading
Operations purchase power in the open market.
36
AVISTAR
The Company's wholly-owned subsidiary, Avistar, was formed in August 1999
as a New Mexico corporation and is currently engaged in certain unregulated,
non-utility businesses, including energy and utility-related services previously
operated by the Company. The PRC authorized the Company to invest $50 million in
equity in Avistar and to enter into a reciprocal loan agreement for up to $30
million. The Company has currently invested $35 million in Avistar. In February
2000, Avistar invested $3 million for a 25% ownership interest in AMDAX.com, a
start-up company which developed a proprietary auction platform designed to
efficiently bring together electricity buyers and sellers in the deregulated
natural gas and electricity markets. In the second quarter 2000, Avistar
invested $1 million in Nth Power, a venture capital fund. In December 2000,
Avistar invested $10 million for a 5% ownership interest in Mainstreet Networks,
an Internet Gateway Service Provider. Together with local utilities, Mainstreet
Networks plans to provide low-cost Internet-based services to homes through an
Internet gateway attached at the customer's electric meter.
ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS
On November 9, 2000 the Company and Western Resources, Inc. ("Western
Resources") announced that both companies' boards of directors approved an
agreement under which the Company will acquire the Western Resources' electric
utility operations in a tax-free, stock-for-stock transaction.
The new combined company will serve over one million retail electric
customers and 435,000 retail gas customers in New Mexico and Kansas and will
have generating capacity of more than 7,000 MW. The transaction exceeds the
Company's stated goal of doubling its generation capacity and tripling its power
sales more than three years ahead of schedule. The transaction will also make
the new company a leading energy supplier in the Western and Midwestern
wholesale markets.
The transaction will provide the Company with the opportunity to
accelerate its proven growth strategy by developing a similar niche product,
asset-backed wholesale power marketing strategy at Western Resources. The
Company expects this transaction to contribute significantly towards its
targeted 10 percent annual average earnings growth over the next five years. The
strategic nature of the acquisition is based upon revenue-growth. As a result,
the Company expects modest cost savings although cost reduction will be one
aspect of the integration effort. At present the Company does not intend on
significant cost savings associated with involuntary workforce reductions. The
new holding company will seek to minimize any workforce effects through reduced
hiring, attrition, and other appropriate measures. All existing labor agreements
will be honored.
The transaction is expected to close promptly after all of the conditions
to its consummation are fulfilled, including the spin off to Western Resources'
shareholders of Western Resources' non-utility assets, approval from both
companies' shareholders and customary regulatory approvals. (See "Other Issues
Facing The Company - Acquisition of Western Resources Electric Operations"
below).
37
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
Introduction of competitive market forces and restructuring of the
electric utility industry in New Mexico continue to be key issues facing the
Company. New Mexico's Electric Utility Industry Restructuring Act of 1999 (the
"Restructuring Act"), which was enacted into law in April 1999, would begin to
open the state's electric power market to customer choice beginning in 2002. The
Restructuring Act would give schools, residential and small business customers
the opportunity to choose among competing power suppliers beginning in January
2002. Competition would be expanded to include all customers starting in July
2002. Rural electric cooperatives and municipal electric systems have the option
not to participate in the competitive market.
Under the Restructuring Act, residential and small business customers who
do not select a power supplier in the open market would buy their electricity
through their local utility through "standard offer service" whereby the local
distribution utility would procure power supplies through a process approved by
the PRC. The local distribution utility system and related services such as
billing and metering would continue to be regulated by the PRC, while
transmission services and wholesale power sales would remain subject to Federal
regulation.
The Restructuring Act does not require utilities to divest their
generating plants, but requires certain deregulated activities to be separated
from activities regulated by the PRC through creation of at least two separate
corporations.
The Company plans to reorganize its operations by forming a holding
company structure as a means of achieving the corporate and asset separation
required by the Restructuring Act. The Company's plan for a holding company
structure would separate the Company into two subsidiaries. In June 2000,
shareholders approved the mandatory share exchange necessary to implement the
holding company structure. If the Company receives all necessary regulatory and
other approvals, all of the Company's electric and gas distribution and
transmission assets and certain related liabilities would be transferred to a
newly created subsidiary ("Asset Transfer"). After this asset transfer, this
subsidiary will acquire the name "Public Service Company of New Mexico" (for
purposes of this discussion, the subsidiary is referred to as "UtilityCo") and
the corporation formerly named Public Service Company of New Mexico will be
renamed Manzano Energy Corporation (for purposes of this discussion, the
subsidiary is referred to as "PowerCo"). PowerCo would continue to own the
Company's existing electric generation and certain other unregulated,
competitive assets after completion of the transfer of the regulated business to
the newly created utility subsidiary. UtilityCo, PowerCo and Avistar would be
wholly-owned subsidiaries of the proposed holding company.
For a discussion on the status of the formation of the holding company
and corporate separation, see "Other Issues Facing The Company - The
Restructuring Act, The Formation of the Holding Company and Corporate
Separation" below.
COMPETITIVE STRATEGY
The restructuring of the electric utility industry is expected to provide
new opportunities; however, the Company anticipates that it will experience
downward pressure on the Company's utility earnings from their current levels.
38
The reasons for the downward pressure include possible limits on return on
equity, disallowance of some stranded costs and the potential loss of certain
customers in a competitive environment.
Under the holding company structure proposed to comply with the
Restructuring Act, the regulated businesses (natural gas and electric
transmission and distribution) will be grouped under a separate company and
would focus on the core utility business in New Mexico. The unregulated
businesses under the Restructuring Act (power production, bulk power marketing,
including energy trading activities and energy services) would aggressively
pursue efforts to expand energy marketing and utility related businesses into
carefully targeted markets in an effort to increase shareholder value. The
Company believes that successful operations of its proposed unregulated business
activities under a holding company structure would better position the Company
in an increasingly competitive utility environment.
The Company's Generation and Trading Operations have contributed
significant earnings to the Company in recent years as a result of increased
off-system sales including its energy trading activities. The Company plans to
expand its wholesale energy trading functions which could include an expansion
of its generation portfolio. The Company continuously evaluates its physical
asset acquisition strategies to ensure an optimal mix of base-load generation,
peaking generation and purchased power in its power portfolio. In addition to
the continued energy trading activities, the Company will further focus on
opportunities in the market place where excess capacity is disappearing and mid-
to long-term market demands are growing.
The Company's current business plan includes a 300% increase in sales and
a doubling of its generating capacity through the construction or acquisition of
additional power generation assets in its surrounding region of operations over
the next five to seven years. The proposed acquisition of Western Resources
electric utility businesses announced on November 9, 2000, will allow the
Company to meet this goal well ahead of schedule by adding approximately 5,600
MW to the Company's generation portfolio growth. The Company will continue to
pursue growth in its generation portfolio and intends to spend $400 to $800
million over the next five years to achieve generation portfolio growth. Such
growth will be dependent upon the Company's ability to generate funds for the
Company's expansion. There can be no assurance that these competitive
businesses, particularly the generation business, will be successful or, if
unsuccessful, that they will not have a direct or indirect adverse effect on the
Company.
At the Federal level, there have been a number of proposals on electric
restructuring being considered with no concrete timing for definitive actions.
None of these proposals have been acted upon by Congress. Issues such as
stranded cost recovery, market power, utility regulation reform, the role of
states, subsidies, consumer protections and environmental concerns are expected
to be reintroduced if not acted upon in the current Congressional session. In
addition, the FERC has stated that if Congress mandates electric retail access,
it should leave the details of the program to the states with the FERC having
the authority to order the necessary transmission access for the delivery of
power for the states' retail access programs.
Although it is unable to predict the ultimate outcome of retail
competition in New Mexico, the Company has been and will continue to be active
at both the state and Federal levels in the public policy debates on the
39
restructuring of the electric utility industry. The Company will continue to
work with customers, regulators, legislators and other interested parties to
find solutions that bring benefits from competition while recognizing the
importance of reimbursing utilities for past commitments.
RESULTS OF OPERATIONS
The following discussion is based on the financial information presented
in Footnote 1 of the Consolidated Financial Statements - Nature of Business and
Segment Information. The table below sets forth the operating results as
percentages of total operating revenues for each business segment.
Year Ended December 31, 2000
Utility
---------------------------------------- Generation
Electric Gas and Trading
------------------- ----------------- -------------------
Operating revenues:
External customers ................ $ 538,758 99.87% $319,924 100.00% $ 750,434 69.80%
Intersegment revenues ............. 707 0.13 -- -- 324,744 30.20
---------- ------ -------- ------ ---------- ------
Total revenues .................... 539,465 100.00 319,924 100.00 1,075,178 100.00
---------- ------ -------- ------ ---------- ------
Cost of energy sold ................. 5,048 0.94 195,333 61.06 749,499 69.71
Intersegment purchases .............. 324,744 60.20 -- -- 707 0.07
---------- ------ -------- ------ ---------- ------
Total fuel costs .................. 329,792 61.13 195,333 61.06 750,206 69.78
---------- ------ -------- ------ ---------- ------
Gross margin ........................ 209,673 38.87 124,591 38.94 324,972 30.22
---------- ------ -------- ------ ---------- ------
Administrative and other costs ...... 43,874 8.13 43,241 13.52 30,009 2.79
Energy production costs ............. 1,208 0.22 1,485 0.46 137,201 12.76
Depreciation and amortization ....... 32,410 6.01 19,994 6.25 40,628 3.78
Transmission and distribution costs . 33,091 6.13 27,206 8.50 25 --
Taxes other than income taxes ....... 14,210 2.63 8,716 2.72 11,430 1.06
Income taxes ........................ 28,053 5.20 5,349 1.67 25,320 2.35
---------- ------ -------- ------ ---------- ------
Total non-fuel operating expenses.. 152,846 28.33 105,991 33.13 244,613 22.75
---------- ------ -------- ------ ---------- ------
Operating income .................... $ 56,827 10.53% $ 18,600 5.81% $ 80,359 7.47%
---------- ------ -------- ------ ---------- ------
40
Year Ended December 31, 1999
Utility
-------------------------------------- Generation
Electric Gas and Trading
------------------- ----------------- ------------------
Operating revenues:
External customers................. $ 540,868 99.87% $ 236,711 100.00% $ 371,109 53.79%
Intersegment revenues.............. 707 0.13 -- -- 318,872 46.21
--------- ------- --------- ------- --------- -------
Total revenues..................... 541,575 100.00 236,711 100.00 689,981 100.00
--------- ------- --------- ------- --------- -------
Cost of energy sold.................. 4,493 0.83 112,925 47.71 414,534 60.08
Intersegment purchases............... 318,872 58.88 -- -- 707 0.10
--------- ------- --------- ------- --------- -------
Total fuel costs................... 323,365 59.71 112,925 47.71 415,241 60.18
--------- ------- --------- ------- --------- -------
Gross margin......................... 218,210 40.29 123,786 52.29 274,740 39.82
--------- ------- --------- ------- --------- -------
Administrative and other costs....... 52,586 9.71 49,716 21.00 26,791 3.88
Energy production costs.............. 2,632 0.49 1,504 0.64 132,787 19.25
Depreciation and amortization........ 31,113 5.74 19,210 8.12 40,253 5.83
Transmission and distribution costs.. 31,013 5.73 28,227 11.92 23 --
Taxes other than income taxes........ 19,014 3.51 6,915 2.92 9,006 1.31
Income taxes......................... 24,082 4.45 2,112 0.89 7,319 1.06
--------- ------- --------- ------- --------- -------
Total non-fuel operating expenses.. 160,440 29.62 107,684 45.49 216,179 31.33
--------- ------- --------- ------- --------- -------
Operating income..................... $ 57,770 10.67% $ 16,102 6.80% $ 58,561 8.49%
--------- ------- --------- ------- --------- -------
Year Ended December 31, 1998
Utility
-------------------------------------- Generation
Electric Gas and Trading
------------------- ----------------- ------------------
Operating revenues:
External customers................. $ 555,568 99.87% $ 255,975 100.00% $ 279,636 43.53%
Intersegment revenues.............. 707 0.13 -- -- 362,722 56.47
--------- ------- --------- ------- --------- -------
Total revenues..................... 556,275 100.00 255,975 100.00 642,358 100.00
--------- -------- --------- ------- --------- -------
Cost of energy sold.................. 4,572 0.82 134,755 52.64 305,525 47.56
Intersegment purchases............... 362,722 65.21 -- -- 707 0.11
--------- -------- --------- ------- --------- -------
Total fuel costs................... 367,294 66.03 134,755 52.64 306,232 47.67
--------- ------- --------- ------- --------- -------
Gross Margin......................... 188,981 33.97 121,220 47.36 336,126 52.33
--------- ------- --------- ------- --------- -------
Administrative and other costs....... 44,632 8.02 46,941 18.34 25,739 4.01
Energy production costs.............. 846 0.15 233 0.09 148,667 23.14
Depreciation and amortization........ 30,586 5.50 14,961 5.84 37,114 5.78
Transmission and distribution costs.. 31,985 5.75 24,341 9.51 130 0.02
Taxes other than income taxes........ 20,592 3.70 7,007 2.74 9,752 1.52
Income taxes......................... 19,954 3.59 8,685 3.39 23,262 3.62
--------- ------- --------- ------- --------- -------
Total non-fuel operating expenses.. 148,595 26.71 102,168 39.91 244,664 38.09
--------- ------- --------- ------- --------- -------
Operating income..................... $ 40,386 7.26% $ 19,052 7.44% $ 91,462 14.24%
--------- ------- --------- ------- --------- -------
41
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
UTILITY OPERATIONS
Electric - Operating revenues declined $2.1 million (0.4%) for the year
to $539.5 million due to the implementation in late July 1999 of the rate order
lowering rates by $22.2 million year-over-year. This was mostly offset by
increased retail electricity delivery of 7.1 million MWh compared to 6.8 million
MWh delivered in the prior year period, a 4.2% improvement which increased
revenues $21.8 million year-over-year. This increased volume was the result of
weather-related consumption and load growth.
The gross margin, or operating revenues minus cost of energy sold,
decreased $8.5 million reflecting a decrease in gross margin as a percentage of
revenues of 1.4%. This decline reflects the rate reduction discussed above, and
an increase in intersegment transfer pricing. The Company's Generation and
Trading Operations exclusively provide power to the Company's Electric Product
Offering. Intersegment purchases for the Generation and Trading Operations are
priced using internally developed transfer pricing and are not based on market
rates. Customer rates for electric service are set by the PRC based on the
recovery of the cost of power production and a rate of return that includes
certain generation assets that are part of Generation and Trading Operations,
among other things.
Administrative and general costs decreased $8.7 million (16.6%) for the
year. This decrease is due to non-recurring Year 2000 ("Y2K") compliance costs
and non-recurring costs related to the Company's implementation of its new
customer billing system in 1999. In addition, in 1999, as a result of a
significant increase in delinquent accounts due to system implementation
problems, the Company incurred additional bad debt costs of $5.5 million above
its normal experience rate. Bad debt expense in 2000 was $4.9 million, a 29.9%
decline for the year (see "Implementation of New Billing System" below for
additional discussion). As a percentage of revenues, administrative and other
costs decreased to 8.1% from 9.7% for the year ended December 31, 2000 and 1999,
respectively, primarily as a result of reduced costs.
Energy production costs decreased $1.4 million (54.1%) for the year
primarily due to non-recurring Y2K compliance costs in 2000. As a percentage of
revenues, energy production costs decreased from 0.5% to 0.2%.
Depreciation and amortization increased $1.3 million (4.2%) for the year.
The increase is due to the impact of amortizing the costs of the new customer
billing system, which has a five-year amortization life, and depreciating the
expansion of the electric distribution system. Depreciation and amortization as
a percentage of revenues increased from 5.7% to 6.0%.
Transmission and distribution costs increased $2.1 million (6.7%) for the
year primarily due to increased scheduled maintenance of transmission lines and
the addition of station related equipment for reliability purposes. This
increase in scheduled maintenance is expected to continue in 2001. As a
percentage of revenues, transmission and distribution costs increased from 5.7%
to 6.1%.
Taxes other than income decreased $4.8 million (25.3%) due to a change
in the recognition of electric franchise fees collected from customers and due
to municipalities, partially offset by the impact of the implementation of the
new customer billing system on the collection of certain taxes and an increase
42
in expected tax liabilities. Franchise fees were a part of the Company's rate
structure in the prior year. In the current year, they have been unbundled from
the rate structure. As a result, the Company is now a collection agent for the
municipalities taxes and does not incur expense or generate revenues as a result
of collecting the fees. Taxes other than income as a percentage of revenues
decreased to 2.6% from 3.5%.
Gas - Operating revenues increased $83.2 million (35.2%) for the year to
$319.9 million. This increase was driven by a 31.3% increase in the average rate
charges per decatherm due to high gas prices in the later months of 2000 as a
result of increased market demand, a 3.0% volume increase and a gas rate
increase which became effective October 30, 2000. Residential and commercial
customers volume decreased 10.5% due to unseasonably warm weather during the
early part of 2000. Customer volume, other than residential and commercial,
increased 14.9%. This growth was primarily attributed to industrial and
transportation customers such as the Company's Generation and Trading Operations
whose increased demand was driven by the strong power market in the Western
United States. Such growth is unlikely to recur in 2001.
The gross margin, or operating revenues minus cost of energy sold,
increased $0.8 million (0.7%). This increase is due to higher distribution
volumes on which the Company earns cost of service revenues. The Company
purchases natural gas in the open market and resells it at cost to its
distribution customers. As a result, the increase in gas prices driving
increased cost of sales revenues does not have an impact on the Company's gross
margin or earnings. In addition, the rate increase partially contributed to the
increase in gross margin.
Administrative and general costs decreased $6.5 million (13.0%). This
decrease is mainly due to non-recurring Y2K compliance costs, customer billing
system costs and lower associated bad debt costs. The Electric and Gas Product
Offerings share the same billing system, and the Gas Product Offering
experienced the same delinquency problems discussed above in the "Electric
Product Offering" results of operations. As a result in 1999, the Company
incurred additional bad debt costs of $2.7 million above its normal experience
rate. However, bad debt expense did not significantly decline in 2000 as the
Company increased its bad debt costs by approximately $2 million in anticipation
of a higher than normal delinquency rate driven by the significantly higher
natural gas prices experienced in November and December 2000. This trend is
similar to historic collection trends associated with past gas price spikes.
Depreciation and amortization increased $0.8 million (4.1%) for the year.
The increase is due to the impact of amortizing the costs of a new customer
billing system and depreciating the expansion of the gas transmission system.
Transmission and distribution costs decreased $1.0 million (3.6%)
primarily due to non-recurring Y2K compliance costs.
Taxes other than income increased $1.8 million (25.5%) primarily due to
higher tax liabilities and the impact of the implementation of the new customer
billing system on the collection of certain taxes.
43
GENERATION AND TRADING OPERATIONS
Operating revenues grew $385.2 million (55.8%) for the year to $1.08
billion. This increase in wholesale electricity sales reflects strong regional
wholesale electric prices caused by a warm summer, limited power generation
capacity, increasing natural gas prices and the power supply imbalance in the
Western United States. These factors contributed to unusually high wholesale
prices which the Company does not believe to be sustainable in the long-term,
but continue to effect markets in 2001. In addition, these factors have led to
an extremely volatile wholesale electric power market with significant risk (see
Other Issues Facing the Company - Western United States Wholesale Power Market).
The Company delivered wholesale (bulk) power of 12.4 million MWh of electricity
this period compared to 11.2 million MWh delivered last year, an increase of
10.6%. The MWh increase is attributable to increased trading activity during the
year. Wholesale revenues from third-party customers increased from $371.1
million to $750.4 million, a 102.2% increase. The increase was largely price
driven.
The gross margin, or operating revenues minus cost of energy sold,
increased $50.2 million (18.3%). Higher margins were partially offset by $8.5
million of losses associated with the Company's assessment of risk in the
wholesale market (see Other Issues Facing The Company - Western United States
Wholesale Power Market) and unrealized mark-to-market losses of $4.8 million
which the Company recognized relating to its power trading contracts (see Note
(5) of the Notes to Consolidated Financial Statements). These items were
recorded as revenue adjustments. Gross margin as a percentage of revenues
decreased from 39.8% to 30.2% reflecting higher fuel and purchased power costs
due to higher wholesale sales volumes and scheduled outages at the Company's San
Juan Generating Station and Four Corners Plant. The Company expects similar
planned outages in 2001.
Administrative and general costs increased $3.2 million (12.0%) for the
year. This increase is due to a one-time charge of $4.5 million in connection
with the acquisition of a new, long-term wholesale customer (see Note (11) of
the Notes to Consolidated Financial Statements) and an increase in bad debt
costs, partially offset by lower legal costs related to a lawsuit settlement
involving the Company's decommissioning trust (which was settled in August 2000;
see Consolidated Results of Operations discussion) and non-recurring Y2K
compliance costs. As a percentage of revenues, administrative and other costs
decreased to 2.8% from 3.9% for the year ended December 31, 2000 and 1999,
respectively as a result of increased revenues.
Energy production costs increased $4.4 million (3.3%) for the year. These
costs are generation related. The increase is due to higher maintenance costs
resulting from scheduled outages at San Juan Unit 3 and Four Corners Unit 4,
which were partially offset by lower PVNGS employee costs as a result of
additional employee incentive and retiree healthcare costs in the prior year
that did not recur in 2000 and additional PVNGS billings in 1999 for 1998
expenses as a result of an audit by the station owners. As a percentage of
revenues, energy production costs decreased from 19.3% to 12.8%. The decrease is
primarily due to a significant increase in energy sales.
Taxes other than income increased $2.4 million (26.9%) due to higher tax
liabilities. Taxes other than income as a percentage of revenues decreased
slightly from 1.3% to at 1.1% as a result of the increase in energy sales.
44
UNREGULATED BUSINESSES
Avistar contributed $2.2 million in revenues for the year compared to
$8.9 million in the comparable prior year period due to lower business volumes
resulting from slow developing markets associated with Avistar's new product
offerings. Operating losses for Avistar increased from $4.4 million in the prior
year to $6.6 million in the current year.
CONSOLIDATED
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, increased $8.0 million for
the year. This increase was due to additional administrative and consulting
expenses for strategic initiatives, higher legal costs and reorganizational
costs incurred in anticipation of separating utility operations under the
Restructuring Act.
Other income and deductions, net of taxes, increased $4.2 million for the
year to $34.4 million due to gains, $13.2 million before income taxes related to
the settlement of a lawsuit (see "Other Issues Facing the Company - Nuclear
Decommissioning Trust") and $4.6 million before income taxes related to the
resolution of two gas rate cases (see "Other Issues Facing The Company - Gas
Rate Orders"). The current year also had increased mark-to-market gains on the
corporate hedge (see "Note 5 to the Consolidated Financial Statements"). These
increases were partially offset by $6.7 million before income taxes of costs
related to the Company's proposed acquisition of Western Resources' electric
utility assets. The Company expects to continue to incur acquisition related
costs in 2001 and beyond. While these costs were deductible for income tax
purposes in 2000, a significant portion of these future costs may not be tax
deductible. In addition, other income and deductions included a valuation loss
recognized for Avistar's AMDAX.com investment, and expenses related to the
transfer of the operation of the City of Santa Fe's water system to the
municipality. In 1999, other income and deductions included gains, net of taxes,
of $4.2 million of equity income from a passive investment and $1.2 million from
closing down certain coal mine reclamation activities in an inactive subsidiary.
Net interest charges decreased $4.7 million for the period to $65.9
million primarily as a result of the retirement of $31.6 million of senior
unsecured notes in June and August 1999 and $32.8 million in January 2000.
The Company's consolidated income tax expense, before the cumulative
effect of an accounting change, was $74.3 million, an increase of $32.0 million
for the year. The Company's 2000 income tax effective rate, before the
cumulative effect of the accounting change, was 42.4%. Included in the Company's
2000 income tax expense is the write-off of $6.6 million of income tax related
regulatory assets. These assets relate to pre-1981 electric utility rate
adjustments for certain tax benefits. The write-off of these assets reflects
management's view of the probable financial outcome of utility deregulation in
New Mexico, based on existing circumstances. Excluding the write-off of income
tax related regulatory assets, the Company's effective tax rate was 38.7%. The
Company's 1999 effective tax rate was 34.7%. The increase in the rate was
primarily due to the favorable tax treatment received on the 1999 equity
earnings discussed above.
45
The Company's net earnings from continuing operations for the year ended
December 31, 2000 were $100.9 million, a 26.8% increase. These results were
impacted by certain special items comprised of gains from the settlement of a
lawsuit and the favorable resolution of two gas rate cases and charges related
to the impairment of certain regulatory assets, the acquisition of a new
long-term wholesale customer and the proposed acquisition of Western Resources
("2000 Special Items"). The Company's net earnings excluding the 2000 Special
Items were $102.6 million. Net earnings for the year ended December 31, 1999
included certain special items comprised of gains related to equity income from
a passive investment and mine closure activities and bad debt costs associated
with system implementation problems ("1999 Special Items"). Net earnings from
continuing operations excluding the 1999 and 2000 Special Items increased from
$78.5 million in 1999 to $102.6 million in 2000.
Earnings per share from continuing operations excluding the cumulative
effect of the accounting change on a diluted basis were $2.58 (excluding the
2000 Special Items) for the year ended December 31, 2000 compared to $1.91
(excluding the 1999 Special Items) for the year ended December 31, 1999. Diluted
weighted average shares outstanding were 39.7 million and 41.1 million in 2000
and 1999, respectively. The decrease reflects the common stock repurchase
program in 1999 and 2000. Net earnings per share from continuing operations
primarily increased due to expansion of the Company's wholesale energy trading
activities and the common stock repurchase program.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
UTILITY OPERATIONS
Electric - Operating revenues decreased $14.8 million (2.6%) for the
year to $541.6 million primarily due to the implementation of a new rate order
in late July 1999 (which lowered rates by $18 million year over year). The rate
reduction was partially offset by an increase in volume. Retail electricity
delivery was 6.8 million MWh compared to 6.7 million MWh delivered last year, a
1.5% improvement. Sales volume growth was negatively impacted by cooler
temperatures during the summer months.
The gross margin, or operating revenues minus cost of energy sold,
increased $29.2 million (15.5%) reflecting an increase in gross margin as a
percentage of revenues of 6.3%. This increase reflects a decrease in
intersegment transfer prices, partially offset by the rate reduction discussed
above. The Company's Generation and Trading Operations exclusively provide power
to the Company's Electric Product Offering. Intersegment purchases for the
Generation and Trading Operations are priced using internally developed transfer
pricing and are not based on market rates.
Administrative and general costs increased $8.0 million (17.8%) for the
year. This increase is due to Y2K compliance costs and costs related to the
Company's implementation of its new customer billing system. In addition, the
Company incurred incremental bad debt costs throughout 1999 of $5.5 million as a
result of a significant increase in delinquent accounts due to system
implementation problems (see "Implementation of New Billing System" below for
additional discussion). As a percentage of revenues, administrative and general
costs increased from 8.0% to 9.7%.
46
Energy production costs increased $1.8 million for the year primarily due
to Y2K compliance costs in 1999. As a percentage of revenues, energy production
costs increased from 0.2% to 0.5%.
Depreciation and amortization increased $0.5 million (1.7%) for the year.
The increase is due to the impact of the new customer billing system. As a
result of this, the Company revised its depreciation rates as required by the
PRC. Depreciation and amortization as a percentage of revenues increased from
5.5% to 5.7% largely reflecting the decrease in energy sales.
Transmission and distribution costs decreased $1.0 million (3.0%) for the
year. This was primarily the result of lower maintenance costs due to the milder
weather. As a percentage of revenues, transmission and distribution costs
remained relatively constant at 5.7% and 5.8% for the years ended December 31,
1999 and 1998, respectively.
Gas - Operating revenues declined $19.3 million (7.5%) for the year to
$236.7 million. This decline was driven by a 13.8% decline in the average rate
charges per decatherm due to weak gas prices and a mild winter. Price declines
were partially offset by a 7.7% volume improvement, as transportation volume
posted double-digit growth of 10.3%.
The gross margin, or operating revenues minus cost of energy, increased
$2.6 million (2.1%). This increase is due to changes in access fee options and
increased volume sales.
Administrative and general increased $2.8 million (5.9%). This increase
is mainly due to Y2K compliance costs and costs related to the Company's
implementation of its new customer billing system. In addition, the Company
incurred higher bad debt costs throughout 1999 of $2.7 million, as a result of a
significant increase in delinquent accounts due to system implementation
problems (see "Implementation of New Billing System" below for additional
discussion).
Depreciation and amortization increased $4.2 million (28.4%) for the
year. The increase is due to the impact of the new customer billing system. As a
result of the addition, the Company revised its depreciation rates as required
by the PRC.
Transmission and distribution expenses increased $3.9 million (16.0%) for
the year. The increase is primarily due to Y2K compliance costs.
GENERATION AND TRADING OPERATIONS
Operating revenues grew $47.6 million (7.4%) for the year to $690.0
million due to an improvement in wholesale electricity sales volume. The Company
delivered wholesale (bulk) power of 11.2 million MWh of electricity this year
compared to 8.8 million MWh delivered last year, an increase of 27.2%. Revenue
growth was negatively impacted by cooler temperatures in the southwest during
the summer months and the availability of abundant hydro power that negatively
impacted market prices in the Western United States.
The gross margin, or operating revenues minus cost of energy, decreased
$61.4 million reflecting a decrease in gross margin as a percentage of revenues
of 23.9%. This decline reflects higher fuel and purchased power costs as a
result of increased sales and higher prices.
47
Administrative and general costs increased $1.1 million (4.1%) for the
year. This increase is due to Y2K compliance costs and higher legal costs
related to a lawsuit involving the Company's decommissioning trust. These
increases were offset by an additional allocation of costs for 1998 and 1999 to
the participants in the jointly-owned SJGS following an audit by the owners of
the station. As a percentage of revenues, administrative and general costs
decreased from 4.0% to 3.9% primarily due to the increase in sales.
Energy production costs decreased $15.9 million (10.7%) for the year.
These costs are generation related. The decrease is primarily due to reduced
nuclear fuel storage costs at PVNGS. In 1998, the Company incurred costs of
$12.1 million for spent nuclear fuel at PVNGS as it was determined that
alternatives to the DOE storage and disposal facilities would be necessary due
to the DOE's failure to complete such facilities by 1998 as required by law.
These costs represent the cost of storage for spent fuel through 1998. As a
percentage of revenues, energy production costs decreased from 23.1% to 19.3%.
The decrease is due to cost control and the decreased nuclear fuel storage costs
and the increase in sales.
Depreciation and amortization increased $3.1 million (8.5%) for the year.
The increase is due to pollution control improvements at certain generation
plants. As a result of the additions, the Company revised its depreciation rates
as required by the PRC. Depreciation and amortization as a percentage of
revenues remained constant at 5.8% reflecting an increase in expense offset by
the increase in energy sales.
UNREGULATED BUSINESSES
Avistar contributed $8.9 million in revenues in 1999 compared to $1.3
million in 1998. Operating loss for the unregulated businesses decreased from
$5.9 million in 1998 to $4.4 million in 1999 reflecting their expanded operating
activities.
CONSOLIDATED
Corporate administrative and general costs remained relatively constant
at $12.7 million for the year.
Other income and deductions, net of taxes, increased $7.5 million for the
year to $30.2 million due to the recording of interest income from the PVNGS
Capital Trust. In addition, other income included certain one-time net gains in
1999 and 1998. In 1999, the Company recognized $4.2 million of equity income
from a passive investment and a gain of $1.2 million as a result of closing down
of coal mining reclamation activities in an inactive subsidiary. In 1998, the
Company recognized $1.3 million in a lawsuit settlement and $1.5 million from
the reversal of a gas rate case reserve.
Net interest charges increased $7.5 million for the year to $70.7
million as a result of the issuance of $435 million in senior unsecured notes in
August 1998, which replaced first mortgage bonds with a lower interest rate, and
the issuance of pollution control revenue bonds of $11.5 million in October
1999. This was partially offset by the retirement of $31.6 million of senior
unsecured notes in June and August 1999 and a decrease in short-term debt
interest charges due to lower short-term borrowings in 1999.
48
The Company's consolidated income tax expense, before the cumulative
effect of accounting change and discontinued operations, was $42.3 million, a
decrease of $14.0 million for the year. The Company's income tax effective rate,
before the cumulative effect of accounting change and discontinued operations,
decreased from 37.2% to 34.7%. This decrease is primarily due to the favorable
tax treatment received on the equity income discussed above. The investment
income qualifies for the 80% dividends received deduction under Internal Revenue
Service regulations.
The Company's net earnings from continuing operations for the year ended
December 31, 1999, were $78.5 million, excluding the one-time gains related to
equity income from a passive investment and mine closure activities and the
one-time charge for bad debt associated with system implementation problems
("1999 Special Items") compared to $99.0 million, excluding one-time gains for
proceeds from a litigation settlement and the reversal of a gas rate case
reserve and the one-time charge for spent nuclear fuel costs at PVNGS ("1998
Special Items") for the year ended December 31, 1998.
Earnings per share from continuing operations on a diluted basis
excluding the cumulative effect of the accounting change were $1.91 (excluding
the 1999 Special Items) for the year ended December 31, 2000 compared to $2.35
(excluding the 1998 Special Items) for the year ended December 31, 1998. Diluted
weighted average shares outstanding were 41.1 million and 42.1 million in 1999
and 1998, respectively. The decrease reflects the common stock repurchase
program in 1999. The 1999 results were negatively impacted by the electric rate
reduction in the third quarter, increased fuel and purchased power costs, a weak
gas market and cooler weather in the West during the summer months. In addition,
Y2K compliance and the implementation of the new customer billing system
increased costs. This impact was partially offset by the gains recorded in other
income.
Discontinued Operations - In August 1998, the Company adopted a plan to
discontinue the natural gas trading operations of its Energy Services Business
Unit and completely discontinued these operations on December 31, 1998. Losses
from discontinued operations, net of taxes, for the year ended December 31,
1998, were $12.4 million, or $0.30 per common share. These losses did not recur
in 1999.
Cumulative Effect of a Change in Accounting Principle - Effective
January 1, 1999, the Company adopted Energy Issues Task Force Issue No. 98-10.
The effect of the initial application of the new standard is reported as a
cumulative effect of a change in accounting principle. As a result, the Company
recorded additional earnings, net of taxes, of approximately $3.5 million, or
$0.08 per common share, to recognize the gain on net open physical electricity
purchase and sales commitments considered to be trading activities.
FUTURE EXPECTATIONS
On January 27, 2001, the Company announced that it expected its 2001
earnings to be within the range of $2.60 to $2.70 per diluted share. This
estimate is based on the Company's strong results in 2000, and management's view
of developments in the wholesale power marketplace in the beginning of 2001.
Management believes that the strong wholesale power market experienced in the
third and fourth quarters of 2000 will continue into the first two quarters of
2001, while the third and fourth quarters of 2001 are not expected to experience
49
the demand that drove wholesale power prices in the comparable quarters in 2000;
therefore, management's expectation is that the third and fourth quarters' net
earnings may be lower than in 2000. The Company's wholesale power marketing
operations are expected to continue to expand in 2001. Accordingly, these
earnings expectations factor in the anticipated continued volatility seen in the
wholesale marketplace in 2000, and appropriate allowances have been made in
these estimates for this market risk, similar in nature to the $8.5 million of
losses recognized for market risk in 2000.
Management's expectations for 2001 assume retail sales growth will
continue at rates comparable to what was experienced in 2000 and the full
realization of the favorable outcome of the two gas rate cases settled in August
of 2000. Expenses are expected to increase due to inflation, growth initiatives
and regulatory filing costs. These earnings estimates do not include any costs
related to the Company's acquisition of the electric utility assets of Western
Resources which are expected to be approximately $10 to $15 million. The
significant capital additions in 2000 are expected to result in increased
depreciation and amortization expense in 2000. In addition, because of
initiatives undertaken in 2000, it is expected that reduced losses in the
non-regulated businesses will contribute to net earnings.
This discussion of future expectations is forward looking information
within the meaning of Section 21E of the Securities and Exchange Act. The
achievement of expected results is dependent upon the assumptions described in
the preceding discussion, and is qualified in its entirety by the Private
Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding
Forward Looking Statements" below) - and the factors described within the
disclosure which could cause the Company's actual financial results to differ
materially from the expected results enumerated above.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2000, the Company had working capital of $147.8 million
including cash and cash equivalents of $107.7 million. This is a decrease in
working capital of $19.3 million from December 31, 1999. This decrease primarily
reflects the Company's increased activity in the wholesale power market.
Cash generated from operating activities was $239.5 million, an increase
of $26.5 million from 1999. This increase was primarily the result of increased
profitability including the favorable settlement of a lawsuit. In addition,
accounts payable increased due to increased wholesale power purchases driven by
the Company's expansion of its wholesale power marketing operations. This
increase was partially offset by an increase in the Company's receivables.
Unrecovered purchased gas adjustments and accounts receivable from utility
customers increased as a result of higher gas prices. In addition, accounts
receivable increased as a result of increased wholesale electricity sales.
50
Cash used for investing activities was $157.5 million in 2000 compared
to $55.9 million in 1999. This increased spending reflects $13.3 million related
to the acquisition of transmission assets (see "Acquisition of Certain Assets
and Related Agreements" below), combustion turbine option payments of $13.0
million, the expansion of the electric distribution system at a cost of $13.7
million and the gas transmission and distribution systems at a cost of $10.1
million to serve new load and for reliability purposes, an investment in an
internet gateway service provider of $10.0 million and additional funding and
realized gains in the decommissioning trust of $9.3 million. Cash used for
investing activities in 2000 includes the $6.7 million of costs related to the
acquisition of Western Resources electric utility assets. In addition, in 1999
the Company liquidated certain insurance-based investments in the nuclear
decommissioning trust of $26.6 million.
Cash used for financing activities was $94.7 million in 2000 compared to
$98.0 million in 1999. This decrease reflects $26.6 million of loan repayments
associated with nuclear decommissioning trust activities in 1999, partially
offset by the issuance of $11.5 million of 6.60% Pollution Control Revenue Bonds
in 1999 and increased common stock repurchases in 2000 (see "Stock Repurchase"
below).
Capital Requirements
Total capital requirements include construction expenditures as well as
other major capital requirements and cash dividend requirements for both common
and preferred stock. The main focus of the Company's construction program is
upgrading generation systems, upgrading and expanding the electric and gas
transmission and distribution systems and purchasing nuclear fuel. In addition,
the Company anticipates significant expenditures to expand its generation
capabilities. Projections for total capital requirements and construction
expenditures for 2001 are $353 million and $347 million, respectively. Such
projections for the years 2001 through 2005 are $1.45 billion and $1.42 billion,
respectively. These estimates are under continuing review and subject to
on-going adjustment (see "Competitive Strategy" above).
The Company's construction expenditures for 2000 were entirely funded
through cash generated from operations. The Company currently anticipates that
internal cash generation and current debt capacity will be sufficient to meet
capital requirements for the years 2001 through 2005, except as provided for in
its proposed plan to separate pursuant to the Restructuring Act (see "Proposed
Holding Company Plan" below). To cover the difference in the amounts and timing
of cash generation and cash requirements, the Company intends to use short-term
borrowings under its liquidity arrangements.
51
Liquidity
At February 1, 2001, the Company had $175 million of available liquidity
arrangements, consisting of $150 million from a senior unsecured revolving
credit facility ("Credit Facility"), and $25 million in local lines of credit.
The Credit Facility will expire in March 2003. There were no outstanding
borrowings as of February 1, 2001.
The Company's ability to finance its construction program at a reasonable
cost and to provide for other capital needs is largely dependent upon its
ability to earn a fair return on equity, results of operations, credit ratings,
regulatory approvals and financial market conditions. Financing flexibility is
enhanced by providing a high percentage of total capital requirements from
internal sources and having the ability, if necessary, to issue long-term
securities, and to obtain short-term credit.
In connection with the Company's announcement of its proposed acquisition
of Western Resources' electric utility operations, Standard and Poors ("S&P"),
Moody's Investor Services ("Moody's") and Fitch IBCA, Duff & Phelps ("Fitch")
have placed the Company's securities ratings on negative credit watch pending
review of the transaction. The Company is committed to maintaining its
investment grade. S&P has rated the Company's senior unsecured debt and its EIP
senior secured debt "BBB-" and its preferred stock "BB". Moody's has rated the
Company's senior unsecured notes and senior unsecured pollution control revenue
bonds "Baa3"; and preferred stock "ba1". The EIP lease obligation bonds are also
rated "Ba1". Fitch rates the Company's senior unsecured notes and senior
unsecured pollution control revenue bonds "BBB-," the Company's EIP lease
obligation "BB+" and the Company's preferred stock "BB-." Investors are
cautioned that a security rating is not a recommendation to buy, sell or hold
securities, that it may be subject to revision or withdrawal at any time by the
assigning rating organization, and that each rating should be evaluated
independently of any other rating.
In addition to the impact of the proposed acquisition of Western
Resources' electric utility operations, future rating actions for the Company's
securities will depend in large part on the actions of the PRC relating to
numerous restructuring issues, including the Company's proposed plan to separate
the utility into a generation business and a distribution and transmission
business as required by the Restructuring Act ("Proposed Plan"). The Company
believes, based on its Proposed Plan (see "Proposed Holding Company Plan"
below), that UtilityCo and PowerCo will both receive investment grade credit
ratings, however, such ratings will be contingent upon many factors that have
yet to be determined. Fitch announced publicly that assuming the Company
implements its Proposed Plan, it would expect to issue investment grade ratings
for UtilityCo, and PowerCo's rating would "border investment grade". Fitch
cautioned that ratings for UtilityCo and PowerCo were highly conditional upon
reaching assumptions provided by the Company.
Covenants in the Company's Palo Verde Nuclear Generating Station Units 1
and 2 lease agreements limit the Company's ability, without consent of the owner
participants in the lease transactions: (i) to enter into any merger or
consolidation, or (ii) except in connection with normal dividend policy, to
convey, transfer, lease or dividend more than 5% of its assets in any single
transaction or series of related transactions. The Credit Facility imposes
similar restrictions regardless of credit ratings.
52
Financing Activities
In January 2000, the Company reacquired $34.7 million of its 7.5% senior
unsecured notes through open market purchases at a cost of $32.8 million.
The Company currently has no requirements for long-term financings during
the period of 2001 through 2004, except as part of its Proposed Plan (see
"Proposed Holding Company Plan" below). However, during this period, the Company
could enter into long-term financings for the purpose of strengthening its
balance sheet and reducing its cost of capital. The Company continues to
evaluate its investment and debt retirement options to optimize its financing
strategy and earnings potential. No additional first mortgage bonds may be
issued under the Company's mortgage. The amount of SUNs that may be issued is
not limited by the SUNs indenture. However, debt to capital requirements in
certain of the Company's financial instruments would ultimately restrict the
Company's ability to issue SUNs.
Proposed Holding Company Plan
On April 18, 2000, the Company filed as an exhibit on Form 8-K, unaudited
pro forma financial statements of PowerCo and UtilityCo that give effect to the
Company's Proposed Plan. The structure of the Proposed Plan presented in the
April 18, 2000 Form 8-K was subsequently revised in October 2000 by the Company.
This revised Proposed Plan results in a capital structure for the holding
company, PowerCo and UtilityCo similar to the presentation in the Form 8-K. The
revised Proposed Plan is subject to regulatory and other approvals as well as
market, economic and business conditions. As such, the revised Proposed Plan may
be subject to significant changes before implementation and the pro forma
financial statements as filed in the Form 8-K may require revision to reflect
the final plan of separation pursuant to the Restructuring Act.
The revised Proposed Plan assumes that the separation required under the
Restructuring Act will be accomplished as follows: PowerCo will transfer its
regulated assets to a wholly owned subsidiary, UtilityCo, in exchange for common
stock, UtilityCo preferred stock, UtilityCo senior unsecured notes and cash.
UtilityCo will also assume certain liabilities associated with the regulated
assets. PowerCo will then dividend the common stock of UtilityCo to the holding
company.
The current holders of PowerCo's public SUNs will be offered the
opportunity to exchange their approximately $368 million of existing SUNs for
$368 million of SUNs issued by UtilityCo with like terms and conditions. The
current holders of PowerCo's preferred stock will be offered the opportunity to
exchange their approximately $12.8 million of preferred stock for preferred
stock issued by UtilityCo with like terms and conditions.
Although there are other alternatives to finance the acquisition of the
regulated assets from PowerCo, based on current market, economic and business
conditions, the Company currently believes that the foregoing transactions
represent the most advantageous way to effect the Asset Transfer. However, the
structure of the revised Proposed Plan is subject to change as the regulatory
approval process continues and is ultimately resolved. Implementation of the
Proposed Plan in 2001 is dependent on the outcome of certain pending legislation
which if enacted, would delay restructuring for five more years.
53
A condition precedent to corporate separation is the obtaining of written
consents from PVNGS lessors. As of December 31, 2000, two lessors had signed
consents, one lessor has agreed in principle to the terms of the signed consent
but had not signed, and two lessors had not agreed to those terms. The signed
consents have various financial covenants which limit PowerCo's ability to sell,
transfer or convey its assets assuming certain coverage ratios are not met.
Additionally, the consents require the holding company to guarantee the leases.
The consents and the covenants will not become effective until corporate
separation occurs.
Stock Repurchase
In March 1999, the Company's board of directors approved a plan to
repurchase up to 1,587,000 shares of the Company's outstanding common stock with
maximum purchase price of $19.00 per share. In December 1999, the Company's
board of directors authorized the Company to repurchase up to an additional
$20.0 million of the Company's common stock. As of December 31, 1999, the
Company repurchased 1,070,700 shares of its previously outstanding common stock
at a cost of $18.8 million. From January 2, 2000 through March 31, 2000, the
Company repurchased an additional 1,167,684 shares of its outstanding common
stock at a cost of $18.9 million. The Company has repurchased all shares
authorized in March 1999 and December 1999 by the Board of Directors.
On August 8, 2000, the Company's Board of Directors approved a plan to
repurchase up to $35 million of the Company's common stock through the end of
the first quarter of 2001. From August 8, 2000 through December 31, 2000 Company
repurchased an additional 417,900 shares of its outstanding common stock at a
cost of $9.0 million. As of February 1, 2001, the Company does not anticipate
continuing its repurchase plan given the share price of its common stock.
Acquisition of Certain Assets and Related Agreements
The Company and Tri-State Generation and Transmission Association, Inc.
("Tri-State") entered into an asset sale agreement dated September 9, 1999,
pursuant to which Tri-State has agreed to sell to the Company certain assets
acquired by Tri-State as the result of Tri-State's merger with Plains Electric
Generation and Transmission Cooperative, Inc. ("Plains") consisting primarily of
transmission assets, a fifty percent interest in an inactive power plant located
near Albuquerque, and an office building. The purchase price was originally
$13.2 million, subject to adjustment at the time of closing, with the
transaction to close in two phases. On July 1, 2000, the first phase was
completed, and the Company acquired the 50 percent ownership in the inactive
power plant and the office building. The second phase relating to the
transmission assets is expected to close in the first quarter 2001.
In addition, on July 1, 2000, the Company advanced $11.8 million to a
former Plains cooperative member as part of an agreement for the Company to
become the cooperative's power supplier. Approximately $4.5 million of this
advance represents an inducement for entering into a 10 year power sales
agreement. Accordingly, the Company expensed this amount in the third quarter as
a business development cost. The remaining $7.5 million will be repaid over 10
years. If the cooperative terminates the contract early, the whole $11.8 million
advance must be repaid to the Company.
54
Dividends
The Company's board of directors reviews the Company's dividend policy
on a continuing basis. The declaration of common dividends is dependent upon a
number of factors including the extent to which cash flows will support
dividends, the availability of retained earnings, the financial circumstances
and performance of the Company, the PRC's decisions on the Company's various
regulatory cases currently pending, the effect of deregulating generation
markets and market economic conditions. The ability to recover stranded costs in
deregulation, future growth plans and the related capital requirements and
standard business considerations will also affect the Company's ability to pay
dividends. In addition, following the separation as required by the
Restructuring Act, the ability of the proposed holding company to pay dividends
will depend initially on the dividends and other distributions that UtilityCo
and PowerCo pay to the holding company.
Capital Structure
The Company's capitalization, including current maturities of long-term
debt, at December 31 is shown below:
2000 1999
---- ----
Common Equity............................ 48.6% 46.7%
Preferred Stock.......................... 0.7 0.7
Long-term Debt........................... 50.7 52.6
----- -----
Total Capitalization*................. 100.0% 100.0%
===== =====
* Total capitalization does not include as debt the present value of
the Company's lease obligations for PVNGS Units 1 and 2 and EIP which
was $162 million as of December 31, 2000 and $165 million as of
December 31, 1999.
55
OTHER ISSUES FACING THE COMPANY
THE RESTRUCTURING ACT, THE FORMATION OF HOLDING COMPANY
AND CORPORATE SEPARATION
The Company has filed its transition plan with the PRC pursuant to the
Restructuring Act in three parts. In November 1999, the Company filed the first
two parts of the transition plan with the PRC. Part one, which has been
approved, requested approval to create Manzano and UtilityCo as wholly-owned
shell subsidiaries of the Company. Part two of the Company's transition plan
requested all PRC approvals necessary for the Company to implement the formation
of the holding company structure, the share exchange and the separation plan.
Part Two is awaiting a recommended decision by the hearing examiner. Under
existing deadlines, the Company must separate its assets no later than August 1,
2001. The Company's management believes that implementation of the separation
plan will not occur prior to August 1, 2001, and there is no assurance that
implementation of the separation plan will occur by that time. On May 31, 2000,
the Company filed with the PRC part three of the transition plan requesting
approval for the recovery of stranded costs and other expenses associated with
the transition to a competitive market, UtilityCo's rates for retail
distribution services, the procurement of "standard offer service" power
supplies for customers who do not select a power supplier and other issues
required to be considered under the Restructuring Act. The Hearing Examiner has
tentatively scheduled hearings on Part three to begin on June 6, 2001. Hearings
are expected to last four to six weeks.
On August 17, 2000, the PRC staff and other parties filed a Joint Motion
to Defer Commission Decision on Separation of Generation Assets and to extend
the Standard Offer Update Deadline. The Joint Motion requested that the PRC not
allow separation to occur until after the 2001 legislative session to allow the
legislature to determine if any amendments to the Restructuring Act might be
necessary in light of the high prices experienced last year in California. The
2001 legislative session began January 16 and ends March 17. On September 11,
2000, the Company filed its response to the Joint Motion, pointing out key
differences between New Mexico's Restructuring Act and California's as well as
differing circumstances between the two states. On September 26, 2000, the PRC
conducted a workshop where numerous interested parties commented on the
California experience and its relevance to New Mexico. To date, the PRC has not
formally acted on the Joint Motion.
The New Mexico Legislature is currently considering various legislative
initiatives that could delay open access and activities under the Restructuring
Act, including corporate separation. Legislators are concerned by the turmoil in
the California retail energy market. On February 14, 2001, Senate Bill 266, as
amended, passed the Senate 39-0. The bill delays implementation of
restructuring, including corporate separation, by an additional five years. The
PRC would have the authority to delay for another year under certain
circumstances. The amended bill would require the PRC to approve a holding
company, without asset separation, by July 1, 2001. In addition, the amended
bill allows utilities to engage in unregulated power generation business
activities until corporate separation is implemented. The cost of new
unregulated utility generation resources will serve as a cap on the price of new
resources needed to serve retail customers until restructuring is implemented.
56
Although the amended bill passed the Senate unanimously, the Company is unable
to predict if it will pass the House of Representatives and in what form, and if
passed by the House, if it will be signed by the Governor. If enacted in its
current form, Senate Bill 266 will provide the Company with significant
flexibility to pursue its growth strategy, despite the delay in restructuring.
The Company had been in discussions with the PRC staff and other parties
in an attempt to arrive at a settlement agreement which addresses the concerns
of the parties and allows separation to continue without significant delay. The
discussions have not continued pending conclusion of the New Mexico Legislative
session in mid March, 2001. However, if Restructuring is not delayed by the
Legislature, it is likely the discussions will be revived. The potential outcome
of any future discussions may be different from the plan the Company filed on
May 31, 2000 and could potentially affect the realizability of certain
regulatory assets recorded by the Company (See "Other Issues Facing the Company
- - The Restructuring Act and Formation of the Holding Company - Stranded Costs").
In addition to the PRC's approval, completion of corporate separation
will require a number of regulatory approvals by, among others, the Securities
and Exchange Commission. Approvals from the Federal Energy Regulatory Commission
and the Nuclear Regulatory Commission have been obtained. In June 2000,
shareholders approved the share exchange; however, completion of corporate
separation will also require certain other consents. Completion may also entail
significant restructuring activities with respect to the Company's existing
liquidity arrangements and the Company's publicly-held senior unsecured notes of
which $368 million were outstanding as of December 31, 2000. Under the Proposed
Plan, holders of the Company's senior unsecured notes, $100 million at 7.5% and
$268.4 million at 7.1%, will be offered the opportunity to exchange their
securities for like senior unsecured notes to be issued by the newly created
regulated business (see "Liquidity and Capital Resources - Financing Activities
and Proposed Holding Company Plan" above).
Stranded Costs
The Restructuring Act recognizes that electric utilities should be
permitted a reasonable opportunity to recover an appropriate amount of the costs
previously incurred in providing electric service to their customers ("stranded
costs"). Stranded costs represent all costs associated with generation-related
assets, currently in rates, in excess of the expected competitive market price
over the life of those assets and include plant decommissioning costs,
regulatory assets, and lease and lease-related costs. Utilities will be allowed
to recover no less than 50% of stranded costs through a non-bypassable charge on
all customer bills for five years after implementation of customer choice. The
PRC could authorize a utility to recover up to 100% of its stranded costs if the
PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is
necessary to maintain the financial integrity of the public utility; (iii) is
necessary to continue adequate and reliable service; and (iv) will not cause an
increase in rates to residential or small business customers during the
transition period. The Restructuring Act also allows for the recovery of nuclear
decommissioning costs by means of a separate wires charge over the life of the
underlying generation assets (see "NRC Prefunding" below).
57
The calculation of stranded costs is subject to a number of highly
sensitive assumptions, including the date of open access, appropriate discount
rates and projected market prices, among others. On May 31, 2000, the Company
filed with the PRC its proposal to recover its stranded costs. These costs,
excluding nuclear decommissioning costs, total a present value of $691.6
million. In addition, stranded costs associated with decommissioning the
Company's portion of the Palo Verde nuclear plant total an additional present
value of $44.4 million. This amount considers the effect of expected earnings on
the Company's qualified nuclear decommissioning trusts.
Approximately $141 million of costs associated with the unregulated
businesses under the Restructuring Act were established as regulatory assets.
Because of the Company's belief that recovery is probable, these regulatory
assets continue to be classified as regulatory assets, although the Company has
discontinued Statement of Financial Accounting Standards No. 71, "Accounting for
the Effects of Certain Types of Regulation" (SFAS 71) and adopted Statement of
Financial Accounting Standards No. 101, "Regulated Enterprises--Accounting for
the Discontinuance of Application of FASB Statement 71." In 2000, the Company
expensed $6.6 million of these assets based on management's view of the probable
financial outcome of restructuring in New Mexico upon existing circumstances. If
discussions with the PRC staff and other parties result in a settlement in which
the amount the Company recovers for stranded costs is less than the amount it
has recorded on the balance sheet as regulatory assets, the Company will be
required to write-off the difference between its recovery of these costs and the
amount it has currently recorded. Likewise, if a delay in corporate separation
occurs, the Company may be required to write-off all or a portion of these
assets due to the uncertainty of recovery resulting from enactment of the delay.
However, Senate Bill 266, as amended, establishes certain regulatory provisions
affecting these costs, which if enacted along with the delay, will allow the
Company to recover mine reclamation costs (see Note 2 to the Consolidated
Financial Statements).
The Company believes that the Restructuring Act if properly applied
provides an opportunity for recovery of a reasonable amount of stranded costs.
If regulatory orders do not provide for a reasonable recovery, the Company is
prepared to vigorously pursue judicial remedies. Final determination and
quantification of stranded cost recovery has not been made by the PRC. The
determination will have an impact on the recoverability of the related assets
and may have a material effect on the future financial results and position of
the Company.
Transition Cost Recovery
In addition, the Restructuring Act authorizes utilities to recover in
full any prudent and reasonable costs incurred in implementing full open access
("transition costs"). These transition costs are currently scheduled to be
recovered through 2007 by means of a separate wires charge. The PRC may extend
this date by up to one year. The Company is still evaluating its expected
transition costs and has not made a final determination of those costs. The
Company, however, currently estimates that these costs will be approximately $46
million, including allowances for certain costs which are non-deductible for
income tax purposes. To date, the Company has capitalized $19.1 million of
expenditures that meet the Restructuring Act's definition of transition-related
costs. Transition costs for which the Company will seek recovery include
professional fees, financing costs, consents relating to the transfer of assets,
management information system changes including billing system changes and
58
public and customer education and communications. Recoverable transition costs
are currently being capitalized and will be amortized over the recovery period
to match related revenues. The Company intends to vigorously pursue remedies
available to it should the PRC disallow recovery of reasonable transition costs.
Costs not recoverable will be expensed when incurred unless these costs are
otherwise permitted to be capitalized under current and future accounting rules.
If the amount of non-recoverable transition costs is material, the resulting
charge to earnings may have a material effect on the future financial results
and position of the Company.
NRC Prefunding
Pursuant to NRC rules on financial assurance requirements for the
decommissioning of nuclear power plants, the Company has a program for funding
its share of decommissioning costs for PVNGS through a sinking fund mechanism
(see "PVNGS Decommissioning Funding"). The NRC rules on financial assurance
became effective on November 23, 1998. The amended rules provide that a licensee
may use an external sinking fund as the exclusive financial assurance mechanism
if the licensee recovers estimated decommissioning costs through cost of service
rates or a "non-bypassable charge". Other mechanisms are prescribed, such as
prepayment, surety methods, insurance and other guarantees, to the extent that
the requirements for exclusive reliance on the fund mechanism are not met.
The Restructuring Act allows for the recoverability of 50% up to 100% of
stranded costs including nuclear decommissioning costs (see "Stranded Costs").
The Restructuring Act specifically identifies nuclear decommissioning costs as
eligible for separate recovery over a longer period of time than other stranded
costs if the PRC determines a separate recovery mechanism to be in the public
interest. In addition, the Restructuring Act states that it is not requiring the
PRC to issue any order which would result in loss of eligibility to exclusively
use external sinking fund methods for decommissioning obligations pursuant to
Federal regulations. If the Company is unable to meet the requirements of the
NRC rules permitting the use of an external sinking fund because it is unable to
recover all of its estimated decommissioning costs through a non-bypassable
charge, the Company may have to pre-fund or find a similarly capital intensive
means to meet the NRC rules. There can be no assurance that such an event will
not negatively affect the funding of the Company's growth plans.
In addition, as part of the determination and quantification of the
stranded costs related to the decommissioning, the Company estimated its future
decommissioning costs. If the Company's estimate proves to be less than the
actual costs of decommissioning, any cost in excess of the amount allowed
through stranded cost recovery may not be recoverable. Such excess costs, if
any, will also be subject to the pre-funding requirements discussed above.
59
Competition
Under current law, the Company is not in direct retail competition with
any other regulated electric and gas utility. Nevertheless, the Company is
subject to varying degrees of competition in certain territories adjacent to or
within areas it serves that are also currently served by other utilities in its
region as well as cooperatives, municipalities, electric districts and similar
types of government organizations.
As a result of the Restructuring Act, the Company may face competition
from companies with greater financial and other resources. There can be no
assurance that the Company will not face competition in the future that would
adversely affect its results.
It is the current intention to have the Company's unregulated businesses
under the Restructuring Act engage primarily in energy-related businesses that
will not be regulated by state or Federal agencies that currently regulate
public utilities (other than the FERC and NRC). These competitive businesses,
including the generation business, will encounter competition and other factors
not previously experienced by the Company, and may have different, and perhaps
greater, investment risks than those involved in the regulated business that
will be engaged in by UtilityCo. Specifically, the passage of the Restructuring
Act and deregulation in the electric utility industry generally are likely to
have an impact on the price and margins for electric generation and thus, the
return on the investment in electric generation assets. In response to
competition and the need to gain economies of scale, electricity producers will
need to control costs to maintain margins, profitability and cash flow that will
be adequate to support investments in new technology and infrastructure. The
Company will have to compete directly with independent power producers, many of
whom will be larger in scale, thus creating a competitive advantage for those
producers due to scale efficiencies.
The New Mexico Legislature is currently considering legislation that
could delay open access and other activities under the Restructuring Act,
including corporate separation. A delay without providing business flexibility
could have a negative effect on the Company's ability to compete in the
wholesale power market. Under the current regulatory environment in New Mexico,
the Company is unable to achieve the necessary business flexibility it requires
to take advantage of business opportunities to execute its growth strategy.
There can be no assurance that the Company can successfully compete in the
wholesale power marketplace and continue to execute its growth strategy if
implementation of the Restructuring Act is rolled back. Senate Bill 266, as
originally introduced, simply delayed restructuring for five years. However,
during the course of committee hearings and floor debate, the bill was amended
so as to provide significant business flexibility to utilities despite the
delay. As amended, Senate Bill 266 passed the Senate 39-0 and is now pending in
the House of Representatives.
60
ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS
Under the terms of an agreement and plan of restructuring and merger, the
Company and Western Resources, whose utility operations consist of its Kansas
Power and Light division and Kansas Gas and Electric subsidiary, will both
become subsidiaries of a new holding company to be named at a future date. Prior
to and as a condition to, the consummation of this combination, Western
Resources will reorganize all of its non-utility assets, including its 85% stake
in Protection One and its 45% investment in ONEOK, into Westar Industries which
will be spun off to Western Resources' shareholders prior to the acquisition of
Western's utility assets by the Company.
The new holding company will issue 55 million of its shares, subject to
adjustment, to Western Resources' shareholders and Westar Industries and 39
million shares to the Company's shareholders. Before any adjustments, the new
company will have approximately 94 million shares outstanding, of which
approximately 41% will be owned by former Company shareholders and 59% will be
owned by former Western Resources shareholders and Westar Industries.
Based on the Company's average closing price over the last ten days prior
to the announcement of the transaction of $27.325 per share, the indicated
equity consideration of the transaction is approximately $1.5 billion. In
addition, approximately $2.9 billion of existing Western Resources debt will be
retained, giving the transaction an aggregate enterprise value of approximately
$4.4 billion. The new company will undertake to refinance and reduce the debt on
Western Resources' books. The new holding company will have a total enterprise
value of approximately $6.5 billion ($2.6 billion in equity; $3.9 billion in
debt and preferred stock).
The transaction will be accounted for as a reverse acquisition by the
Company as the former Western Resources shareholders will receive the majority
of the voting interests in the new holding company. For accounting purposes,
Western Resources will be treated as the acquiring entity. Accordingly, all of
the assets and liabilities of the Company will be recorded at fair value in the
business combination as required by the purchase method of accounting. In
addition, the operations of the Company will be reflected in the operations of
the combined company only from the date of acquisition.
In the transaction, each Company share will be exchanged on a one-for-one
basis for shares in the new holding company. The portion of each Western
Resources share not converted into Westar stock in connection with the spin-off
will be exchanged for a fraction of a share of the new holding company in
accordance with an exchange ratio to be finalized at closing, depending on the
impact of certain adjustments to the transaction consideration. Under the terms
of the agreement, Western Resources and Westar Industries have been given an
incentive to reduce Western Resources net debt balance prior to the consummation
of the transaction. The agreement contains a mechanism to adjust the transaction
consideration based on additional equity contributions. Under this mechanism,
Western Resources could undertake certain activities not affecting its utility
operations to reduce the net debt balance of the utility. The effect of such
activities would be to increase the number of new holding company shares to be
issued to all Western Resources shareholders (including Westar Industries) in
61
the transaction. In addition, Westar Industries has the option of making
additional equity infusions into Western Resources that will be used to reduce
the utility's net debt balance prior to closing. Up to $407 million of such
equity infusions may be used to purchase additional new holding company common
and convertible preferred stock.
At closing, Jeffrey E. Sterba, present chairman, president and chief
executive officer of the Company, will become chairman, president and chief
executive officer of the new holding company, and David C. Wittig, present
chairman, president and chief executive officer of Western Resources, will
become chairman, president and chief executive officer of Westar Industries. The
Board of Directors of the new company will consist of six current Company board
members and three additional directors, two of whom will be selected by the
Company from a pool of candidates nominated by Western Resources, and one of
whom will be nominated by Westar Industries. The new holding company will be
headquartered in New Mexico. Headquarters for the Kansas utilities will remain
in Kansas.
The Company expects that the shareholders of the new holding company will
receive the Company's dividend. The Company's current annual dividend is $0.80
per share. There can be no assurance however that any funds, property or shares
will be legally available to pay dividends at any given time or if available,
the new holding company's Board of Directors will declare a dividend.
The companies expect the transaction to be completed within the next 12
to 18 months. The successful spin-off of Westar Industries from Western
Resources is required prior to the consummation of the transaction. The
transaction is also conditioned upon, among other things, approvals from both
companies' shareholders and customary regulatory approvals from the Kansas
Corporation Commission, the New Mexico Public Regulation Commission, the Federal
Energy Regulatory Commission, the Nuclear Regulatory Commission, and the
Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of
1976. The new holding company expects to register as a holding company with the
Securities and Exchange Commission under the Public Utility Holding Company Act
of 1935. The Company expects that all of the above mentioned approvals will be
obtained; however, such approvals are not assured.
WESTERN UNITED STATES WHOLESALE POWER MARKET
A significant portion of the Company's earnings in 2000 was derived from
the Company's wholesale power trading operations which benefited from the strong
demand and high wholesale prices in the Western United States. These market
conditions were primarily driven by the electric power supply shortages in the
Western United States. As a result of the supply imbalance, the wholesale power
market in the Western United States has become extremely volatile and, while
providing many marketing opportunities, presents significant risk to companies
selling power into this marketplace.
During 2000, regional wholesale electricity prices reached over $1,000
per MWh mainly due to the electric power shortages in the West. Two of
California's major utilities, SCE and PG&E, were unable to pass this cost on to
their ratepayers. As a result, both utilities are experiencing severe liquidity
constraints and have each stated publicly that they may file for bankruptcy. In
62
response to the financial difficulties being experienced by SCE and PG&E and the
resulting turmoil in the California market, the U.S. Secretary of Energy imposed
a "soft" price cap of $150 per MWh effective January 1, 2001, and expiring
January 23, 2001. This price cap was subsequently extended to February 7, 2001.
The price cap requires that any wholesale sales of electricity into the
California market be capped at $150 MWh unless the seller can demonstrate that
its costs exceed the cap. In addition, the Governor and legislature of
California are considering a number of proposals which may put downward pressure
on the price of electricity including, but not limited to, a restructured power
auction system and the purchase of power by the state on a long-term basis. It
is unclear what effect these measures will have on the price of electricity in
California and the surrounding states. Such measures may have an impact on the
sustainability of the high electric power prices experienced in 2000.
The Company is not a major participant in the California market. In 2000,
approximately seven percent of all wholesale power sales by the Company were
made directly to the California Power Exchange ("California PX"), which was the
main market for the purchase and sale of electricity in the state during 2000
and the beginning of 2001, or the California Independent System Operator
("California ISO"), which manages the state's electricity transmission network.
At December 31, 2000, amounts due from the California PX or ISO for power sold
to them totaled $10.5 million. In January and February 2001, SCE and PG&E, major
purchasers of power from the California PX and ISO, defaulted on payments due
the California PX for power purchased from the PX in 2000. In addition, these
companies defaulted on various debt obligations in January and February 2001 due
third party creditors. The impact of these defaults on the Company was
immaterial.
However, under the terms of the participation agreement with the
California PX, defaults by the PX's debtors are charged-back proportionally to
the creditors based on their level of participation in the exchange in the three
months preceding the respective default. Through February 8, 2001, the PX has
had defaults of $865 million by SCE and PG&E for power purchased in November
2000. Additional defaults may occur. The Company has been invoiced for $2.3
million as its proportionate share under the participation agreement. A number
of power marketers and generators have filed a complaint with the FERC to halt
the PX's attempt to collect these payments under the charge-back mechanism,
claiming the mechanism was not intended for these purposes, and even if it was
so intended, such an application is unreasonable and destabilizing to the
California power market. If the FERC does not intercede, and the participating
creditors do not make payments, the PX may draw upon letters of credit and other
collateral on deposit with the exchange. The Company has issued the PX a letter
of credit of $3 million. The Company does not believe the charge-back is
appropriate and is evaluating its course of action; however, the Company does
not believe the situation will have a material adverse effect on its results of
operations or financial condition.
In addition to sales to the California PX and ISO, the Company sells
power to customers in other jurisdictions who sell to the California PX and ISO
and whose ability to pay may be dependent on payment from California. The
Company is unable to determine whether its non-California power sales ultimately
are resold in the California market. The Company's credit risk is monitored by
its Risk Management Committee, which is comprised of senior finance and
operations managers. The Company seeks to minimize its exposure through
established credit limits, a diversified customer base and the structuring of
transactions to take advantage of off-setting positions with its customers. To
the extent these customers who sell power into California are dependent on
payment from California to make their payments to the Company, the Company may
be exposed to credit risk which did not exist prior to the California situation.
63
In 2000, in response to the increased credit risk and market price
volatility described above, the Company recognized $8.5 million of losses to
reflect management's estimate of the increased risk in the wholesale power
market and its impact on 2000 revenues. This determination was based on a
methodology that considers the credit ratings of its customers and the price
volatility in the marketplace, among other things. The Company will continue to
monitor the wholesale power marketplace and adjust its estimates accordingly.
The California Public Utilities Commission ("CPUC") has commenced an
investigation into the functioning of the California wholesale power market and
its associated impact on retail rates. The Company, along with other power
suppliers in California, has been served with a subpoena in connection with this
investigation and has responded to the subpoena. The Company has not heard
further from the CPUC. The Company has been advised that the California Attorney
General is conducting an investigation into possibly unlawful, unfair or
anti-competitive behavior affecting electricity rates in California, and that
Company documents will be subpoenaed in the near future in connection with this
investigation. However, no such subpoena has yet been forthcoming.
In addition, there are several class action lawsuits that have been filed
in California against generators and wholesale sellers of energy into the
California market. These actions allege, in essence, that the defendants engaged
in unlawful and unfair business practices to manipulate the wholesale energy
market, fix prices and restrain supply, and thereby drive up prices. The Company
is not a named defendant in any of these actions, and there has been no claim or
threat of litigation against the Company arising out of the matters addressed in
these actions.
The Company does not believe that these matters will have a material
adverse effect on its results of operations or financial position.
As discussed above, SCE has defaulted on certain of its obligations and
has publicly announced that it may declare bankruptcy. SCE is a 15.8%
participant in PVNGS and a 48.0% participant in Four Corners. Pursuant to an
agreement among the participants in PVNGS and an agreement among the
participants in Four Corners Units 4 and 5, each participant is required to fund
its proportionate share of operation and maintenance, capital, and fuel costs of
PVNGS and Four Corners Units 4 and 5. The Company estimates SCE's total monthly
share of these costs to be approximately $7.1 million for PVNGS and $8.0 million
for Four Corners. The agreements provide 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 for a period of six
months. During this time the defaulting participant is entitled to its share of
the power generated by the respective station. After this grace period, the
defaulting participant must make its payments in arrears before it is entitled
to its continuing share of power. As of February 1, 2001, SCE has not defaulted
on its payment obligations with respect to PVNGS and Four Corners. The Company
is unable to predict whether the California situation will cause SCE to default
on its payment obligations.
64
Implementation of New Billing System
On November 30, 1998, the Company implemented a new customer billing
system. Due to a significant number of problems associated with the
implementation of the new billing system, the Company was unable to generate
appropriate bills for all its customers through the first quarter of 1999 and
was unable to analyze delinquent accounts until November 1999.
Under PRC rules and PRC approved Company rules, the Company is required
to issue customer bills on a monthly basis. The Company was granted a temporary
variance, and the PRC began a hearing on whether the Company violated PRC rules,
regulations or orders or the New Mexico Public Utility Act. The investigation
was concluded on November 2, 1999, without the PRC imposing any civil penalty on
the Company and with an approved stipulation that the Company be permitted to
bill an additional service charge to customers who were not billed the
appropriate electric service charge or gas access fee. The stipulation was
limited to approximately $0.7 million in the November and December billing
cycles.
Because of the implementation issues associated with the new billing
system, the Company estimated retail gas and electric revenues through July
1999. Beginning with August 1999, the Company was able to determine actual
revenues for all prior periods affected and began reconciling with previously
estimated revenues. In December 1999, the Company completed its reconciliation
of system revenues. As a result, 1999 revenues represented actual revenues as
determined by the new billing system. The resulting reconciliation did not
materially impact recorded revenues. However, a significant number of individual
accounts required corrections.
As a result of the delay of normal collection activities, the Company
incurred a significant increase in delinquent accounts, many of which occurred
with customers that no longer have active accounts with the Company. As a
result, the Company significantly increased its estimate of bad debt costs
throughout 1999.
The Company continued its analysis and collection efforts of its
delinquent accounts resulting from the problems associated with the
implementation of the new customer billing system throughout 2000 and identified
additional bad debt exposure. By the end of 2000, the Company completed its
analysis of its delinquent accounts and resumed its normal collection
procedures. As a result, the Company has determined that $13.5 million of
customer receivables will not be collectible. Based upon information available
at December 31, 2000, the Company believes the allowance for doubtful accounts
of $9.0 million is adequate for management's estimate of potential uncollectible
accounts.
In addition, due to the significantly higher natural gas prices
experienced in November and December 2000, the Company increased its bad debt
expense by approximately $2 million in anticipation of higher than normal
delinquency rates. The Company expects this trend to continue as long as natural
gas prices remain higher than in the past years.
65
The following is a summary of the allowance for doubtful accounts during
2000, 1999 and 1998:
2000 1999 1998
-------- -------- -------
(In thousands)
Allowance for doubtful accounts, beginning
of year....................................... $ 12,504 $ 836 $ 783
Bad debt expense................................ 9,980 11,496 3,325
Less: Write off (adjustments) of uncollectible
accounts................................. 13,521 (172) 3,272
-------- --------- -------
Allowance for doubtful accounts, end of year ... $ 8,963 $ 12,504 $ 836
======== ========= =======
Electric Rate Case
In November 1998, the NMPUC issued a final order in the Company's
electric rate case, requiring the Company to reduce rates in 1999 by $60.2
million, by $25.6 million in 2000 and by an additional $25.6 million in 2001.
The rate reduction order reflected, among other things, the revaluation of the
Company's generation resources based on a so-called "market-based price" and the
finding by the NMPUC that recovery of stranded costs is illegal. In December
1998, the Company appealed the rate case order to the New Mexico Supreme Court
("Supreme Court").
On March 15, 1999, the Supreme Court issued a ruling, vacating the NMPUC
order on the Company's electric rate case and remanding the case to the PRC, the
successor of the NMPUC, for further proceedings.
On August 25, 1999, the PRC issued an order approving a settlement. The
PRC ordered the Company to reduce its electric rates by $34.0 million
retroactive to July 30, 1999. In addition, the order includes a rate freeze
until retail electric competition is fully implemented in New Mexico or until
January 1, 2003 whichever is earlier. The settlement reduces electric
distribution operating revenues by approximately $39 million and $19 million in
2000 and 1999, respectively.
GAS RATE ORDERS
In April 2000, the Supreme Court ruled in favor of the Company in
overturning a $6.9 million rate reduction imposed on the Company's natural gas
utility by the state's former NMPUC in 1997 for its 1995 gas rate case. Although
the Supreme Court upheld certain portions of the gas rate case order by the PUC,
the Supreme Court vacated the rate order as "unreasonable and unlawful" because
certain disallowances ordered by the PUC unreasonably hindered the Company's
ability to earn a fair rate of return. The case was remanded to the PRC. In
addition in March 2000, the Supreme Court vacated the PUC's final order in the
Company's 1997 gas rate case and remanded it back to the PRC. The Supreme Court
specifically rejected portions of the final order requiring the Company to offer
residential customers a choice of utility access fees.
66
Rate Case Settlement
On October 24, 2000, the PRC issued a final order approving a stipulation
negotiated in the third quarter between the Company and the PRC staff which
resolved all issues raised by the two remanded rate cases. The final order adds
approximately $1.2 million to the Company's revenues in the final quarter of
2000, $4.7 million in 2001, and $3.9 million in 2002. The Company has reversed
certain reserves against costs recovered in the settlement that were recorded
against earnings at the time of the original regulatory orders, resulting in a
one-time pre-tax gain of $4.6 million. This amount will be collected from
customers in rates over the next 12 years.
NUCLEAR DECOMMISSIONING TRUST
In 1998, the Company and the trustee of the Company's master
decommissioning trust filed a civil complaint and an amended complaint,
respectively, against several companies and individuals for the
under-performance of a corporate owned life insurance program. The program was
used to fund a portion of the Company's nuclear decommissioning obligations for
its 10.2% interest in PVNGS.
The parties reached a settlement agreement under which the complaint and
counterclaim were dismissed with prejudice on September 5, 2000 and the Company
and trustee received $13.8 million in settlement proceeds.
Effects of Certain Events on Future Revenues
The Company's 100 MW power sale contract with San Diego Gas and Electric
Company ("SDG&E") will expire in April of 2001. SDG&E has verbally notified the
Company that it will not renew this contract. The FERC must ultimately approve
the termination of the contract. The Company currently estimates that the net
revenue reduction resulting from the expiration of the SDG&E contract will be
approximately $20 million annually. Whether or not these revenues will be
replaced depends on market conditions. In addition, previously reported
litigation between the Company and SDG&E regarding prior years' contract pricing
has been resolved in the Company's favor.
On October 4, 1999, Western Area Power Administration ("WAPA") filed a
petition at the FERC requesting the FERC, on an expedited basis, to order the
Company to provide network transmission service to Western under the Company's
Open Access Transmission Tariff on behalf of the United States Department of
Energy ("DOE") as contracting agent for KAFB. The Company is opposing the WAPA
petition and intends to litigate this matter vigorously. The net revenue
reduction to the Company if the DOE replaces the Company as the power supplier
to KAFB is estimated to be approximately $7.0 million annually. Whether or not
these revenues will be replaced depends on market conditions.
As part of the rate case settlement (discussed above), the Company agreed
that certain changes to the language of the retail tariff under which Kirtland
Air Force Base ("KAFB") currently takes service would be considered in a
separate proceeding before the PRC. Hearings on this issue have not yet been
scheduled. The PRC is considering briefs submitted by the parties addressing the
scope of the proceeding. KAFB has not renewed its electric service contract with
the Company that expired in December 1999 but continues to purchase retail
service from the Company. (See Item 3. - "Legal Proceedings - Other Proceedings
- - Kirtland Air Force Base ("KAFB") Contract").
67
COAL FUEL SUPPLY
In 1997, the Company was notified by SJCC, supplier of coal to SJGS, of
certain audit exceptions identified by the Federal Minerals Management Service
("MMS") for the period 1986 through 1997. These exceptions pertain to the
valuation of coal for purposes of calculating the Federal coal royalty. Primary
issues include whether coal processing and transportation costs should be
included in the base value of La Plata coal for royalty determination. The
Company was notified during the fourth quarter of 2000 that SJCC and the MMS
agreed to a settlement of all claims. The Company's share of the settlement
including a recalculation of current invoices was approximately $3 million. The
Company recorded the settlement as part of its cost of coal in the fourth
quarter of 2000.
In 1996, the Company was notified by SJCC that the Navajo Nation proposed
to select certain properties within the San Juan and La Plata Mines (the "mining
properties") pursuant to the Navajo-Hopi Land Settlement Act of 1974 (the
"Act"). The mining properties are operated by SJCC under leases from the BLM and
comprise a portion of the fuel supply for the SJGS. An administrative appeal by
SJCC is pending. In the appeal, SJCC argued that transfer of the mining
properties to the Navajo Nation may subject the mining operations to taxation
and additional regulation by the Navajo Nation, both of which could increase the
price of coal that might potentially be passed on to the SJGS through the
existing coal sales agreement. The Company is monitoring the appeal and other
developments on this issue and will continue to assess potential impacts to the
SJGS and the Company's operations. The Company is unable to predict the ultimate
outcome of this matter.
FUEL, WATER AND GAS NECESSARY FOR GENERATION OF ELECTRICITY
The Company's generation mix for 2000 was 68.0% coal, 39.8% nuclear and
2.2% gas and oil. Due to locally available natural gas and oil supplies, the
utilization of locally available coal deposits and the generally abundant supply
of nuclear fuel, the Company believes that adequate sources of fuel are
available for its generating stations (see "COAL FUEL SUPPLY" above).
Water for Four Corners and SJGS is obtained from the San Juan River. BHP
holds rights to San Juan River water and has committed a portion of those rights
to Four Corners through the life of the project. The Company and Tucson have a
contract with the USBR for consumption of 16,200 acre feet of water per year for
the SJGS. The contract expires in 2005. In addition, the Company was granted the
authority to consume 8,000 acre feet of water per year under a state permit that
is held by BHP. The Company is of the opinion that sufficient water is under
contract for the SJGS through 2005. The Company has signed a contract with the
Jicarilla Apache Tribe for a twenty-seven year term, beginning in 2006, for
replacement of the current USBR contract for 16,200 acre feet of water. The
contract must still be approved by the USBR and is also subject to environmental
approvals. The Company is actively involved in the San Juan River Recovery
Implementation Program to mitigate any concerns with the taking of the
negotiated water supply from a river that contains endangered species and
critical habitat. The Company believes that it will continue to have adequate
sources of water available for its generating stations.
68
The Company obtains its supply of natural gas primarily from sources
within New Mexico pursuant to contracts with producers and marketers. These
contracts are generally sufficient to meet the Company's peak-day demand. The
Company serves certain cities which depend on EPNG or Transwestern Pipeline
Company for transportation of gas supplies. Because these cities are not
directly connected to the Company's transmission facilities, gas transported by
these companies is the sole supply source for those cities. The Company believes
that adequate sources of gas are available for its distribution systems.
NEW SOURCE REVIEW RULES
The United States Environmental Protection Agency ("EPA") has proposed
changes to its New Source Review ("NSR") rules that could result in many actions
at power plants that have previously been considered routine repair and
maintenance activities (and hence not subject to the application of NSR
requirements) as now being subject to NSR. In November 1999, the Department of
Justice at the request of the EPA filed complaints against seven companies
alleging the companies over the past 25 years had made modifications to their
plants in violation of the NSR requirements, and in some cases the New Source
Performance Standards ("NSPS") regulations. Whether or not the EPA will prevail
is unclear at this time. The EPA has reached a settlement with one of the
companies sued by the Justice Department and is in the process of attempting to
negotiate settlement agreements with one of those other companies. No complaint
has been filed against the Company, and the Company believes that all of the
routine maintenance, repair, and replacement work undertaken at its power plants
was and continues to be in accordance with the requirements of NSR and NSPS.
However, by letter dated October 23, 2000, the New Mexico Environment Department
("NMED") made an information request of the Company, advising the Company that
the NMED was in the process of assisting the EPA in the EPA's nationwide effort
"of verifying that changes made at the country's utilities have not
inadvertently triggered a modification under the Clean Air Act's Prevention of
Significant Determination ("PSD") policies." The Company has responded to the
NMED information request.
The nature and cost of the impacts of EPA's changed interpretation of the
application of the NSR and NSPS, together with proposed changes to these
regulations, may be significant to the power production industry. However, the
Company cannot quantify these impacts with regard to its power plants. It is
also unknown what changes in EPA policy, if any, may occur in the NSR area as a
result of the change in administration in Washington. If the EPA should prevail
with its current interpretation of the NSR and NSPS rules, the Company may be
required to make significant capital expenditures which could have a material
adverse affect on the Company's financial position and results of operations.
COMPLIANCE WITH ENVIRONMENTAL LAWS AND REGULATIONS
The normal course of operations of the Company necessarily involves
activities and substances that expose the Company to potential liabilities under
laws and regulations protecting the environment. Liabilities under these laws
and regulations can be material and in some instances may be imposed without
regard to fault, or may be imposed for past acts, even though such past acts may
have been lawful at the time they occurred. Sources of potential environmental
liabilities include the Federal Comprehensive Environmental Response
Compensation and Liability Act of 1980 and other similar statutes.
69
The Company records its environmental liabilities when site assessments
or remedial actions are probable and a range of reasonably likely cleanup costs
can be estimated. The Company reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified
site using currently available information, including existing technology,
presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless
there is a probable amount, the Company records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities at undiscounted
amounts).
The Company's recorded estimated minimum liability to remediate its
identified sites is $8.3 million. The ultimate cost to clean up the Company's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature
of contamination; the scarcity of reliable data for identified sites; and the
time periods over which site remediation is expected to occur. The Company
believes that, due to these uncertainties, it is remotely possible that cleanup
costs could exceed its recorded liability by up to $21.1 million. The upper
limit of this range of costs was estimated using assumptions least favorable to
the Company.
Labor Union Negotiations
The collective bargaining agreement between the Company and the
International Brotherhood of Electrical Workers Local Union 611 ("IBEW"), which
covers the approximately 654 bargaining unit employees in the Utility and
Generation and Trading Operations expired on May 1, 2000, but continued in full
force and effect while the parties negotiated. The successor agreement was
reached on August 22, 2000 and was ratified by IBEW members on September 1,
2000. The IBEW's charge with the National Labor Relations Board ("NLRB")
alleging the Company has bargained in bad faith, and by its actions has
committed an unfair labor practice is pending. The Company will vigorously
defend against the Union's allegations.
NAVAJO NATION TAX ISSUES
APS, the operating agent for Four Corners, has informed the Company that
in March 1999, APS initiated discussions with the Navajo Nation regarding
various tax issues in conjunction with the expiration of a tax waiver, in July
2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to
the possessory interest tax and the business activity tax associated with the
Four Corners operations on the reservation. The Company believes that the
resolution of these tax issues will require an extended process and could
potentially affect the cost of conducting business activities on the
reservation. The Company is unable to predict the ultimate outcome of
discussions with the Navajo Nation regarding these tax issues.
70
NEW AND PROPOSED ACCOUNTING STANDARDS
Decommissioning: The Staff of the Securities and Exchange Commission
("SEC") has questioned certain of the current accounting practices of the
electric industry regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in financial statements of
electric utilities. In February 2000, the Financial Accounting Standards Board
("FASB") issued an exposure draft regarding Accounting for Obligations
Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The
Exposure Draft requires the recognition of a liability for an asset retirement
obligation at fair value. In addition, present value techniques used to
calculate the liability must use a credit adjusted risk-free rate. Subsequent
remeasures of the liability would be recognized using an allocation approach.
The Company has not yet determined the impact of the Exposure Draft.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities, ("SFAS 133"): SFAS 133
establishes accounting and reporting standards requiring derivative instruments
to be recorded in the balance sheet as either an asset or liability measured at
its fair value. SFAS 133 also requires that changes in the derivatives' fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows derivative
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. In June
1999, FASB issued SFAS 137 to amend the effective date for the compliance of
SFAS 133 to January 1, 2001. In June 2000, the FASB issued SFAS 138 that
provides certain amendments to SFAS 133. The amendments, among other things,
expand the normal sales and purchases exception to contracts that implicitly or
explicitly permit net settlement and contracts that have a market mechanism to
facilitate net settlement. The expanded exception excludes a significant portion
of the Company's contracts that previously would have required valuation under
SFAS 133. Effective January 1, 2001, the Company adopted SFAS 133, as amended.
The Company has identified all financial instruments that meet the
definition of a derivative under SFAS 133, as amended, as of January 1, 2001 in
which the Company is a party. Certain of the Company's identified derivative
instruments are marked-to-market under EITF 98-10 as of December 31, 2000. The
related gains and losses (unrealized and realized) for these derivative
instruments are recorded as adjustments to operating revenues. In addition, the
financial instruments underlying the Company's corporate hedge of certain
investments in its nuclear, executive retirement and retiree medical benefits
trusts meet the definition of a derivative under SFAS 133, as amended, and are
marked-to-market as of December 31, 2000. The related unrealized and realized
losses are recorded as a component of other income and deductions on the
Consolidated Statement of Earnings.
Pursuant to SFAS 133, as amended, the Company designated certain forward
purchase contracts for electricity as cash flow hedges. The Company's designated
cash flow hedges at January 1, 2001, were forward purchase contracts for the
purchase of electric power for forecasted jurisdictional use during planned
outages in 2001. The hedged risks associated with these instruments are the
changes in cash flows associated with the forecasted purchase of electricity due
to changes in the price of electricity on the spot market. Assessment of hedge
effectiveness will be based on the changes in the forward price of electricity.
71
SFAS 133, as amended, provides that the effective portion of the gain or
loss on a derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period or periods during which the hedged
forecasted transaction affects earnings. The results of hedge ineffectiveness
and the change in fair value of a derivative that an entity has chosen to
exclude from hedge effectiveness are required to be presented in current
earnings.
Because the Company's derivative instruments as defined by SFAS 133, as
amended, are currently marked-to-market or are classified as cash flow hedges,
the adoption of SFAS 133, as amended, will not have an impact on the net
earnings of the Company. However, the adoption of SFAS 133, as amended, will
increase comprehensive income by $6.0 million, net of taxes for the recording of
the Company's cash flow hedges. The physical contracts will subsequently be
recognized as a component of the cost of purchased power when the actual
physical delivery occurs. At January 1, 2001, the derivative instruments
designated as cash flow hedges had a gross asset position of $9.9 million on the
hedged transactions. See Note 5 for financial instruments currently
marked-to-market.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
Statements made in this filing that relate to future events are made
pursuant to the Private Securities Litigation Reform Act of 1995. Readers are
cautioned that such forward-looking statements with respect to revenues,
earnings, performance, strategies, prospects and other aspects of the business
of the Company are based upon current expectations and are subject to risk and
uncertainties, as are the forward-looking statements with respect to the
benefits of the Company's proposed acquisition of Western Resources and the
businesses of the Company and Western Resources. The Company assumes no
obligation to update this information.
Because actual results may differ materially from expectations, the
Company cautions readers not to place undue reliance on these statements. A
number of factors, including weather, fuel costs, changes in supply and demand
in the market for electric power, the performance of generating units and the
transmission system, and state and federal regulatory and legislative decisions
and actions, including rulings issued by the NMPRC pursuant to the Electric
Utility Industry Restructuring Act of 1999 and in other cases now pending or
which may be brought before the commission and any action by the New Mexico
Legislature to amend or repeal that Act, or other actions relating to
restructuring or stranded cost recovery, or federal or state regulatory,
legislative or legal action connected with the California wholesale power
market, could cause the Company's results or outcomes to differ materially from
those indicated by such forward-looking statements in this filing.
In addition, factors that could cause actual results or outcomes related
to the proposed acquisition of Western Resources to differ materially from those
indicated by such forward looking statements include, but are not limited to,
risks and uncertainties relating to: the possibility that shareholders of the
Company and/or Western Resources will not approve the transaction, the risks
that the businesses will not be integrated successfully, the risk that the
benefits of the transaction may not be fully realized or may take longer to
realize than expected, disruption from the
72
transaction making it more difficult to maintain relationships with clients,
employees, suppliers or other third parties, conditions in the financial markets
relevant to the proposed transaction, the receipt of regulatory and other
approvals of the transaction, that future circumstances could cause business
decisions or accounting treatment to be decided differently than now intended,
changes in laws or regulations, changing governmental policies and regulatory
actions with respect to allowed rates of return on equity and equity ratio
limits, industry and rate structure, stranded cost recovery, operation of
nuclear power facilities, acquisition, disposal, depreciation and amortization
of assets and facilities, operation and construction of plant facilities,
recovery of fuel and purchased power costs, decommissioning costs, present or
prospective wholesale and retail competition (including retail wheeling and
transmission costs), political and economic risks, changes in and compliance
with environmental and safety laws and policies, weather conditions (including
natural disasters such as tornadoes), population growth rates and demographic
patterns, competition for retail and wholesale customers, availability, pricing
and transportation of fuel and other energy commodities, market demand for
energy from plants or facilities, changes in tax rates or policies or in rates
of inflation or in accounting standards, unanticipated delays or changes in
costs for capital projects, unanticipated changes in operating expenses and
capital expenditures, capital market conditions, competition for new energy
development opportunities and legal and administrative proceedings (whether
civil, such as environmental, or criminal) and settlements, the outcome of
Protection One accounting issues reviewed by the SEC staff as disclosed in
previous Western Resources SEC filings, and the impact of Protection One's
financial condition on Western Resources' consolidated results.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices and also adverse market
changes for investments held by the Company's various trusts. The Company also
uses certain derivative instruments for bulk power electricity trading purposes
in order to take advantage of favorable price movements and market timing
activities in the wholesale power markets. Information about market risk is set
forth in Note 5 to the Notes to the Consolidated Financial Statements and
incorporated by reference. The following additional information is provided.
The Company uses value at risk ("VAR") to quantify the potential exposure
to market movement on its open contracts and excess generating assets. The VAR
is calculated utilizing the variance/co-variance methodology over a three day
period within a 99% confidence level. The Company's VAR as of December 31, 2000
from its electric trading contracts was $36.9 million. In 2000, the Company
changed its methodology for calculating its VAR. Previously, bulk power
available for sale from the Company's excess capacity and assets excluded from
jurisdictional rates was measured using projected hourly load forecasts. These
assets are now measured using average peak load forecasts for the respective
block of power in the forward market. The change in methodology results in less
available MW's for sale in the VAR calculation. Management believes this more
accurately portrays its capacity from its excess generating assets.
The Company's wholesale power marketing operations, including both firm
commitments and trading activities, are managed through an asset backed
strategy, whereby the Company's aggregate net open position is covered by its
own excess generation capabilities. The Company is exposed to market risk if its
generation capabilities were disrupted or if its jurisdictional load
requirements were greater than anticipated. If the Company were required to
cover all or a portion of its net open contract position, it would have to meet
its commitments through market purchases. The Company's VAR calculation
considers this exposure.
73
The Company's VAR is regularly monitored by the Company's Risk Management
Committee which is comprised of senior finance and operations managers. The Risk
Management Committee has put in place procedures to ensure that increases in VAR
are reviewed and, if deemed necessary, acted upon to reduce exposures. In
addition, the Company is exposed to credit losses in the event of
non-performance or non-payment by counterparties. The Company uses a credit
management process to access and monitor the financial conditions of
counterparties. Credit exposure is also regularly monitored by the Company's
Risk Management committee.
The VAR represents an estimate of the potential gains or losses that
could be recognized on the Company's wholesale power marketing portfolio given
current volatility in the market, and is not necessarily indicative of actual
results that may occur, since actual future gains and losses will differ from
those estimated. Actual gains and losses may differ due to actual fluctuations
in market rates, operating exposures, and the timing thereof, as well as changes
to the Company's wholesale power marketing portfolio during the year.
74
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Page
----
Management's Responsibility for Financial Statements .................. F-1
Report of Independent Public Accountants .............................. F-2
Financial Statements:
Consolidated Statements of Earnings ................................ F-3
Consolidated Balance Sheets ........................................ F-4
Consolidated Statements of Cash Flows .............................. F-6
Consolidated Statements of Capitalization .......................... F-7
Notes to Consolidated Financial Statements ......................... F-8
Supplementary Data:
Quarterly Operating Results ........................................ F-45
Comparative Operating Statistics ................................... F-46
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The accompanying financial statements, which consolidate the accounts of Public
Service Company of New Mexico and its subsidiaries, have been prepared in
conformity with accounting principles generally accepted in the United States.
The integrity and objectivity of data in these financial statements and
accompanying notes, including estimates and judgments related to matters not
concluded by year-end, are the responsibility of management as is all other
information in this Annual Report. Management devotes ongoing attention to
review and appraisal of its system of internal controls. This system is designed
to provide reasonable assurance, at an appropriate cost, that the Company's
assets are protected, that transactions and events are recorded properly and
that financial reports are reliable. The system is augmented by a staff of
corporate auditors; careful attention to selection and development of qualified
financial personnel; and programs to further timely communication and monitoring
of policies, standards and delegated authorities.
The Audit Committee of the Board of Directors, composed entirely of outside
directors, meets regularly with financial management, the corporate auditors and
the independent auditors to review the work of each. The independent auditors
and corporate auditors have free access to the Audit Committee, without
management representatives present, to discuss the results of their audits and
their comments on the adequacy of internal controls and the quality of financial
reporting.
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Public Service Company of New Mexico:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Public Service Company of New Mexico (a New Mexico
Corporation) and subsidiaries as of December 31, 2000 and 1999, and the related
consolidated statements of earnings, and cash flows for each of the three years
in the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Public Service Company of New
Mexico and subsidiaries as of December 31, 2000 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
January 26, 2001
F-2
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
Year Ended December 31,
-------------------------------------------
2000 1999 1998
------------ ------------- -------------
(In thousands, except per share amounts)
Operating Revenues: (note 1, 7)
Utility.................................................... $ 859,389 $ 778,286 $ 812,250
Generation and Trading..................................... 1,075,178 689,981 642,358
Unregulated businesses..................................... 2,158 8,855 1,266
Intersegment elimination................................... (325,451) (319,579) (363,429)
------------ ------------- -----------
Total operating revenues................................ 1,611,274 1,157,543 1,092,445
------------ ------------- -----------
Operating Expenses:
Cost of energy sold........................................ 949,880 531,952 449,426
Administrative and general................................. 147,268 153,709 135,727
Energy production costs.................................... 139,894 140,784 149,747
Depreciation and amortization.............................. 93,059 92,661 86,141
Transmission and distribution costs........................ 60,330 59,264 56,457
Taxes, other than income taxes............................. 34,405 34,084 37,992
Income taxes (note 7)...................................... 53,964 25,010 41,306
------------ ------------- -----------
Total operating expenses................................ 1,478,800 1,037,464 956,796
------------ ------------- -----------
Operating income........................................ 132,474 120,079 135,649
------------ ------------- -----------
Other Income and Deductions:
Other...................................................... 54,296 47,500 37,672
Income tax expense (note 7)............................... (20,382) (17,298) (14,985)
------------ ------------- -----------
Net other income and deductions......................... 33,914 30,202 22,687
------------ ------------- -----------
Income before interest charges.......................... 166,388 150,281 158,336
------------ ------------- -----------
Interest Charges:
Interest on long-term debt (note 3)........................ 62,823 65,899 50,929
Other interest charges..................................... 2,619 4,768 12,288
------------ ------------- -----------
Net interest charges.................................... 65,442 70,667 63,217
------------ ------------- -----------
Net Earnings from Continuing Operations...................... 100,946 79,614 95,119
Discontinued Operations, Net of Tax (note 13)................ - - (12,437)
Cumulative Effect of a Change in Accounting..................
Principle, Net of Tax .................................... - 3,541 -
------------ ------------- -----------
Net Earnings................................................. 100,946 83,155 82,682
Preferred Stock Dividend Requirements........................ 586 586 586
------------ ------------- ------------
Net Earnings Applicable to Common Stock...................... $ 100,360 $ 82,569 $ 82,096
============ ============= ============
Net Earnings per Share of Common Stock (Basic) (note 6)...... $ 2.54 $ 2.01 $ 1.97
============ ============= ============
Net Earnings per Share of Common Stock (Diluted) (note 6).... $ 2.53 $ 2.01 $ 1.95
============ ============= ============
Dividends Paid per Share of Common Stock..................... $ 0.80 $ 0.80 $ 0.77
============ ============= ============
The accompanying notes are an integral part of these financial statements.
F-3
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
As of December 31,
-------------------------------
2000 1999
-------------- ---------------
(In thousands)
Utility Plant, at original cost except PVNGS: (notes 10, 11)
Electric plant in service.............................................................. $2,030,813 $1,976,009
Gas plant in service................................................................... 553,755 483,819
Common plant in service and plant held for future use.................................. 36,678 69,273
-------------- ---------------
2,621,246 2,529,101
Less accumulated depreciation and amortization......................................... 1,153,377 1,077,576
-------------- ---------------
1,467,869 1,451,525
Construction work in progress.......................................................... 123,653 104,934
Nuclear fuel, net of accumulated amortization of $19,081 and $20,832................... 25,784 25,923
-------------- ---------------
Net utility plant................................................................... 1,617,306 1,582,382
-------------- ---------------
Other Property and Investments:
Other investments (notes 5, 12)........................................................ 479,821 483,008
Non-utility property, net of accumulated depreciation of $1,644 and $1,261............. 3,666 4,439
-------------- ---------------
Total other property and investments................................................ 483,487 487,447
-------------- ---------------
Current Assets:
Cash and cash equivalents.............................................................. 107,691 120,399
Accounts receivables, net of allowance for uncollectible accounts of $8,963 and $12,504 242,742 147,746
Other receivables...................................................................... 64,857 68,911
Inventories............................................................................ 36,091 39,992
Regulatory assets (note 2)............................................................. 47,604 24,056
Other current assets................................................................... 11,417 4,934
-------------- ---------------
Total current assets................................................................ 510,402 406,038
-------------- ---------------
Deferred charges:
Regulatory assets (note 2)............................................................. 226,849 195,898
Prepaid pension cost (note 8).......................................................... 18,116 16,126
Other deferred charges................................................................. 38,073 35,377
-------------- ---------------
Total deferred charges.............................................................. 283,038 247,401
-------------- ---------------
$2,894,233 $2,723,268
============== ===============
The accompanying notes are an integral part of these financial statements.
F-4
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILIITES
As of December 31,
---------------------------------
2000 1999
---------------- ---------------
(In thousands)
Capitalization: (note 3)
Common stock equity:
Common stock outstanding--39,118 and 40,703 shares...................... $ 195,589 $ 203,517
Additional paid-in capital.............................................. 432,222 453,393
Accumulated other comprehensive income, net of tax (note 3)............. (27) 2,352
Retained earnings....................................................... 296,843 227,829
---------------- ---------------
Total common stock equity.............................................. 924,627 887,091
Minority interest......................................................... 12,211 12,771
Cumulative preferred stock without mandatory redemption requirements...... 12,800 12,800
Long-term debt, less current maturities (note 3).......................... 953,823 988,489
---------------- ---------------
Total capitalization................................................... 1,903,461 1,901,151
---------------- ---------------
Current Liabilities:
Accounts payable.......................................................... 257,991 150,645
Accrued interest and taxes................................................ 36,889 34,237
Other current liabilities................................................. 67,758 54,137
---------------- ---------------
Total current liabilities.............................................. 362,638 239,019
---------------- ---------------
Deferred Credits:
Accumulated deferred income taxes (note 7)................................ 166,249 153,179
Accumulated deferred investment tax credits (note 7)...................... 47,853 50,996
Regulatory liabilities (note 2)........................................... 65,552 88,497
Regulatory liabilities related to accumulated deferred income tax (note 2) 20,696 15,091
Accrued postretirement benefits cost (note 8)............................. 11,899 8,945
Other deferred credits (note 12).......................................... 315,885 266,390
---------------- ---------------
Total deferred credits................................................. 628,134 583,098
---------------- ---------------
Commitments and Contingencies (note 11)..................................... - -
---------------- ---------------
$ 2,894,233 $ 2,723,268
================ ===============
The accompanying notes are an integral part of these financial statements.
F-5
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
----------------------------------------------
2000 1999 1998
-------------- -------------- --------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings......................................................... $100,946 $ 83,155 $ 82,682
Adjustments to reconcile net earnings to net cash flows..............
from operating activities:
Depreciation and amortization.................................... 103,829 103,891 98,154
Gain on cumulative effect of a change in
Accounting principle ......................................... - (5,862) -
Other,........................................................... 33,268 26,170 27,462
Changes in certain assets and liabilities:
Accounts receivables........................................... (94,996) (16,937) 1,302
Other assets................................................... (32,444) (20,189) 31,066
Accounts payable............................................... 107,346 36,670 (40,490)
Other liabilities.............................................. 21,566 6,147 10,812
-------------- -------------- --------------
Net cash flows provided from operating activities........ 239,515 213,045 210,988
-------------- -------------- --------------
Cash Flows From Investing Activities:
Utility plant additions.............................................. (146,878) (95,298) (128,784)
Return (purchase) of PVNGS lease obligation bonds.................... 16,668 16,903 (204,364)
Merger acquisition costs............................................. (6,700) - -
Other investing...................................................... (20,590) 22,509 (7,844)
-------------- -------------- --------------
Net cash flows used in investing activities.............. (157,500) (55,886) (340,992)
-------------- -------------- --------------
Cash Flows From Financing Activities:
Borrowings (note 3).................................................. - 11,500 896,348
Repayments (note 3).................................................. (32,800) (58,200) (694,651)
Exercise of employee stock options (note 9).......................... (1,232) 1,453 (3,687)
Common stock repurchase (note 3)..................................... (27,867) (18,799) -
Dividends paid....................................................... (32,265) (33,359) (32,789)
Other Financing...................................................... (559) (635) 7,868
-------------- -------------- --------------
Net cash flows (used) generated by financing activities.. (94,723) (98,040) 173,089
-------------- -------------- --------------
Increase (Decrease) in Cash and Cash Equivalents....................... (12,708) 59,119 43,085
Beginning of Year...................................................... 120,399 61,280 18,195
-------------- -------------- --------------
End of Year............................................................ $ 107,691 $ 120,399 $ 61,280
============== ============== ==============
Supplemental cash flow disclosures:
Interest paid........................................................ $ 64,045 $ 67,770 $ 50,109
============== ============== ==============
Income taxes paid, net of refunds.................................... $ 50,480 $ 36,575 $ 49,048
============== ============== ==============
Acquired DOE pipeline in exchange for transportation services........ - $ 3,100 -
============== ============== ==============
The accompanying notes are an integral part of these financial statements.
F-6
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,
-------------------------------
2000 1999
--------------- --------------
(In thousands)
Common Stock Equity: (note 3)
Common Stock, par value $5 per share.................................. $ 195,589 $ 203,517
Additional paid-in capital............................................ 432,222 453,393
Accumulated other comprehensive income, net of tax (27) 2,352
Retained earnings..................................................... 296,843 227,829
--------------- --------------
Total common stock equity......................................... 924,627 887,091
--------------- --------------
Minority Interest......................................................... 12,211 12,771
--------------- --------------
Cumulative Preferred Stock: (note 3)
Without mandatory redemption requirements:
1965 Series, 4.58% with a stated value of $100.00 and a
current redemption price of $102.00. Outstanding shares
at December 31, 2000 were 128,000................................ 12,800 12,800
--------------- --------------
Long-Term Debt: (note 3)
Issue and Final Maturity
First Mortgage Bonds, Pollution Control Revenue Bonds:
5.7% due 2016................................................. 65,000 65,000
6.375% due 2022................................................. 46,000 46,000
--------------- --------------
Total First Mortgage Bonds 111,000 111,000
--------------- --------------
Senior Unsecured Notes, Pollution Control Revenue Bonds:
6.30% due 2016................................................. 77,045 77,045
5.75% due 2022................................................. 37,300 37,300
5.80% due 2022................................................. 100,000 100,000
6.375% due 2022................................................. 90,000 90,000
6.375% due 2023................................................. 36,000 36,000
6.40% due 2023................................................. 100,000 100,000
6.30% due 2026................................................. 23,000 23,000
6.60% due 2029................................................. 11,500 11,500
--------------- --------------
Total Senior Unsecured Notes, Pollution Control Revenue Bonds.... 474,845 474,845
--------------- --------------
Senior Unsecured Notes:
7.10% due 2005................................................ 268,420 268,420
7.50% due 2018................................................ 100,025 135,000
Other, including unamortized premium and (discounted), net........... (467) (776)
--------------- --------------
Total long-term debt......................................... 953,823 988,489
--------------- --------------
Total Capitalization...................................................... $ 1,903,461 $ 1,901,151
=============== ==============
The accompanying notes are an integral part of these financial statements.
F-7
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000, 1999 and 1998
Summary of Significant Accounting Policies
Accounting Principles
The Company prepares its financial statements in accordance with the
uniform system of accounts prescribed by the Federal Energy Regulatory
Commission ("FERC") and the National Association of Regulatory Utility
Commissioners, and adopted by the New Mexico Public Regulation Commission
("PRC"), the successor of the New Mexico Public Utility Commission ("NMPUC"),
effective January 1, 1999.
The Company's accounting policies conform to the provisions of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation ("SFAS 71"). SFAS 71 requires a rate-regulated entity to
reflect the effects of regulatory decisions in its financial statements. In
accordance with SFAS 71, the Company has deferred certain costs and recorded
certain liabilities pursuant to the rate actions of the PRC, NMPUC and FERC.
These "regulatory assets" and "regulatory liabilities" are enumerated and
discussed in Note 2.
To the extent that the Company concludes that the recovery of a
regulatory asset is no longer probable due to regulatory treatment, the effects
of competition or other factors, the amount would be recorded as a charge to
earnings as recovery is no longer probable. The Company has discontinued the
application of SFAS 71 as of December 31, 1999, for the generation portion of
its business effective with the passage of the Electric Utility Industry
Restructuring Act of 1999 ("Restructuring Act") in accordance with Financial
Accounting Standards No. 101, "Accounting for the Discontinuation of Application
of FASB Statement No. 71". The Company evaluates its regulatory assets under
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("FAS 121"). In
2000, the Company determined certain stranded assets would not be recovered and
recorded a charge to earnings for these amounts. The Company believes that it
will recover costs associated with its remaining stranded assets including asset
closure costs through a non-bypassable charge as permitted by the Restructuring
Act. See Note 2 for additional discussion.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and subsidiaries in which it owns a majority voting interest. All significant
intercompany transactions and balances have been eliminated.
Financial Statement Preparation and Presentation
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual recorded amounts could differ from those
estimated.
F-8
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
Summary of Significant Accounting Policies (Continued)
Utility Plant
Utility plant, with the exception of Palo Verde Nuclear Generating
Station ("PVNGS") Unit 3 and the Company's owned interests in PVNGS Units 1 and
2, is stated at original cost, which includes capitalized payroll-related costs
such as taxes, pension and other fringe benefits, administrative costs and an
allowance for funds used during construction. Pursuant to a rate stipulation
dated October 1993, the Company did not capitalize amounts relating to an
allowance for funds used during construction in 2000, 1999 or 1998. Utility
plant includes certain electric assets not subject to regulation.
It is Company policy to charge repairs and minor replacements of
property to maintenance expense and to charge major replacements to utility
plant. Gains or losses resulting from retirements or other dispositions of
operating property in the normal course of business are credited or charged to
the accumulated provision for depreciation.
Revenue Recognition
The Company's Utility Operations record electric and gas operating
revenues in the period of delivery, which includes estimated amounts for service
rendered but unbilled at the end of each accounting period. Utility Operations
gas operating revenues exclude an adjustment for gas purchase costs that are
above levels included in base rates but are recoverable under the Purchased Gas
Adjustment Clause ("PGAC") administered by the PRC. The Company recognizes this
adjustment when it is permitted to bill under PRC guidelines.
The Company's Generation and Trading Operations record operating
revenues to the Utility Operations and to third parties in the period of
delivery. Certain sales to firm requirements wholesale customers include a cost
of energy adjustment for recoverable fixed costs. The Company recognizes this
adjustment when it is permitted to bill under FERC guidelines. Generation and
Trading Operations transactions that are net settled, whereby the unplanned
netting of delivery and acceptance of electric power for convenience of
transmission and settlement occurs (referred to as a "bookout"), are recorded
gross in operating revenues and fuel and purchased power expense.
Financial instruments utilized in connection with energy trading
activities are accounted for at fair market value under EITF 98-10. Unrealized
gains and losses resulting from the impact of price movements on the Company's
contracts are recognized as adjustments to Generation and Trading Operations
operating revenues. The market prices used to value these transactions reflect
management's best estimate considering various factors including closing
exchange and over-the counter quotations, time value and volatility factors
underlying the commitments.
The cash flow impact of these financial instruments is reflected as cash
flows from operating activities in the Consolidated Statement of Cash Flows.
F-9
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
Summary of Significant Accounting Policies (Continued)
Recoverable Fuel Costs
The Company's fuel and purchased power costs for its firm requirements
wholesale customers that are above the levels included in base rates are
recoverable under a fuel and purchased power cost adjustment approved by the
FERC. Such costs are deferred until the period in which they are
billed or credited to customers. The Company's gas purchase costs that are above
levels included in base rates are recoverable under similar Purchased Gas
Adjustment Clause administered by the PRC.
Depreciation and Amortization
Provision for depreciation and amortization of utility plant is made at
annual straight-line rates approved by the PRC. The average rates used are as
follows:
2000 1999 1998
------ ------ ------
Electric plant ...................... 3.42% 3.38% 3.32%
Gas plant ........................... 3.28% 3.37% 3.06%
Common plant ........................ 6.75% 7.73% 7.34%
The provision for depreciation of certain equipment is charged to
clearing accounts and subsequently allocated to operating expenses or
construction projects based on the use of the equipment. Depreciation of
non-utility property is computed on the straight-line method. Amortization of
nuclear fuel is computed based on the units of production method.
Nuclear Decommissioning
The Company accounts for nuclear decommissioning costs on a
straight-line basis over the respective license period. Such amounts are based
on the future value of expenditures estimated to be required to decommission the
plant.
For gas, the excess or deficiency is accumulated for refund or surcharge to
customers on an annual basis. Future recovery of these costs is subject to
approval by the PRC.
Amortization of Debt Acquisition Costs
Discount, premium and expense related to the issuance of long-term debt
are amortized over the lives of the respective issues. In connection with the
retirement of long-term debt, such amounts associated with resources subject to
PRC regulation are amortized over the lives of the respective issues. Amounts
associated with the Company's firm-requirements wholesale customers and its
resources excluded from PRC retail rates are recognized immediately as expense
or income as they are incurred.
F-10
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
Summary of Significant Accounting Policies (Continued)
Stock Options
The Company continues to apply Accounting Principles Board ("APB")
Opinion No. 25, Accounting for Stock Issued to Employees, and related
interpretations in accounting for its plan. Accordingly, no compensation cost
has been recognized for this plan.
Income Taxes
The Company reports income tax expense in accordance with SFAS 109,
Accounting for Income Taxes. SFAS 109 requires that deferred income taxes for
temporary differences between financial and income tax reporting be recorded
using the liability method. Therefore, deferred income taxes are computed using
the statutory tax rates scheduled to be in effect when temporary differences
reverse. Current PRC jurisdictional rates include the tax effects of the
majority of these temporary differences (normalization). Recovery of reversing
temporary differences previously accounted for under the flow-through method is
also included in rates charged to customers. For regulated operations, any
changes in tax rates applied to accumulated deferred income taxes may not be
immediately recognized because of ratemaking and tax accounting provisions
required by the Internal Revenue Code. Items accorded flow-through treatment
under PRC orders, deferred income taxes and the future ratemaking effects of
such taxes, as well as corresponding regulatory assets and liabilities, are
recorded in the financial statements.
Asset Impairment
The Company regularly evaluates the carrying value of its regulatory and
tangible long-lived assets in relation to their future undiscounted cash flows
to assess recoverability in accordance with SFAS 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
Impairment testing of power generation assets is performed periodically in
response to changes in market conditions resulting from industry deregulation.
Power generation assets used to supply jurisdictional and wholesale markets are
evaluated on a group basis using future undiscounted cash flows based on current
open market price conditions. The Company also has generation assets that are
used for the sole purpose of reliability. These assets are tested as an
individual group. Power generation assets held under operating leases are not
currently evaluated for impairment (see note 4).
Financial Instruments
The Company enters into energy trading contracts to take advantage of
market opportunities associated with the purchase and sale of electricity. Such
contracts are marked-to-market each period end. In addition, the Company
protected its decommissioning and retiree trust assets against market price
volatility by purchasing financial put and call options. These instruments are
also marked-to-market each period end. The Company also periodically hedges
natural gas purchases to limit commodity price volatility. Unrealized gains and
losses from natural gas-related swaps, futures and forward contracts are
deferred and recognized as the natural gas is sold and is recovered through gas
rates charged to customers (see Note 5).
F-11
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
Summary of Significant Accounting Policies (Continued)
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities
In December 1998, the Emerging Issues Task Force ("EITF") of the FASB
reached consensus on EITF Issue No. 98-10 which requires that energy trading
contracts should be marked-to-market (measured at fair value determined as of
the balance sheet date) with the gains and losses included in earnings.
Effective January 1, 1999, the Company adopted EITF Issue No. 98-10. The effect
of the initial application of the new standard is reported as a cumulative
effect of a change in accounting principle. (See Note 5)
Change in Presentation
Certain prior year amounts have been reclassified to conform to the 2000
financial statement presentation.
(1) Nature of Business and Segment Information
The Company is an investor-owned integrated utility engaged in the
generation, transmission, distribution and sale and trading of electricity, and
the transportation, distribution and sale of natural gas. In addition, the
Company provides energy and utility related services under its wholly-owned
subsidiary, Avistar, Inc. ("Avistar").
Under current law, the Company is not in any direct retail competition
with any other regulated electric and gas utility. The Restructuring Act in New
Mexico, which was enacted into law on April 8, 1999, opens the state's electric
power market to customer choice for certain customers beginning 2002 with the
balance of customers obtaining open access mid 2002. The Restructuring Act
requires that assets and activities subject to the PRC jurisdiction, primarily
electric and gas distribution, and transmission assets and activities
(collectively, the "regulated business"), be separated from other competitive
business, primarily electric generation and service and certain other energy
services operations (collectively, "the unregulated businesses"). Such
separation is required to be accomplished through the creation of at least two
separate corporations. The Company has decided to accomplish the mandated
separation by the formation of a holding company and the transfer of the
regulated businesses to a newly-created, wholly owned subsidiary of such holding
company, subject to various regulatory and other approvals. Under existing
deadlines, corporate separation of the regulated business from the competitive
businesses must be completed by August 1, 2001. However, the New Mexico
Legislature is currently considering various legislative actions that could
delay open access and activities under the Restructuring Act, including
corporate separation.
As it currently operates, the Company's principal business segments are
utility operations, which include the Electric Product Offering ("Electric") and
the natural Gas Product Offering ("Gas"), and Generation and Trading Operations
("Generation"). The Electric Product Offering consists of two major business
lines that include distribution and transmission. The transmission business line
does not meet the definition of a segment due to its immateriality and is
combined with the distribution business line for disclosure purposes.
F-12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(1) Nature of Business and Segment Information (Continued)
Electric procures all of its electric power needs from the Company's
Generation and Trading Operations. These intersegment sales are priced using
internally developed transfer pricing, and are not based on market rates.
Customer electric rates are regulated by the PRC and determined on a basis that
includes the recovery of the cost of power production by the Company's
Generation and Trading Operations and a return on the related assets, among
other things.
UTILITY OPERATIONS
Electric
The Company provides jurisdictional retail electric service to a large
area of north central New Mexico, including the cities of Albuquerque and Santa
Fe, and certain other areas of New Mexico. Approximately 369,000, 361,000 and
358,000 retail electric customers were served by the Company at December 31,
2000, 1999 and 1998, respectively. The Company owns or leases 2,781 circuit
miles of transmission lines, interconnected with other utilities east into
Texas, west into Arizona, and north into Colorado and Utah.
Gas
The Company's gas operations distributes natural gas to most of the major
communities in New Mexico, including Albuquerque and Santa Fe, serving
approximately 435,000, 426,000 and 419,000 customers as of December 31, 2000,
1999 and 1998. The Company's customer base includes both sales-service customers
and transportation-service customers.
The Company obtains its supply of natural gas primarily from sources
within New Mexico pursuant to contracts with producers and marketers.
GENERATION AND TRADING OPERATIONS
The Company's generation and trading operations serve four principal
markets. These include sales to the Company's Utility Operations to cover
jurisdictional electric demand, sales to firm-requirements wholesale customers,
other contracted sales to third parties for a specified amount of capacity
(measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a
given period of time and energy sales made on an hourly basis at fluctuating,
spot-market rates. As of December 31, 2000, the total net generation capacity of
facilities owned or leased by the Company was 1,653 MW, including a 132 MW power
purchase contract accounted for as an operating lease. In addition to generation
capacity, the Company purchases power in the open market.
UNREGULATED
The Company's wholly-owned subsidiary, Avistar, was formed in August 1999
as a New Mexico corporation and is currently engaged in certain unregulated,
non-utility businesses, including energy and utility-related services previously
operated by the Company. Unregulated also includes certain corporate activities,
which are not material.
F-13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(1) Nature of Business and Segment Information (Continued)
RISKS AND UNCERTAINTIES
The Company's future results may be affected by changes in regional
economic conditions; the outcome of labor negotiations with unionized employees;
fluctuations in fuel, purchased power and gas prices; the actions of utility
regulatory commissions; changes in law; environmental regulations and external
factors such as the weather. As a result of state and Federal regulatory
reforms, the public utility industry is undergoing a fundamental change. As this
occurs, the electric generation business is transforming into a competitive
marketplace. The Company's future results will be impacted by its ability to
recover its stranded costs, the market price of electricity and natural gas
costs incurred previously in providing power generation to electric service
customers, and the costs of transition to an unregulated status. In addition, as
a result of deregulation, the Company may face competition from companies with
greater financial and other resources.
Summarized financial information by business segment for 2000, 1999 and
1998 is as follows:
Utility
--------------------------------------
Electric Gas Total Generation Unregulated Consolidated
-------- --- ----- ---------- ----------- ------------
(In thousands)
Twelve Months Ended:
- --------------------------
2000:
Operating revenues:
External customers............. 538,758 319,924 858,682 750,434 2,158 1,611,274
Intersegment revenues.......... 707 - 707 324,744 - 325,451
Depreciation and amortization..... 32,410 19,994 52,404 40,628 27 93,059
Interest income (loss)............ 1,158 517 1,675 39,439 7,581 48,695
Net interest charges.............. 17,771 11,089 28,860 36,065 517 65,442
Income tax expense (benefit)
From continuing operations...... 27,883 7,576 35,459 44,541 (5,656) 74,344
Operating income (loss)........... 56,827 18,600 75,427 80,359 (23,312) 132,474
Segment net income (loss)......... 39,711 10,885 50,596 74,095 (23,745) 100,946
Total assets...................... 707,837 521,636 1,229,473 1,410,554 254,206 2,894,233
Gross property additions.......... 51,815 40,418 92,233 53,025 1,620 146,878
F-14
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(1) Nature of Business and Segment Information (Continued)
Summarized financial information by business segment for 2000, 1999 and
1998 is as follows:
Utility
------------------------------------
Electric Gas Total Generation Unregulated Consolidated
-------- ----- ----- ---------- ----------- ------------
(In thousands)
Twelve Months Ended:
- --------------------------
1999:
Operating revenues:
External customers............. 540,867 236,711 777,578 371,109 8,855 1,157,542
Intersegment revenues.......... 707 - 707 318,872 - 319,579
Depreciation and amortization..... 31,113 19,210 50,323 40,253 2,084 92,660
Interest income (loss)............ 76 1,066 1,142 39,439 7,581 48,162
Net interest charges.............. 19,822 13,585 33,407 36,561 699 70,667
Income tax expense (benefit)
From continuing operations...... 23,806 2,299 26,105 25,454 (9,249) 42,310
Operating income (loss)........... 57,769 16,102 73,871 58,561 (12,352) 120,080
Cumulative effect of a change in
Accounting Principle, net of tax - - - 3,541 - 3,541
Segment net income (loss)......... 37,499 2,780 40,279 57,068 (14,192) 83,155
Total assets...................... 734,898 449,790 1,184,688 1,445,145 93,434 2,723,267
Gross property additions.......... 42,253 27,150 69,403 23,899 2,334 95,636
1998:
Operating revenues:
External customers............. 555,568 255,974 811,542 279,636 1,267 1,092,445
Intersegment revenues.......... 707 - 707 362,722 - 363,429
Depreciation and amortization..... 30,586 14,961 45,547 37,114 3,480 86,141
Interest income................... 35 957 992 16,927 17,150 35,069
Net interest charges.............. 10,211 6,498 16,709 45,559 949 63,217
Income tax expense (benefit)
from continuing operations...... 21,339 9,526 30,865 36,194 (10,768) 56,291
Operating income (loss)........... 40,386 19,051 59,437 91,462 (15,250) 135,649
Discontinued Operations
net of tax...................... - - - - (12,437) (12,437)
Segment net income (loss)......... 32,219 13,761 45,980 65,610 (28,908) 82,682
Total assets...................... 732,609 417,948 1,150,557 1,469,635 48,410 2,668,602
Gross property additions.......... 55,566 36,963 92,529 30,557 5,744 128,830
On August 4, 1998, the Company adopted a plan to discontinue the natural
gas trading operations of its Energy Services Business Unit and completely
discontinued these operations on December 31, 1998 (see Note 13).
F-15
(2) Regulatory Assets and Liabilities
The Company is subject to the provisions of SFAS 71, with respect to
operations regulated by the PRC. Regulatory assets represent probable future
revenue to the Company associated with certain costs which will be recovered
from customers through the ratemaking process. Regulatory liabilities represent
probable future reductions in revenues associated with amounts that are to be
credited to customers through the ratemaking process. Regulatory assets and
liabilities reflected in the Consolidated Balance Sheets as of December 31,
relate to the following:
2000 1999
--------- ---------
(In thousands)
Assets:
Current:
PGAC .......................................... $ 46,390 $ 19,310
Gas Take-or-Pay Costs ......................... 1,214 4,746
--------- ---------
Subtotal ................................... 47,604 24,056
--------- ---------
Deferred:
Deferred Income Taxes ......................... 33,848 35,713
Loss on Reacquired Debt ....................... 7,687 8,133
Gas Imputed Revenues........................... 2,117 7,290
Gas Reservation Fees .......................... - 7,029
Deferred Customer Expense on Gas Assets Sale .. 7,984 6,468
Gas Retirees' Health Care Costs ............... 1,724 3,264
Proposed Transmission Line Costs .............. 2,377 2,432
Gas Rate Case Costs ........................... - 1,571
Other ......................................... 482 331
--------- ---------
Subtotal .................................. 56,219 72,731
--------- ---------
Stranded and Transition Assets................. 170,630 123,167
--------- ---------
Total Assets................................ 274,453 219,454
--------- ---------
Liabilities:
Deferred:
Deferred Income Taxes ......................... (43,834) (46,815)
Gas Regulatory Reserve ........................ (980) (20,830)
Customer Gain on Gas Assets Sale .............. (7,226) (7,226)
DOE Line Acquisition........................... (2,490) (3,083)
Gain on Reacquired Debt ....................... (1,791) (708)
Other.......................................... (568) (607)
--------- ---------
Subtotal....................................... (56,889) (79,269)
--------- ---------
Stranded and Transition Liabilities............... (29,359) (24,319)
--------- ---------
Total Liabilities........................... (86,248) (103,588)
--------- ---------
Net Regulatory Assets ...................... $ 188,205 $ 115,866
========= =========
F-16
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(2) Regulatory Assets and Liabilities (Continued)
Substantially all of the Company's regulatory assets and regulatory
liabilities are reflected in rates charged to customers or have been addressed
in a regulatory proceeding.
In 1999, the State of New Mexico enacted the Restructuring Act that
provides guidelines to deregulate power generation activities in New Mexico and
opens the state's power markets to customer choice beginning 2002, according to
the currently effective schedule. The Restructuring Act recognizes that electric
utilities should be permitted a reasonable opportunity to recover an appropriate
amount of the costs previously incurred in providing electric service to their
customers ("stranded costs"). Stranded costs represent all costs associated with
generation related assets, currently in rates, in excess of the expected
competitive market price and include plant decommissioning costs, regulatory
assets, and lease and lease-related costs. Utilities will be allowed to recover
no less than 50% of stranded costs through a non-bypassable charge on all
customer bills for five years after implementation of customer choice. The PRC
could authorize a utility to recover up to 100% of its stranded costs if the PRC
finds that recovery of more than 50%: (i) is in the public interest; (ii) is
necessary to maintain the financial integrity of the public utility; (iii) is
necessary to continue adequate and reliable service; and (iv) will not cause an
increase in rates to residential or small business customers during the
transition period. The Restructuring Act also allows for the recovery of nuclear
decommissioning costs by means of a separate wires charge over the life of the
underlying generation assets.
Approximately $141 million of costs associated with the unregulated
businesses under the Restructuring Act were established as regulatory assets.
Because of the Company's belief that recovery is probable, these regulatory
assets continue to be classified as regulatory assets, although the Company has
discontinued Statement of Financial Accounting Standards No. 71, "Accounting for
the Effects of Certain Types of Regulation" (SFAS 71) and adopted Statement of
Financial Accounting Standards No. 101, "Regulated Enterprises--Accounting for
the Discontinuance of Application of FASB Statement 71." In 2000, the Company
expensed $6.6 million of these assets based on management's view of the probable
financial outcome of restructuring in New Mexico upon existing circumstances. If
discussions with the PRC staff and other parties result in a settlement in which
the amount the Company recovers for stranded costs is less than the amount it
has recorded on the balance sheet as regulatory assets, the Company will be
required to write-off the difference between its recovery of these costs and the
amount it has currently recorded. Likewise, if a delay in corporate separation
occurs, the Company may be required to write-off all or a portion of these
assets due to the uncertainty of recovery resulting from enactment of the delay.
However, Senate Bill 266 as amended establishes certain regulatory provisions
affecting these costs, which if enacted along with the delay, will allow the
Company to recover mine reclamation costs.
Pursuant to the Restructuring Act, utilities will also be allowed to
recover in full any prudent and reasonable costs incurred in implementing full
open access ("transition costs"). The transition costs will be recovered through
2007 under the current schedule by means of a separate wires charge. The Company
estimates these costs as being in excess of $46 million, including allowances
for certain costs which are non-deductible for income tax purposes. Transition
costs include professional fees, financing costs including underwriting fees,
consents relating to the transfer to assets, management information system
changes including billing system changes and public and customer
F-17
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(2) Regulatory Assets and Liabilities (Continued)
communications. Recoverable transition costs will be capitalized and amortized
over the recovery period to match related revenues. Costs not recoverable will
be expensed when incurred unless otherwise capitalizable under the accounting
rules.
Regulatory assets and liabilities reflected in the Consolidated Balance
Sheets as of December 31, related to stranded or transitions costs are as
follows:
2000 1999
----------- ------------
(In thousands)
Assets
Transition Costs.......................... $ 19,069 $ 4,293
Mine Reclamation Costs.................... 113,856 78,856
Deferred Income Taxes..................... 35,726 37,725
Loss on Reacquired Debt................... 1,979 2,293
----------- ------------
Subtotal............................... 170,630 123,167
----------- ------------
Liabilities
Deferred Income Taxes..................... (20,696) (15,091)
PVNGS Prudence Audit...................... (5,434) (5,809)
Settlement Due Customers.................. (3,205) (3,384)
Gain on Reacquired Debt................... (24) (35)
------------ ------------
Subtotal............................... (29,359) (24,319)
------------ ------------
Net Stranded Cost and Transition Cost.. $ 141,271 $ 98,848
============ ============
Based on a current evaluation of the various factors and conditions that
are expected to impact future cost recovery, the Company believes that its net
regulatory assets are probable of future recovery.
(Intentionally Left Blank)
F-18
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(3) Capitalization
Changes in common stock, additional paid-in capital, retained earnings
and comprehensive income are as follows:
Common Stock
-----------------------------
Additional
Number Aggregate Paid-In Retained
Of Shares Par Value Capital Earnings
-------------- ------------- ------------ -------------
(Dollars in thousands)
Balance at December 31, 1998................ 41,774,083 208,870 465,386 186,220
Stock repurchase (1,070,700) (5,353) (13,446) -
Tax benefit from exercise of stock options.. - - 1,453 -
Net earnings................................ - - - 83,155
Dividends:
Cumulative preferred stock............... - - - (586)
Common Stock............................. - - - (40,960)
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising
During the period...................... - - - -
Less reclassification adjustment for
Gains included in net income........... - - - -
Minimum pension liability adjustment........ - - - -
-------------- ------------ ------------ --------------
Balance at December 31, 1999................ 40,703,383 203,517 453,393 227,829
Stock Repurchase............................ (1,585,584) (7,928) (19,939) -
Exercise of stock options................ - - (1,232) -
Net earnings................................ - - - 100,946
Dividends:
Cumulative preferred stock............... - - - (586)
Common Stock............................. - - - (31,346)
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising
During the period...................... - - - -
Less reclassification adjustment for
Gains included in net income........... - - - -
-------------- ------------ ------------ -------------
Balance at December 31, 2000................ 39,117,799 195,589 432,222 296,843
============== ============ ============ =============
F-19
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(3) Capitalization (Continued)
Comprehensive Income
The Company's investments held in rabbi trust for certain retirement
benefits are classified as available-for-sale, and accordingly unrealized
holding gains and losses are recognized as a component of comprehensive income.
Realized gains and losses are included in earnings. Net losses related to the
Company's pension plans, not yet recognized as net periodic pension costs (or
additional minimum liability) are reported as a component of comprehensive
income. Changes in the liability are adjusted as necessary. All components of
comprehensive income are recorded, net of any tax benefit or expense. A deferred
asset or liability is established for the resulting temporary difference.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(In thousands)
Net Earnings...................................... $100,946 $83,155 $82,682
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising from
the period................................. 2,794 4,120 1,519
Less reclassification adjustment for gains
included in net income..................... (5,173) (4,282) (673)
Minimum pension liability adjustment.......... - 1,387 (205)
-------- -------- --------
Total Other Comprehensive Income.................. (2,379) 1,225 641
--------- -------- --------
Total Comprehensive Income........................ $98,567 $84,380 $83,323
========= ======== ========
Common Stock
The number of authorized shares of common stock with par value of $5 per
share is 80 million shares. The declaration of common dividends is dependent on
a number of factors, including the extent to which cash flows will support
dividends, the availability of retained earnings, the financial circumstances
and performance of the Company and the PRC's decisions on the Company's various
regulatory cases currently pending. In addition, the ability to recover stranded
costs in deregulation, future growth plans and the related capital requirements
and standard business considerations will also affect the Company's ability to
pay dividends.
In March 1999, the Company's Board of Directors approved a plan to
repurchase up to 1,587,000 shares of the Company's outstanding common stock with
maximum purchase price of $19.00 per share. In December 1999, the Company's
Board of Directors authorized the Company to repurchase
F-20
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(3) Capitalization (Continued)
up to an additional $20.0 million of the Company's common stock. As of December
31, 1999, the Company had repurchased 1,070,700 shares of its previously
outstanding common stock at a cost of $18.8 million. From January 2, 2000
through March 31, 2000, the Company repurchased an additional 1,167,684 shares
of its previously outstanding common stock at a cost of $18.9 million. On August
8, 2000, the Company's Board of Directors approved a plan to repurchase up to
$35 million of the Company's common stock through the end of the first quarter
of 2001. From August 8, 2000 through December 31, 2000, the Company repurchased
an additional 417,900 shares of its outstanding common stock at a cost of $9.0
million. The Company may from time-to-time repurchase additional common stock
for various corporate purposes.
On September 16, 1996, the Company implemented a dividend reinvestment
and stock purchase plan for investors, including customers and employees. The
plan, called PNM Direct, also includes safekeeping services and automatic
investment features. The Company's stock is purchased in the open market to meet
plan requirements.
Cumulative Preferred Stock
The number of authorized shares of cumulative preferred stock is 10
million shares. The Company has 128,000 shares, 1965 Series, 4.58%, stated value
of $100 per share, of cumulative preferred stock outstanding. The 1965 Series
does not have a mandatory redemption requirement but may be redeemable at 102%
of the par value with accrued dividends. The holders of the 1965 Series are
entitled to payment before holders of common stock in the event of any
liquidation or dissolution or distribution of assets of the Company. In
addition, the 1965 Series is not entitled to a sinking fund and cannot be
converted into any other class of stock of the Company. The Company's restated
articles of incorporation limit the amount of preferred stock which may be
issued. The earnings test in the Company's restated articles of incorporation
currently allows for the issuance of additional preferred stock.
Long-Term Debt
The Company has $268,420,000 of long-term debt that matures in August
2005.
On March 11, 1998, the Company modified its 1947 Indenture of Mortgage
and Deed of Trust; no future bonds can be issued under the mortgage. The first
mortgage bonds continue to serve as collateral for the tax-exempt pollution
control revenue bonds ("PCBs") in the outstanding principal amount of $111
million.
In March 1998, the Company replaced the first mortgage bonds
collateralizing $463 million of PCBs with senior unsecured notes ("SUNs") which
were issued under a new senior unsecured note indenture. Also, in March 1998,
the Company retired $140 million principal amount of first mortgage bonds. While
first mortgage bonds continue to serve as collateral for PCBs in the outstanding
principal amount of $111 million, the lien of the mortgage was substantially
reduced to cover only the Company's ownership interest in PVNGS. With the
exception of the $111 million of PCBs secured by first mortgage bonds, the SUNs
are and will be the senior debt of the Company.
F-21
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(3) Capitalization (Continued)
In August 1998, the Company issued and sold $435 million of SUNs in two
series, the 7.10% Series A due August 1, 2005, in the principal amount of $300
million, and the 7.50% Series B due August 1, 2018, in the principal amount of
$135 million. These SUNs were issued under an indenture similar to the indenture
under which the SUNs were issued in March 1998, and it is expected that future
long-term debt financings will be similarly issued.
On October 28, 1999, tax-exempt pollution control revenue bonds of $11.5
million with an interest rate of 6.60% were issued to partially reimburse the
Company for expenditures associated with its share of a recently completed
upgrade of the emission control system at SJGS.
In 1999, the Company retired $31.6 million of its 7.10% senior unsecured
notes through open market purchases, utilizing the funds from operations and the
funds from temporary investments. In January 2000, the Company retired $35.0
million of its 7.5% senior unsecured notes through open market purchases
utilizing funds from operations and the funds from temporary investments. The
gains recognized on these purchases were immaterial.
Revolving Credit Facility and Other Credit Facilities
At December 31, 2000, the Company had a $150 million unsecured revolving
credit facility (the "Facility") with an expiration date of March 11, 2003. The
Company must pay commitment fees of 0.1875% per year on the total amount of the
Facility. There were no outstanding borrowings under the Facility as of December
31, 2000, and the Company was in compliance with all covenants under the
Facility.
(4) Lease Commitments
The Company leases interests in Units 1 and 2 of PVNGS, certain
transmission facilities, office buildings and other equipment under operating
leases. The lease expense for PVNGS is $66.3 million per year over base lease
terms expiring in 2015 and 2016. Covenants in the Company's PVNGS Units 1 and 2
lease agreements limit the Company's ability, without consent of the owner
participants and bondholders in the lease transactions, (i) to enter into any
merger or consolidation, or (ii) except in connection with normal dividend
policy, to convey, transfer, lease or dividend more than 5% of its assets in any
single transaction or series of related transactions.
Future minimum operating lease payments (in thousands) at December 31, 2000
are:
2000 ..................................... $ 78,998
2001 ..................................... 78,884
2002 ..................................... 78,881
2003 ..................................... 78,881
2004 ..................................... 78,881
Later years .............................. 723,305
----------
Total minimum lease payments .......... $1,117,830
==========
F-22
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(4) Lease Commitments (Continued)
Operating lease expense, inclusive of PVNGS leases, was approximately
$81.6 million in 2000, $81.1 million in 1999 and $82.6 million in 1998.
Aggregate minimum payments to be received in future periods under noncancelable
subleases are approximately $4.1 million.
(5) Financial Instruments
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices and adverse market changes
for investments held by the Company's various trusts. The Company also uses
certain derivative instruments for bulk power electricity trading purposes in
order to take advantage of favorable price movements and market timing
activities in the wholesale power markets.
The estimated fair value of the Company's financial instruments
(including current maturities) at December 31, is as follows:
2000 1999
--------------------- -----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
(In thousands)
Long-Term Debt ................................. 953,823 930,359 $(988,489) $(932,687)
Investment in PVNGS Lessors' Notes.............. 405,960 440,079 424,605 455,888
Derivatives..................................... 4,296 194,372 117 (25,921)
Decommissioning Trust........................... 54,977 54,977 51,752 51,752
Fossil-Fueled Plant Decommissioning Trust....... 4,760 4,760 4,591 4,591
Rabbi Trust..................................... 12,284 14,281 16,901 16,931
Fair value is based on market quotes provided by the Company's
investment bankers and trust advisors and the Company's risk management models.
The carrying amounts reflected on the consolidated balance sheets
approximate fair value for cash, temporary investments, and receivables and
payables due to the short period of maturity.
The Company is exposed to credit losses in the event of non-performance
or non-payment by counterparties. The Company uses a credit management process
to assess and monitor the financial conditions of counterparties. The Company's
credit risk with its largest counterparty as of December 31, 2000 was $16.7
million.
Natural Gas Contracts
Pursuant to a 1997 order issued by the NMPUC, predecessor to the PRC, the
Company has previously entered into swaps to hedge certain portions of natural
gas supply contracts in order to protect the Company's natural gas customers
from the risk of adverse price fluctuations in the natural gas market. The
financial impact of all hedge gains and losses from swaps is recoverable through
the Company's purchased gas adjustment clause as deemed prudently incurred by
the PRC. As a result,
F-23
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(5) Financial Instruments (Continued)
earnings were not affected by gains or losses generated by these instruments.
The Company hedged 40% of its natural gas deliveries during the 1998-1999
heating season. Less than 15.5% of the 1998-1999 heating season portfolio was
hedged using financial hedging contracts. The Company hedged a portion of its
1999-2000 heating season gas supply portfolio through the use of both physical
and financial hedging tools. Less than 9.1% of the Company's 1999-2000 heating
season portfolio was hedged using financial hedging contracts.
The Company contracted for gas price caps, a type of hedge, to protect
its natural gas customers from price risk during the 2000-2001 heating season
through the use of financial hedging tools. The Company expended $5 million to
purchase price cap options that limit the maximum amount the Company would pay
for gas during the winter heating season. The Company recovered the $5 million
in hedging costs during the months of October and November 2000 in equal $2.5
million allotments as a component of the PGAC. Results of the winter 2000-2001
hedging activities were an estimated $27 million benefit to system gas supply
customers in the form of lower gas costs, net of the cost of the price caps.
Fuel Hedging
The Company's Generation and Trading Operations commenced a program to
reduce its exposure to fluctuations in prices for gas and oil purchases used as
a fuel source for some of its generation. The Generation and Trading Operations
purchased futures contracts for a portion of its anticipated natural gas needs
in the third quarter and fourth quarter. The futures contracts capped the
Company's natural gas purchase prices at $3.70 to $3.99 per MMBTU and had a
notional principal of $4.5 million. Simultaneously, a delivery location basis
swap was purchased for quantities corresponding to the futures quantities to
protect against price differential changes at the specific delivery points. A
portion of financial instruments settled in the third quarter and the remaining
in the fourth quarter. The Company accounted for these transactions as hedges;
accordingly, gains and losses related to these transactions are deferred and
recognized in earnings as an adjustment to its cost of fuel. The fuel hedge
program ended in October 2000.
Electricity Trading Contracts
To take advantage of market opportunities associated with the purchase
and sale of electricity, the Company's Generation and Trading Operations
periodically enters into derivative financial instrument contracts. In addition,
the Company enters into forward physical contracts and physical options. The
Company generally accounts for these financial instruments as trading activities
under the accounting guidelines set forth under The Emerging Issues Task Force
("EITF") Issue No. 98-10, although at times the Company may enter into contracts
that it may designate as hedges. As a result, all open contracts are marked to
market at the end of each period. The physical contracts are subsequently
recognized as revenues or purchased power when the actual physical delivery
occurs. The Company implemented EITF Issue No. 98-10 as of January 1, 1999 and
recorded as a cumulative effect of a change in accounting principle a gain of
approximately $3.5 million, net of taxes, or $0.09 per common share, on net open
physical electricity purchases and sales commitments considered to be trading
activities.
F-24
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(5) Financial Instruments (Continued)
Through December 31, 2000, the Company's wholesale electric trading
operations settled trading contracts for the sale of electricity that generated
$88.9 million of electric revenues by delivering 2.1 million KWh. The Company
purchased $78.6 million or 1.9 million KWh of electricity to support these
contractual sale and other open market sales opportunities.
As of December 31, 2000, the Company had open trading contract positions
to buy $10.9 million and to sell $4.3 million of electricity. At December 31,
2000, the Company had a gross mark-to-market gain (asset position) on these
trading contracts of $6.8 million and gross mark-to-market loss (liability
position) of $11.4 million, with net mark-to-market loss (liability position) of
$4.6 million. The mark-to-market valuation is recognized in earnings each
period.
The Company's wholesale power marketing operations, including both firm
commitments and trading activities, are managed through an asset backed
strategy, whereby the Company's aggregate net open position is covered by its
own excess generation capabilities. The Company is exposed to market risk if its
generation capabilities were disrupted or if its jurisdictional load
requirements were greater than anticipated. If the Company were required to
cover all or a portion of its net open contract position, it would have to meet
its commitments through market purchases. The Company's value-at-risk
calculation considers this exposure (see Item 7A. Quantitative and Qualitative
Disclosure About Market Risk).
New Accounting Standard
On January 1, 2001, the Company implemented Statement of Financial
Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging
Activities (see Note 15 - New and Proposed Accounting Standards).
Hedge of Trust Assets
As of December 31, 2000, the Company had about $33 million invested in
domestic stocks in various trusts for nuclear decommissioning, executive
retirement and retiree medical benefits. The Company uses financial derivatives
based on the Standard & Poor's ("S&P") 500 Index to limit potential loss on
these investments due to adverse market fluctuations. The options are structured
as a collar, protecting the portfolio against losses beyond a certain amount and
balancing the cost of that downside protection by forgoing gains above a certain
level. If the S&P 500 Index is within the specified range when the option
contract expires, the Company will not be obligated to pay, nor will the Company
have the right to receive cash. In February 2000, certain contracts were
terminated. These new contracts increase the downside protection and further
limit the upside gain. Subsequently, the Company entered into similar contracts
which expire on June 15, 2001. In October and November 2000, certain of these
contracts were terminated. The Company recognized realized gains of $0.7 million
for the year ended December 31, 2000, and recorded net unrealized gains of $3.0
million (pre-tax) on the market value of its options. The net effect of the
collar instruments for the year ended December 31, 2000 were net pre-tax gains
of $3.7 million.
F-25
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(6) Earnings Per Share
In accordance with SFAS No. 128, Earnings per Share, dual presentation
of basic and diluted earnings per share has been presented in the Consolidated
Statements of Earnings. The following reconciliation illustrates the impact on
the share amounts of potential common shares and the earnings per share amounts:
2000 1999 1998
----------- ---------- -----------
Basic:
Net Earnings from Continuing Operations............................... $ 100,946 $ 79,614 $ 95,119
Discontinued Operations, net of tax (note 13): - - (12,437)
Cumulative Effect of a Change in Accounting
Principle, net of tax (note 14).................................... 3,541 -
----------- ----------- -----------
Net Earnings.......................................................... 100,946 83,155 82,682
Preferred Stock Dividend Requirements................................. 586 586 586
----------- ----------- -----------
Net Earnings Applicable to Common Stock............................... $ 100,360 $ 82,569 $ 82,096
=========== =========== ===========
Average Number of Common Shares Outstanding........................... 39,487 41,038 41,774
=========== =========== ===========
Net Earnings (Loss) per Share of Common Stock:
Earnings from continuing operations................................. $ 2.54 $ 1.93 $ 2.27
Discontinued operations (note 13)................................... - - (0.30)
Cumulative effect of a change in accounting principle (note 14)..... - 0.08 -
----------- ----------- -----------
Net Earnings per Share of Common Stock (Basic)........................ $ 2.54 $ 2.01 $ 1.97
=========== =========== ===========
Diluted:
Net Earnings from Continuing Operations............................... $ 100,946 $ 79,614 $ 95,119
Discontinued Operations, net of tax (note 13)......................... - - (12,437)
Cumulative Effect of a Change in Accounting
Principle, net of tax (note 14).................................... - 3,541 -
----------- ----------- -----------
Net Earnings.......................................................... $ 100,946 83,155 82,682
Preferred Stock Dividend Requirements................................. 586 586 586
----------- ----------- -----------
Net Earnings Applicable to Common Stock............................... $ 100,360 $ 82,569 $ 82,096
=========== =========== ===========
Average Number of Common Shares Outstanding........................... 39,487 41,038 41,774
Diluted effect of common stock equivalents (a)........................ 223 65 298
----------- ----------- -----------
Average common and common equivalent shares
Outstanding......................................................... 39,710 41,103 42,072
=========== =========== ===========
Net Earnings (Loss) per Share of Common Stock:
Earnings from continuing operations................................. $ 2.53 $ 1.93 $ 2.25
Discontinued operations.............................................
- (0.30)
Cumulative effect of a change in accounting principle............... -
0.08 -
----------- ----------- ----------
ngs per Share of Common Stock (Basic)................................. $ 2.53 $ 2.01 $ 1.95
=========== =========== ==========
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out of-the-money options of 105,336; 66,143; and 23,794 for the years
ended 2000, 1999 and 1998, respectively.
F-26
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(7) Income Taxes
Income taxes before discontinued operations and cumulative effect of a
change in accounting principle consist of the following components:
2000 1999 1998
----------- ---------- -----------
(In thousands)
Current Federal income tax ................ $ 41,666 $ 23,511 $ 32,785
Current state income tax .................. 13,726 8,502 11,451
Deferred Federal income tax ............... 19,729 13,494 15,797
Deferred state income tax ................. 2,368 210 (324)
Amortization of accumulated
investment tax credits .................... (3,143) (3,409) (3,418)
----------- ---------- -----------
Total income taxes ...................... $ 74,346 $ 42,308 $ 56,291
=========== ========== ===========
Charged to operating expenses ............. $ 53,964 $ 25,010 $ 41,306
Charged to other income and deductions ... 20,382 17,298 14,985
----------- ---------- -----------
Total income taxes....................... $ 74,346 $ 42,308 $ 56,291
=========== ========== ===========
The Company's provision for income taxes before discontinued operations
and cumulative effect of a change in accounting principle differed from the
Federal income tax computed at the statutory rate for each of the years shown.
The differences are attributable to the following factors:
2000 1999 1998
--------- --------- ---------
(In thousands)
Federal income tax at statutory rates .......... $ 61,352 $ 42,673 $ 52,993
Investment tax credits ......................... (3,143) (3,409) (3,418)
Depreciation of flow-through items ............. 2,250 605 531
Gains on the sale and leaseback of PVNGS
Units 1 and 2 ............................... (527) (527) (527)
Dividends received deduction.................... - (1,301) -
Annual reversal of deferred income taxes
accrued at prior tax rates.................... (2,477) (2,320) (1,905)
Income tax related regulatory asset write-off... 6,552 - -
State income tax ............................... 8,343 5,541 7,074
Other .......................................... 1,996 1,046 1,543
--------- --------- ---------
Total income taxes .......................... $ 74,346 $ 42,308 $ 56,291
========= ========= =========
Effective tax rate 42.41% 34.70% 37.18%
F-27
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(7) Income Taxes (Continued)
The components of the net accumulated deferred income tax liability
were:
2000 1999
--------- ---------
(In thousands)
Deferred Tax Assets:
Alternative minimum tax credit carryforward....... $ - $ 18,420
Nuclear decommissioning costs..................... 23,892 22,073
Regulatory liabilities related to income taxes ... 41,695 44,547
Other ............................................ 69,469 52,199
--------- ---------
Total deferred tax assets .................... 135,056 137,239
--------- ---------
Deferred Tax Liabilities:
Depreciation ..................................... 184,127 184,687
Investment tax credit ............................ 47,853 50,996
Fuel costs ....................................... 24,808 15,984
Regulatory assets related to income taxes......... 67,435 71,170
Other ............................................ 45,631 33,668
--------- ---------
Total deferred tax liabilities ............... 369,854 356,505
--------- ---------
Accumulated deferred income taxes, net .............. $234,798 $219,266
========= =========
The following table reconciles the change in the net accumulated
deferred income tax liability to the deferred income tax expense included in the
consolidated statement of earnings for the period:
Net change in deferred income tax liability per above table........... $15,532
Change in tax effects of income tax related regulatory assets
and liabilities.................................................... 882
Tax effect of mark-to-market on investments available for sale........ 2,540
Deferred income tax expense from continuing operations
---------
for the period..................................................... $18,954
=========
The Company has no net operating loss carryforwards as of December 31,
2000.
The Company defers investment tax credits related to rate regulated
assets and amortizes them over the estimated useful lives of those assets. The
Company anticipates that this practice will continue when the generation assets
are no longer rate regulated upon full implementation of the Restructuring Act.
(8) Pension and Other Postretirement Benefits
Pension Plan
The Company and its subsidiaries have a pension plan covering
substantially all of their union and non-union employees, including officers.
The plan is non-contributory and provides for benefits to be paid to eligible
employees at retirement based primarily upon years of service with the Company
and the average of their highest annual base salary for three consecutive years.
F-28
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(8) Pension and Other Postretirement Benefits (Continued)
The Company's policy is to fund actuarially-determined contributions.
Contributions to the plan reflect benefits attributed to employees' years of
service to date and also for services expected to be provided in the future.
Plan assets primarily consist of common stock, fixed income securities, cash
equivalents and real estate.
In December 1996, the Board of Directors approved changes to the
Company's non-contributory defined benefit plan ("Retirement Plan") and the
implementation of a 401(k) defined contribution plan effective January 1, 1998.
Salaries used in Retirement Plan benefit calculations were frozen as of December
31, 1997. Additional credited service can be accrued under the Retirement Plan
up to a limit determined by age and years of service. The Company contributions
to the 401(k) plan consist of a 3 percent non-matching contribution, and a 75
percent match on the first 6 percent contributed by the employee on a before-tax
basis. The Company contributed $8.9 and $8.4 million in the years ended December
31, 2000 and 1999.
The following sets forth the pension plan's funded status, components of
pension costs and amounts (in thousands) at December 31:
Pension Benefits
-------------------------
2000 1999
------------ -----------
Change in Benefit Obligation:
Benefit obligation at beginning of year........... $331,061 $330,048
Service cost...................................... 6,491 7,407
Interest cost..................................... 23,572 21,777
Actuarial gain.................................... (30,934) (12,797)
Benefits paid..................................... (17,038) (15,374)
------------ -----------
Benefit obligation at end of period........... 313,152 331,061
------------ -----------
Change in Plan Assets:
Fair value of plan assets at beginning of year.... 361,640 330,556
Actual return on plan assets...................... 45,225 46,458
Employer contribution............................. - -
Benefits paid..................................... (17,038) (15,374)
------------ -----------
Fair value of plan assets at end of year...... 389,827 361,640
------------ -----------
Funded Status..................................... 76,675 30,579
Unamortized transition assets..................... (1,158) (2,322)
Unrecognized net actuarial gain................... (57,445) (12,209)
Unrecognized prior service cost................... 44 78
------------ -----------
Prepaid pension cost.......................... $18,116 $16,126
============ ===========
Weighted - Average Assumptions as of December 31,
Discount rate..................................... 8.25% 7.50%
Expected return on plan assets.................... 9.00% 8.75%
Rate of compensation increase..................... N/A N/A
F-29
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(8) Pension and Other Postretirement Benefits (Continued)
Pension Benefits
---------------------------------
2000 1999 1998
--------- ---------- ----------
Components of Net Periodic Benefit Cost:
Service cost............................... $ 6,491 $ 7,407 $ 6,660
Interest cost.............................. 23,572 21,777 20,101
Expected return on plan assets............. (30,923) (27,466) (26,755)
Amortization of prior service cost......... (1,130) (1,130) (1,130)
--------- ---------- ----------
Net periodic pension costs (benefits).... $ (1,990) $ 588 $ (1,124)
========= ========== ==========
Other Postretirement Benefits
The Company provides medical and dental benefits to eligible retirees.
Currently, retirees are offered the same benefits as active employees after
reflecting Medicare coordination. The following sets forth the plan's funded
status, components of net periodic benefit cost (in thousands) at December 31:
Other Benefits
--------------------------
2000 1999
----------- -------------
Change in Benefit Obligation:
Benefit obligation at beginning of year........... $ 73,765 $ 74,539
Service cost...................................... 1,053 1,402
Interest cost..................................... 5,428 4,782
Actuarial loss (gain)............................. 1,465 (6,958)
----------- -------------
Benefit obligation at end of period........... 81,711 73,765
----------- -------------
Change in Plan Assets:
Fair value of plan assets at beginning of year.... 41,825 37,602
Actual return on plan assets....................... 3,661 5,269
Employer contribution............................. 1,431
597
Benefits paid..................................... (2,224) (1,643)
----------- -------------
Fair value of plan assets at end of year...... 44,693 41,825
----------- -------------
Funded Status..................................... (37,018) (31,940)
Unamortized transition assets..................... 3,181 (622)
Unrecognized prior service cost................... 21,805 23,617
----------- -------------
Accrued postretirement benefits (cost)....... $ (12,032) $ (8,945)
=========== =============
Weighted - Average Assumptions as of December 31,
Discount rate..................................... 8.25% 7.50%
Expected return on plan assets.................... 9.00% 8.75%
Rate of compensation increase..................... N/A N/A
F-30
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(8) Pension and Other Postretirement Benefits (Continued)
Pension Benefits
--------------------------------
2000 1999 1998
--------- ---------- ---------
Components of Net Periodic Benefit Cost:
Service cost.............................. $ 1,053 $ 1,402 $ 1,292
Interest cost............................. 5,428 4,782 4,501
Expected return on plan assets............ (3,572) (3,135) (2,943)
Amortization of prior service cost........ 1,817 1,817 1,817
--------- ---------- ---------
Net periodic post retirement
benefit cost....................... $ 4,726 $ 4,866 $ 4,667
========= ========== =========
The effect of a 1% increase in the health care trend rate assumption
would increase the accumulated postretirement benefit obligation as of December
31, 2000, by approximately $12.9 million and the aggregate service and interest
cost components of net periodic postretirement benefit cost for 2000 by
approximately $1.6 million. The health care cost trend rate is expected to
decrease to 5.5% by 2007 and to remain at that level thereafter.
Executive Retirement Program
The Company has an executive retirement program for a group of management
employees. The program was intended to attract, motivate and retain key
management employees. The Company's projected benefit obligation for this
program, as of December 31, 2000, was $16.9 million, of which the accumulated
and vested benefit obligation was $16.9 million. As of December 31, 2000, the
Company has recognized an additional liability of $2.0 million for the amount of
unfunded accumulated benefits in excess of accrued pension costs. The net
periodic cost for 2000, 1999 and 1998 was $1.9 million, $2.3 million and $2.3
million, respectively. In 1989, the Company established an irrevocable grantor
trust in connection with the executive retirement program. Under the terms of
the trust, the Company may, but is not obligated to, provide funds to the trust,
which was established with an independent trustee, to aid it in meeting its
obligations under such program. Marketable securities in the amount of
approximately $12.3 million (fair market value of $14.3 million) are presently
in trust. No additional funds have been provided to the trust since 1989.
(9) Stock Option Plans
The Company's Performance Stock Plan ("PSP") is a non-qualified stock
option plan, covering a group of management employees. Options to purchase
shares of the Company's common stock are granted at the fair market value of the
shares on the date of the grant. Options granted through December 31, 1995
vested on June 30, 1996 and have an exercise term of up to 10 years. All
subsequent awards granted after December 31, 1995, vest three years from the
grant date of the awards. Options granted or approved on or after February 9,
1998, can also vest upon retirement. The maximum number of options authorized
are five million shares that could be granted through December 31, 2000.
F-31
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(9) Stock Option Plans (Continued)
On June 6, 2000, the shareholders approved a new employee stock incentive
plan, the Omnibus Performance Equity Plan ("the Omnibus Plan"). The Omnibus Plan
is subject to consummation of the share exchange to form the new holding company
as part of separation under the Restructuring Act. The Omnibus Plan provides for
the granting of Non-Qualified Stock Options, incentive stock options, restricted
stock rights, performance shares, performance units and stock appreciation
rights to officers and key employees. The total number of shares of common stock
subject to awards under the Omnibus Plan may not exceed five million, subject to
adjustment under certain circumstances defined in the Omnibus Plan.
In addition, the Company has a Director Retainer Plan ("DRP") which
provides for payment of the Directors' annual retainer in the form of cash,
restricted stock or options to purchase shares of the Company's common stock.
The number of options granted in 2000 and 1999 under the DRP was 6,000 shares
with an exercise price of $6.19 and 8,000 shares with an exercise price of
$9.69, respectively. 4,000 options were exercised under the DRP during 2000. The
maximum number of options authorized are 100,000 shares through April 30, 2002.
The number of options outstanding as of December 31, 2000, was 31,000.
Restricted Stock issuances are based on the fair market value of the Company's
common stock on the date of grant and vest over three years. As of December 31,
2000, 14,985 shares of restricted stock issued under the DRP were outstanding.
The fair value of each option grant is determined on the date of grant
using the Black-Scholes option-pricing model with the following average
assumptions used for grants in 1998, 1999 and 2000, respectively: dividend yield
of 3.75%, 4.9% and 2.98%; expected volatility of 26.78%, 30.29% and 26.43%,
risk-free interest rates of 4.65%, 6.43%; and 5.11%.
F-32
(9) Stock Option Plans (Continued)
A summary of the status of the Company's stock option plans at December
31, and changes during the years then ended is presented below. Prior periods
have been restated for comparability purposes.
2000 1999 1998
--------------------- ------------------------- -------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
- --------------------------------------- ---------- ---------- ----------- ----------- ---------- --------
Outstanding at beginning of year....... 1,574,418 $18.187 1,014,242 $18.819 1,536,662 $17.704
Granted................................ 2,078,500 $19.403 608,708 $17.397 10,000 $12.750
Exercised.............................. 296,027 $16.290 - N/A 473,063 $14.663
Forfeited.............................. 20,670 $17.320 48,532 $18.649 59,357 $21.194
---------- ----------- ----------
Outstanding at end of year............. 3,336,221 1,574,418 1,014,242
========== =========== ==========
Options exercisable at year-end ....... 916,263 766,454 435,409
========== =========== ==========
Options available for future grant .... - 2,183,624 2,752,806
========== =========== ==========
Weighted-average fair value of
options granted during the year:
PSP............................... $7.24 $3.89 N/A
========== =========== ==========
DRP............................... $6.98 $5.85 $7.32
========== =========== ==========
The following table summarizes information about stock options outstanding at
December 31, 2000:
Options Outstanding Options Exercisable
-------------------------------------------------- ---------------------------
Weighted-
Average Weighted Weighted
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 12/31/00 Life Prices At 12/31/00 Prices
- ------------------- ------------------ ----------------- ------------- -------------- ------------
$5.50 - $12.75 31,000 7.63 years $ 8.605 25,000 $ 9.185
$11.50 - $24.313 3,305,221 8.55 years $19.220 891,263 $19.109
------------ -----------
3,336,221 8.54 years $19.121 916,263 $18.839
============ ===========
F-33
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(9) Stock Option Plans (Continued)
Had compensation cost for the Company's performance stock plan been
determined consistent with SFAS No. 123, Accounting for Stock-Based
Compensation, the effect on the Company's pro forma net earnings and pro forma
earnings per share would be as follows (in thousands, except per share data):
2000 1999 1998
------------------------- ------------------------ -----------------------
As Reported Pro forma As Reported Pro forma As Reported Pro forma
------------- ---------- ------------ ---------- ------------- ---------
Net earnings: (available for
Common)...................... 100,360 96,735 $82,569 $81,573 $82,096 $81,554
Net earnings per share
Basic...................... $2.54 $2.45 $2.01 $1.99 $1.97 $1.95
Diluted.................... $2.53 $2.44 $2.01 $1.98 $1.95 $1.95
(10) Construction Program and Jointly-Owned Plants
The Company's construction expenditures for 2000 were approximately
$147.0 million, including expenditures on jointly-owned projects. The Company's
proportionate share of expenses for the jointly-owned plants is included in
operating expenses in the consolidated statements of earnings.
At December 31, 2000, the Company's interests and investments in
jointly-owned generating facilities are:
Construction
Plant in Accumulated Work in Composite
Station (Fuel Type) Service Depreciation Progress Interest
---------- ------------- ----------- ---------
(In thousands)
San Juan Generating Station (Coal)... $706,063 $351,618 $ 827 46.3%
Palo Verde Nuclear Generating
Station (Nuclear)*................. $197,141 $ 54,518 $ 25,291 10.2%
Four Corners Power Plant Units 4
and 5 (Coal) ..................... $117,797 $ 74,000 $ 3,066 13.0%
- ---------------
* Includes the Company's interest in PVNGS Unit 3, the Company's interest
in common facilities for all PVNGS units and the Company's owned
interests in PVNGS Units 1 and 2.
San Juan Generating Station ("SJGS")
The Company operates and jointly owns SJGS. At December 31, 2000, SJGS
Units 1 and 2 are owned on a 50% shared basis with Tucson Electric Power
Company, Unit 3 is owned 50% by the Company, 41.8% by Southern California Public
Power Authority ("SCPPA") and 8.2% by Tri-State Generation and Transmission
Association, Inc. Unit 4 is owned 38.457% by the Company, 28.8% by M-S-R Public
Power Agency, ("M-S-R"), 10.04% by the City of Anaheim, California, 8.475% by
the City of Farmington, 7.2% by the County of Los Alamos, and 7.028% by Utah
Associated Municipal Power Systems.
F-34
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(10) Construction Program and Jointly-Owned Plants (Continued)
Palo Verde Nuclear Generating Station
The Company is a participant in the three 1,270 MW units of PVNGS, also
known as the Arizona Nuclear Power Project, with Arizona Public Service Company
("APS") (the operating agent), Salt River Project, El Paso Electric Company ("El
Paso"), Southern California Edison Company, SCPPA and The Department of Water
and Power of the City of Los Angeles. The Company has a 10.2% undivided interest
in PVNGS, with portions of its interests in Units 1 and 2 held under leases.
(See Note 11 for additional discussion.)
(11) Commitments and Contingencies
Long-Term Power Contracts
The Company has a power purchase contract with Southwestern Public
Service Company ("SPS") which originally provided for the purchase of up to 200
MW, expiring in May 2011. The Company may reduce its purchases from SPS by 25 MW
annually upon three years' notice. The Company provided such notice to reduce
the purchase by 25 MW in 1999 and by an additional 25 MW in 2000. The Company
has 39 MW of contingent capacity obtained from El Paso under a transmission
capacity for generation capacity trade arrangement that increases to 70 MW from
1999 through 2003. In addition, the Company is interconnected with various
utilities for economy interchanges and mutual assistance in emergencies.
In 1996, the Company entered into a long-term PPA for the rights to all
the output of a new gas-fired generating plant. The plant received FERC approval
for "exempt wholesale generator" status with respect to the gas turbine
generating unit. The PPA's maximum dependable capacity is 132 MW. In July 2000,
the plant went into operation. The gas turbine generating unit is operated by
Delta and is located on the Company's retired Person Generating Station site in
Albuquerque, New Mexico. Primary fuel for the gas turbine generating unit is
natural gas, which is provided by the Company. In addition, the unit has the
capability to utilize low sulfur fuel oil in the event natural gas is not
available or cost effective. For accounting purposes, the PPA is treated as an
operating lease.
The Company has been actively trading in the wholesale power market and
has entered into and anticipates that it will continue to enter into power
purchases to accommodate its trading activity.
Construction Commitment
The Company has committed to purchase a combustion turbine for $36.0
million. In February 2000, the Company made a 10% deposit toward the purchase
price. The turbine is for a planned power generation plant with an estimated
cost of approximately $63.0 million for which a contract has not been finalized.
The planned plant is part of the Company's ongoing competitive strategy of
increasing generation capacity over time.
F-35
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(11) Commitments and Contingencies (Continued)
Plains Acquisition
The Company and Tri-State Generation and Transmission Association, Inc.
("Tri-State") entered into an asset sale agreement dated September 9, 1999,
pursuant to which Tri-State agreed to sell the Company certain assets acquired
by Tri-State's merger with Plains Electric Generation and Transmission
Cooperative, Inc., consisting primarily of transmission assets, a fifty percent
interest in an inactive power plant located near Albuquerque, and an office
building in Albuquerque. The purchase price is $13.2 million, subject to
adjustment at the time of closing with the transaction to close in two phases.
The asset sale agreement contains standard covenants and conditions for this
type of agreement. On July 1, 2000, the first phase was completed, and the
Company acquired the 50 percent ownership in the inactive power plant and the
office building. The second phase relating to the transmission assets is
expected to close in the first quarter of 2001.
In addition, on July 1, 2000, the Company advanced $11.8 million to a
former Plains cooperative member as part of an agreement for the Company to
become the cooperative's power supplier. Approximately $4.5 million of this
advance represents an inducement for entering into a 10 year power sales
agreement. Accordingly, the Company has expensed this amount in the third
quarter as a business development cost. The remaining $7.5 million will be
repaid over 10 years. If the cooperative terminates the contract early, the
whole $11.8 million advance must be repaid to the Company.
New Customer Billing System
On November 30, 1998, the Company implemented a new customer billing
system. Due to a significant number of problems associated with the
implementation of the new billing system, the Company was unable to generate
appropriate bills for all its customers through the first quarter of 1999 and
was unable to analyze delinquent accounts until November 1999.
Under PRC rules and PRC approved Company rules, the Company is required
to issue customer bills on a monthly basis. The Company was granted a temporary
variance, and the PRC began a hearing on whether the Company violated PRC rules,
regulations or orders or the New Mexico Public Utility Act. The investigation
was concluded on November 2, 1999, without the PRC imposing any civil penalty on
the Company and with an approved stipulation that the Company be permitted to
bill an additional service charge to customers who were not billed the
appropriate electric service charge or gas access fee. The stipulation was
limited to approximately $0.7 million in the November and December 1999 billing
cycles.
Because of the implementation issues associated with the new billing
system, the Company estimated retail gas and electric revenues through July
1999. Beginning with August 1999, the Company was able to determine actual
revenues for all prior periods affected and began reconciling with previously
estimated revenues. In December 1999, the Company completed its reconciliation
of system revenues. As a result, 1999 revenues represented actual revenues as
determined by the new billing system. The resulting reconciliation did not
materially impact recorded revenues. However, a significant number of individual
accounts required corrections.
F-36
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(11) Commitments and Contingencies (Continued)
As a result of the delay of normal collection activities, the Company
incurred a significant increase in delinquent accounts, many of which occurred
with customers that no longer have active accounts with the Company. As a
result, the Company significantly increased its estimated bad debt costs
throughout 1999.
The Company continued its analysis and collection efforts of its
delinquent accounts resulting from the problems associated with the
implementation of the new customer billing system throughout 2000 and identified
additional bad debt exposure. By the end of 2000, the Company completed its
analysis of its delinquent accounts and resumed its normal collection
procedures. As a result, the Company has determined that $13.5 million of
customer receivables will not be collectible. Based upon information available
at December 31, 2000, the Company believes the allowance for doubtful accounts
of $9.0 million is adequate for management's estimate of potential uncollectible
accounts.
In addition, due to the significantly higher natural gas prices
experienced in November and December 2000, the Company increased its bad debt
expense by approximately $2 million in anticipation of higher than normal
delinquency rates. The Company expects this trend to continue as long as natural
gas prices remain higher than in the past years.
The following is a summary of the allowance for doubtful accounts during
2000, 1999 and 1998:
2000 1999 1998
--------- --------- ----------
(In thousands)
Allowance for doubtful accounts, beginning
of year....................................... $12,504 $ 836 $ 783
Bad debt accrual................................ 9,980 11,496 3,325
Less: Write off (adjustments) of
uncollectible accounts........................ 13,521 (172) 3,272
--------- --------- --------
Allowance for doubtful accounts, end of year ... $ 8,963 $12,504 $ 836
========= ========= ========
Electric Rate Case Settlement
On August 25, 1999, the PRC issued an order approving the rate case
settlement resulting from the NMPUC's final order of November 30, 1998. The PRC
ordered the Company to reduce its electric rates by $34.0 million annually
retroactive to July 30, 1999. In addition, the order includes a rate freeze
until electric competition is fully implemented in New Mexico or until January
1, 2003 whichever is earlier. The settlement reduced revenues by approximately
$39 million and $19 million in 2000 and 1999, respectively.
F-37
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(11) Commitments and Contingencies (Continued)
Gas Rate Orders
On October 24, 2000, the PRC issued a final order approving a stipulation
negotiated in the third quarter between the Company and the PRC staff which
resolved all issues raised by the two remanded gas rate cases. The final order
adds approximately $1.2 million to the Company's revenues in the final quarter
of 2000, $4.7 million in 2001, and $3.9 million in 2002. The Company has
reversed certain reserves against costs recovered in the settlement that were
recorded against earnings at the time of the original regulatory orders,
resulting in a one-time pre-tax gain of $4.6 million. This amount will be
collected from customers in rates over the next 12 years.
Nuclear Decommissioning Trust
In 1998, the Company and the trustee of the Company's master
decommissioning trust sued several companies and individuals, in State District
Court in Santa Fe County, for the under-performance of a corporate owned life
insurance program. The program was used to fund a portion of the Company's
nuclear decommissioning obligations for its 10.2% interest in PVNGS.
The parties reached a settlement agreement under which all claims were
dismissed with prejudice on September 5, 2000 and the Company and trustee
received $13.8 million in settlement proceeds.
PVNGS Liability and Insurance Matters
The PVNGS participants have insurance for public liability resulting from
nuclear energy hazards to the full limit of liability under Federal law. This
potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the primary liability insurance
limit, the Company could be assessed retrospective adjustments. The maximum
assessment per reactor under the program for each nuclear incident is
approximately $88 million, subject to an annual limit of $10 million per reactor
per incident. Based upon the Company's 10.2% interest in the three PVNGS units,
the Company's maximum potential assessment per incident for all three units is
approximately $27.0 million, with an annual payment limitation of $3 million per
incident. If the funds provided by this retrospective assessment program prove
to be insufficient, Congress could impose revenue raising measures on the
nuclear industry to pay claims. The United States Nuclear Regulatory Commission
and Congress are reviewing the related laws. The Company cannot predict whether
or not Congress will change the law. However, certain changes could possibly
trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by
the lessors.
F-38
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(11) Commitments and Contingencies (Continued)
The PVNGS participants maintain "all-risk" (including nuclear hazards)
insurance for nuclear property damage to, and decontamination of, property at
PVNGS in the aggregate amount of $2.75 billion as of January 1, 2001. The
Company is a member of an industry mutual insurer which provides both the
"all-risk" and increased cost of generation insurance to the Company. In the
event of adverse losses experienced by this insurer, the Company is subject to
an assessment. The Company's maximum share of any assessment is approximately
$2.3 million per year.
PVNGS Decommissioning Funding
The Company has a program for funding its share of decommissioning costs
for PVNGS. The nuclear decommissioning funding program is invested in equities
and fixed income instruments in qualified and non-qualified trusts. The results
of the 1998 decommissioning cost study indicated that the Company's share of the
PVNGS decommissioning costs excluding spent fuel disposal will be approximately
$171.3 million (in 2000 dollars).
The Company funded an additional $3.9 million, $3.1 million and $3.0
million in 2000, 1999 and 1998, respectively, into the qualified and
non-qualified trust funds. The estimated market value of the trusts at the end
of 2000 was approximately $55 million.
Nuclear Spent Fuel and Waste Disposal
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the
"Waste Act"), the United States Department of Energy ("DOE") is obligated to
accept and dispose of all spent nuclear fuel and other high-level radioactive
wastes generated by all domestic power reactors. Under the Waste Act, DOE was to
develop the facilities necessary for the storage and disposal of spent nuclear
fuel and to have the first such facility in operation by 1998. DOE has announced
that such a repository now cannot be completed before 2010.
The operator of PVNGS has capacity in existing fuel storage pools at
PVNGS which, with certain modifications, could accommodate all fuel expected to
be discharged from normal operation of PVNGS through 2002, and believes it could
augment that storage with the new facilities for on-site dry storage of spent
fuel for an indeterminate period of operation beyond 2002, subject to obtaining
any required governmental approvals. The Company currently estimates that it
will incur approximately $41.0 million (in 1998 dollars) over the life of PVNGS
for its share of the fuel costs related to the on-site interim storage of spent
nuclear fuel during the operating life of the plant. The Company accrues these
costs as a component of fuel expense, meaning the charges are accrued as the
fuel is burned. In 1998, the Company expensed $12.1 million for on-site interim
nuclear storage costs related to nuclear fuel burned prior to 1998. In 2000, the
Company expensed approximately $1.0 million for on-site interim nuclear fuel
storage costs related to nuclear fuel burned during 2000. The operator of PVNGS
currently believes that spent fuel storage or disposal methods will be available
for use by PVNGS to allow its continued operation beyond 2002.
F-39
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(11) Commitments and Contingencies (Continued)
Other
There are various claims and lawsuits pending against the Company and
certain of its subsidiaries. The Company is also subject to Federal, state and
local environmental laws and regulations, and is currently participating in the
investigation and remediation of numerous sites. In addition, the Company
periodically enters into financial commitments in connection with business
operations. It is not possible at this time for the Company to determine fully
the effect of all litigation on its consolidated financial statements. However,
the Company has recorded a liability where the litigation effects can be
estimated and where an outcome is considered probable. The Company does not
expect that any known lawsuits, environmental costs and commitments will have a
material adverse effect on its financial condition or results of operations.
(12) Environmental Issues
The normal course of operations of the Company necessarily involves
activities and substances that expose the Company to potential liabilities under
laws and regulations protecting the environment. Liabilities under these laws
and regulations can be material and in some instances may be imposed without
regard to fault, or may be imposed for past acts, even though the past acts may
have been lawful at the time they occurred. Sources of potential environmental
liabilities include the Federal Comprehensive Environmental Response
Compensation and Liability Act of 1980 and other similar statutes.
The Company records its environmental liabilities when site assessments
or remedial actions are probable and a range of reasonably likely cleanup costs
can be estimated. The Company reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified
site using currently available information, including existing technology,
presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless
there is a probable amount, the Company, records the lower end of this
reasonably likely range of costs (classified as other long-term liabilities at
undiscounted amounts).
The Company's recorded estimated minimum liability to remediate its
identified sites is $6.8 million. The ultimate cost to clean up the Company's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature
of contamination; the scarcity of reliable data for identified sites; and the
time periods over which site remediation is expected to occur. The Company
believes that, due to these uncertainties, it is remotely possible that cleanup
costs could exceed its recorded liability by up to $11.6 million. The upper
limit of this range of costs was estimated using assumptions least favorable to
the Company.
F-40
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(12) Environmental Issues (Continued)
Remediation of identified sites previously used in operations, used by
tenants or contaminated by former owners required spending of $1.6 million in
2000 and $4.4 million in 1999. In 2001, the Company anticipates spending $0.7
million for remediation and $1.4 million for control and prevention. The
majority of the December 31, 2000 environmental liability is expected to be paid
over the next five years, funded by cash generated from operations. Future
environmental obligations are not expected to have a material impact on the
results of operations or financial condition of the Company.
(13) Discontinued Operations
On August 4, 1998, the Company adopted a plan to discontinue the gas
trading operations of its Energy Services Business Unit. Accordingly, the gas
marketing operations of its Energy Services Business Unit are reported as
discontinued operations. Estimated losses on the disposal of the gas marketing
segment were $5.1 million (net of income tax benefit of $3.3 million), which
includes a provision for anticipated operating losses prior to disposal.
Operating losses of the discontinued operations prior to the date of
discontinuation were $7.3 million in 1998. This amount includes income tax
benefits related to the losses from discontinued operations of $4.8 million in
1998. Total sales from the discontinued operations was $159.2 million in 1998.
Prior to the decision to discontinue non-utility operations, such total sales
and income tax benefits were included in operating revenues and operating
expenses in the consolidated statement of earnings.
(14) Proposed Acquisition
On November 9, 2000 the Company and Western Resources, Inc. (Western
Resources) announced that both companies' boards of directors approved an
agreement under which the Company will acquire the Western Resources electric
utility operations in a tax-free, stock-for-stock transaction.
Under the terms of the agreement, the Company and Western Resources,
whose utility operations consist of its Kansas Power and Light division and
Kansas Gas and Electric subsidiary, will both become subsidiaries of a new
holding company to be named at a future date. Prior to the consummation of this
combination, Western Resources will reorganize all of its non-utility assets,
including its 85 percent stake in Protection One and its 45 percent investment
in ONEOK, into Westar Industries which will be spun off to Western Resources'
shareholder, prior to the acquisition of Western's utility assets by the
Company.
The new holding company will issue 55 million of its shares, subject to
adjustment, to Western Resources' shareholders and Westar Industries. Before any
adjustments, the new company will have approximately 94 million shares
outstanding, of which approximately 41 percent will be owned by former Company
shareholders and 59 percent will be owned by former Western Resources
shareholders and Westar Industries.
F-41
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(14) Proposed Acquisition (Continued)
Based on the Company's average closing price over the last ten days prior
to the announcement of $27.325 per share, the indicated equity consideration of
the transaction is approximately $1.50 billion, including conversion of the
Westar Industries obligation. Approximately $2.93 billion of existing Western
Resources debt, giving the transaction an aggregate enterprise value of
approximately $4.44 billion. The Company plans to reduce and refinance a portion
of the Western Resources debt. The new holding company will have a total
enterprise value of approximately $6.5 billion ($2.6 billion in equity; $3.9
billion in debt and preferred stock).
The transaction will be accounted for as a reverse acquisition by the
Company as Western Resources shareholders will receive the majority of the
voting interests in the new holding company. For accounting purposes Western
Resources will be treated as the acquiring entity. Accordingly, all of the
assets and liabilities of the Company will be recorded at fair value in the
business combination as required by the purchase method of accounting. In
addition, the operations of the Company will be reflected in the reported
results of the combined company only from the date of acquisition.
In the transaction, each Company share will be exchanged on a one-for-one
basis for shares in the new holding company. Each Western Resources share will
be exchanged for a fraction of a share of the new company. This exchange ratio
will be finalized at closing, depending on the impact of certain adjustments to
the transaction consideration. Since Western Resources and Westar Industries
remain committed to reducing Western Resources' net debt balance prior to
consummation of the transaction, they have agreed with the Company on a
mechanism to adjust the transaction consideration based on additional equity
contributions. Under this mechanism, Western Resources could undertake certain
activities not affecting the utility operations to reduce the net debt balance
of the utility. The effect of such activities would be to increase the number of
new holding company shares to be issued to all Western Resources shareholders
(including Westar Industries) in the transaction. In addition, Westar Industries
has the option of making additional equity infusions into Western Resources that
will be used to reduce the utility's net debt balance prior to closing. Up to
$407 million of such equity infusions may be used to purchase additional new
holding company common and convertible preferred stock.
The successful spin-off of Westar Industries from Western Resources is
required prior to the consummation of the transaction. The transaction is also
conditioned upon, among other things, approvals from both companies'
shareholders and customary regulatory approvals from the Kansas Corporation
Commission, the New Mexico Public Regulation Commission, the Federal Energy
Regulatory Commission, the Nuclear Regulatory Commission, and the Department of
Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The new
holding company expects to register as a holding company with the Securities and
Exchange Commission under the Public Utility Holding Company Act of 1935.
Management believes that the above mentioned approvals are expected to be
obtained over the next 12 to 18 months, however should such approvals not to be
obtained, final consummation of the proposed acquisition cannot occur.
F-42
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(15) New and Proposed Accounting Standards
Decommissioning: The Staff of the Securities and Exchange Commission
("SEC") has questioned certain of the current accounting practices of the
electric industry regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in financial statements of
electric utilities. In February 2000, the Financial Accounting Standards Board
("FASB") issued an exposure draft regarding Accounting for Obligations
Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The
Exposure Draft requires the recognition of a liability for an asset retirement
obligation at fair value. In addition, present value techniques used to
calculate the liability must use a credit adjusted risk-free rate. Subsequent
remeasures of the liability would be recognized using an allocation approach.
The Company has not yet determined the impact of the Exposure Draft.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities, ("SFAS 133"): SFAS 133
establishes accounting and reporting standards requiring derivative instruments
to be recorded in the balance sheet as either an asset or liability measured at
its fair value. SFAS 133 also requires that changes in the derivatives' fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows derivative
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. In June
1999, FASB issued SFAS 137 to amend the effective date for the compliance of
SFAS 133 to January 1, 2001. In June 2000, the FASB issued SFAS 138 that
provides certain amendments to SFAS 133. The amendments, among other things,
expand the normal sales and purchases exception to contracts that implicitly or
explicitly permit net settlement and contracts that have a market mechanism to
facilitate net settlement. The expanded exception excludes a significant portion
of the Company's contracts that previously would have required valuation under
SFAS 133. Effective January 1, 2001, the Company adopted SFAS 133, as amended.
The Company has identified all financial instruments that meet the
definition of a derivative under SFAS 133, as amended, currently existing in the
Company. Certain of the Company's identified derivative instruments are
currently marked-to-market under EITF 98-10. The related gains and losses
(unrealized and realized) for these derivative instruments are recorded as
adjustments to operating revenues.
In addition, the financial instruments underlying the Company's corporate
hedge of certain investments in its nuclear executive retirement and retiree
medical benefits trusts meet the definition of a derivative under SFAS 133, as
amended, and are currently marked to market. The related unrealized and realized
losses are recorded as a component of other income and deductions on the
Consolidated Statement of Earnings. The Company designated certain forward
purchase contracts for electricity as cash flow hedges. The Company's designated
cash flow hedges at January 1, 2001, were forward purchase contracts for the
purchase of electric power for forecasted jurisdictional use during planned
outages in 2001. The hedged risks associated with these instruments are the
changes in cash flows related to forecasted purchase of electricity due to
changes in the price of electricity on the spot market. Assessment of hedge
effectiveness will be based on the changes in the forward price of electricity.
F-43
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2000, 1999 and 1998
(15) New and Proposed Accounting Standards (Continued)
SFAS 133, as amended, provides that the effective portion of the gain or
loss on a derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period or periods during which the hedged
forecasted transaction affects earnings. The results of hedge ineffectiveness
and the change in fair value of a derivative that an entity has chosen to
exclude from hedge effectiveness are required to be presented in current
earnings.
Because the Company's derivative instruments as defined by SFAS 133, as
amended, are currently marked to market or are classified as cash flow hedges,
the adoption of SFAS 133, as amended, will not have an impact on the net
earnings of the Company. However, the adoption of SFAS 133, as amended, will
increase comprehensive income by $6.0 million, net of taxes. The physical
contracts will subsequently be recognized as a component of the cost of
purchased power when the actual physical delivery occurs. At January 1, 2001,
the derivative instruments designated as cash flow hedges had a gross asset
position of $9.9 million on the hedged transactions. See Note 5 for financial
instruments currently marked-to-market.
F-44
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
QUARTERLY OPERATING RESULTS
The unaudited operating results by quarters for 2000 and 1999 are as follows:
Quarter Ended
----------------------------------------------------
March 31 June 30 September 30 December 31
---------- ----------- ------------ -----------
(In thousands, except per share amounts)
2000:
Operating Revenues.......................... $ 321,291 $ 329,041 $ 499,477 $ 461,465
Operating Income............................ 30,947 27,654 47,452 26,422
Earnings from Continuing Operations......... 21,952 17,986 46,913 14,096
Net Earnings (1)............................ 21,952 17,986 46,913 14,096
Net Earnings per share from Continuing
Operations............................... 0.55 0.45 1.19 0.36
Net Earnings per Share (Basic).............. 0.55 0.45 1.19 0.36
Net Earnings per Share (Diluted)............ 0.55 0.45 1.18 0.35
1999:
Operating Revenues.......................... $ 272,818 $ 261,371 $ 340,604 $ 282,750
Operating Income............................ 35,068 29,247 30,275 25,489
Earnings from Continuing Operations......... 23,130 18,172 21,401 16,911
Net Earnings................................ 26,671 18,172 21,401 16,911
Net Earnings per share from Continuing
Operations............................... 0.55 0.44 0.52 0.41
Net Earnings per Share (Basic).............. 0.64 0.44 0.52 0.41
Net Earnings per Share (Diluted)............ 0.63 0.44 0.52 0.41
In the opinion of management of the Company, all adjustments
(consisting of normal recurring accruals) necessary for a fair statement of the
results of operations for such periods have been included.
- -------------------
(1) Effective January 1, 1999, the Company adopted EITF Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. The effect of the initial application of EITF Issue No.
98-10 was reported as a cumulative effect of a change in accounting
principle which increased the Company's consolidated net income by
approximately $3.5 million (after related income tax expense of
approximately $2.3 million), or $.08 per common share.
F-45
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------
Utility Operations Sales:
Energy Sales--KWh (in thousands):
Residential............................... 2,163,036 2,027,099 2,007,852 1,976,434 1,892,290
Commercial................................ 3,121,141 2,980,935 2,888,539 2,841,831 2,698,087
Industrial................................ 1,544,367 1,559,155 1,571,824 1,556,264 1,505,801
Other ultimate customers.................. 260,399 236,394 271,659 160,370 310,118
----------- ----------- ----------- ----------- -----------
Total KWh sales......................... 7,088,943 6,803,583 6,739,874 6,534,899 6,406,296
=========== =========== =========== =========== ===========
Gas Throughput--Decatherms (in thousands):
Residential............................... 28,818 32,060 29,282 30,608 28,409
Commercial................................ 9,890 10,845 10,135 10,606 9,574
Industrial................................ 5,033 2,380 1,538 1,278 2,151
Other..................................... 6,392 6,818 8,290 8,143 12,952
----------- ----------- ----------- ----------- -----------
Total gas sales......................... 50,133 52,103 49,245 50,635 53,086
Transportation throughput................. 44,871 40,161 36,413 33,975 47,010
----------- ----------- ----------- ----------- -----------
Total gas throughput.................... 95,004 92,264 85,658 84,610 100,096
=========== =========== =========== =========== ===========
Revenues (in thousands):
Residential............................... $ 185,436 $ 184,088 $ 187,681 $ 184,813 $ 177,220
Commercial................................ 237,350 238,830 241,968 237,629 226,146
Industrial................................ 79,671 85,828 88,644 86,927 83,651
Other ultimate customers.................. 16,208 13,777 18,124 10,135 20,804
----------- ----------- ----------- ----------- -----------
Total revenues to ultimate customers.... 518,665 522,523 536,417 519,504 507,821
Intersegment revenues....................... 707 707 707 - -
Miscellaneous electric revenues............. 20,093 18,345 19,151 3,331 3,115
----------- ----------- ----------- ----------- -----------
Total electric revenues................. $ 539,465 $ 541,575 $ 556,275 $ 522,835 $ 510,936
----------- ----------- ----------- ----------- -----------
Gas Revenues:
Residential............................... $ 191,221 $ 151,954 $ 160,459 $ 185,984 $ 131,858
Commercial................................ 52,959 37,300 42,500 50,094 33,525
Industrial................................ 24,208 8,595 4,876 4,512 5,208
Other..................................... 29,216 20,384 27,148 30,121 29,158
----------- ----------- ----------- ----------- -----------
Revenues from gas sales................... 297,604 218,233 234,983 270,711 199,749
Transportation............................ 14,163 12,390 13,464 14,172 17,215
Other..................................... 8,157 6,088 7,528 9,886 10,337
----------- ----------- ----------- ----------- -----------
Total gas revenues...................... $ 319,924 $ 236,711 $ 255,975 $ 294,769 $ 227,301
----------- ----------- ----------- ----------- -----------
Total Utility Revenues............. $ 859,389 $ 778,286 $ 812,250 $ 817,604 $ 738,237
=========== =========== =========== =========== ===========
Customers at Year End:
Residential............................... 328,519 321,949 319,415 311,314 304,900
Commercial................................ 38,991 38,435 37,652 36,942 36,292
Industrial................................ 371 375 363 363 375
Other ultimate customers.................. 625 625 665 637 632
----------- ----------- ----------- ----------- -----------
Total ultimate customers................ 368,506 361,384 358,095 349,256 342,199
Sales for Resale.......................... 81 83 83 66 56
----------- ----------- ----------- ----------- -----------
Total customers......................... 368,587 361,467 358,178 349,322 342,255
=========== =========== =========== =========== ===========
Gas:
Residential............................... 398,623 390,428 383,292 375,032 367,025
Commercial................................ 32,626 32,116 32,004 31,560 30,757
Industrial................................ 50 51 55 50 54
Other..................................... 3,612 3,688 3,622 3,765 3,541
Transportation............................ 32 32 29 31 36
----------- ----------- ----------- ----------- -----------
Total customers......................... 434,943 426,315 419,002 410,438 401,413
=========== =========== =========== =========== ===========
F-46
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------
Generation and Trading Operations Sales:
Energy Sales--KWh (in thousands):
Firm-requirements wholesale............... 193,853 179,249 278,615 278,727 282,534
Other contracted off-system............... 7,385,266 6,196,499 4,033,931 3,790,081 2,928,321
Economy energy sales...................... 4,773,009 4,795,873 4,469,769 2,716,835 1,364,365
----------- ----------- ----------- ----------- -----------
Total sales to ultimate customers....... 12,352,128 11,171,621 8,782,315 6,785,643 4,575,220
Intersegment sales........................ 7,088,943 6,803,583 6,739,874 6,534,899 6,406,296
----------- ----------- ----------- ----------- -----------
19,441,071 17,975,204 15,522,189 13,320,542 10,981,516
=========== =========== =========== =========== ===========
Revenues (in thousands):
Firm-requirements wholesale............... 6,568 7,046 10,708 10,690 12,359
Other contracted off-system............... 371,900 226,773 142,115 118,876 86,689
Economy energy sales...................... 369,724 131,549 122,156 55,768 22,281
----------- ----------- ----------- ----------- -----------
Total revenues to ultimate customers.... 748,192 365,368 274,979 185,334 121,329
Intersegment revenues..................... 324,744 318,872 362,722 370,019 380,000
Miscellaneous electric revenues........... 2,242 5,741 4,657 14,269 13,374
----------- ----------- ----------- ----------- -----------
Total generation revenues............... $1,075,178 $ 689,981 $ 642,358 $ 569,622 $ 514,703
=========== =========== =========== =========== ===========
Customers at Year End:
Generation 81 83 83 66 56
=========== =========== =========== =========== ===========
Reliable Net Capability--KW................. 1,521,000 1,521,000 1,506,000 1,506,000 1,506,000
Coincidental Peak Demand--KW................ 1,368,000 1,291,000 1,313,000 1,209,000 1,217,000
Average Fuel Cost per Million BTU........... $ 1.3827 $ 1.3169 $ 1.2433 $ 1.2319 $ 1.2735
BTU per KWh of Net Generation............... 10,547 10,490 10,784 10,927 10,768
F-47
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Reference is hereby made to "Election of Directors" in the Company's
Proxy Statement relating to the annual meeting of stockholders to be held on
July 3, 2001 (the "2001 Proxy Statement"), to PART I, SUPPLEMENTAL ITEM -
"EXECUTIVE OFFICERS OF THE COMPANY" and "Other Matters" - "Section 16(a)
Beneficial Ownership Reporting Compliance" in the 2001 Proxy Statement.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to "Executive Compensation" in the 2001 Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is hereby made to "Voting Information", "Election of Directors"
and "Stock Ownership of Certain Executive Officers" in the 2001 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to the 2001 Proxy Statement for such disclosure,
if any, as may be required by this item.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K
(a) - 1. See Index to Financial Statements under Item 8.
(a) - 2. Financial Statement Schedules for the years 2000, 1999, and
and 1998 are omitted for the reason that they are not
required or the information is otherwise supplied.
(a) - 3-A. Exhibits Filed:
Exhibit No. Description
- ----------- -----------
10.8.9 Amendment No. 14 to the Arizona Nuclear Power Project Participation
Agreement effective June 20, 2000.
10.9.7 Underground Letter Agreement dated August 31, 2000, among San Juan
Coal Company, San Juan Transportation Company, the Company, and
Tucson Electric Power Company (confidentiality treatment was
requested as to portions of this exhibit, and such portions were
omitted from the exhibit filed and were filed separately with the
Securities and Exchange Commission).
10.43 2001 Officer Incentive Plan effective January 1, 2001
E-1
Exhibit No. Description
- ----------- -----------
10.74.2 Second Amendment to the Third Restated and Amended Public Service
Company of New Mexico Performance Stock Plan, effective December 7,
1998.
10.74.3 Third Amendment to the Third Restated and Amended Public Service
Company of New Mexico Performance Stock Plan, effective December 10,
2000.
23.1 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
(a) - 3-B. Exhibits Incorporated By Reference:
In addition to those Exhibits shown above, the Company hereby
incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and
Regulation S-K section 10, paragraph (d) by reference to the filings set forth
below:
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
Articles of Incorporation and By-laws
3.1 Restated Articles of Incorporation of the 4-(b) to Registration Statement 2-99990
Company, as amended through May 10, No. 2-99990 of the Company.
1985.
3.2 By-laws of Public Service Company of 3.2 to Annual Report of the 1-6986
New Mexico With All Amendments to Registrant on Form 10-K for
and including February 8, 2000 the fiscal year ended
December 31, 1999
Instruments Defining the Rights of Security Holders, Including Indentures
4.1 Indenture of Mortgage and Deed of 4-(d) to Registration Statement 2-99990
Trust dated as of June 1, 1947, between No. 2-99990 of the Company.
the Company and The Bank of New York (formerly
Irving Trust Company), as Trustee, together
with the Ninth Supplemental Indenture dated as
of January 1, 1967, the Twelfth Supplemental
Indenture dated as of September 15, 1971, the
Fourteenth Supplemental Indenture dated as of
December 1, 1974 and the Twenty- Second
Supplemental Indenture dated as of October 1,
1979 thereto relating to First Mortgage Bonds
of the Company.
E-2
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
4.2 Portions of sixteen supplemental 4-(e) to Registration Statement 2-99990
Indentures to the Indenture of Mortgage No. 2-99990 of the Company.
and Deed of Trust dated as of June 1,
1947, between the Company and The Bank of New
York (formerly Irving Trust Company), as
Trustee, relevant to the declaration or
payment of dividends or the making of other
distributions on or the purchase by the
Company of shares of the Company's Common
Stock.
4.3 Fifty-third Supplemental Indenture, dated 4.3 to the Company's Quarterly 1-6986
as of March 11, 1998, supplemental to Report on Form 10-Q for the
Indenture of Mortgage and Deed of Trust, quarter ended March 31, 1998.
dated as of June 1, 1947, between the
Company and The Bank of New York
(formerly Irving Trust Company), as
trustee.
4.4 Indenture (for Senior Notes), dated as of 4.4 to the Company's 1-6986
March 11, 1998, between the Company and The Quarterly Report on Form
Chase Manhattan Bank, as Trustee. 10-Q for the quarter ended March
31, 1998.
4.5 First Supplemental Indenture, dated as 4.5 to the Company's 1-6986
of March 11, 1998, supplemental to Quarterly Report on Form
Indenture, dated as of March 11, 1998, 10-Q for the quarter ended March
Between the Company and The Chase 31, 1998.
Manhattan Bank, as Trustee.
4.6 Second Supplemental Indenture, dated 4.6 to the Company's Quarterly 1-6986
as of March 11, 1998, supplemental to Report on Form
Indenture, dated as of March 11, 1998, 10-Q for the quarter ended March
Between the Company and The Chase 31, 1998.
Manhattan Bank, as Trustee.
4.7 Indenture (for Senior Notes), dated as of 4.1 to Registration 33-53367
August 1, 1998, between the Company Statement No. 33-53367 of the
and The Chase Manhattan Bank, as Company.
Trustee.
E-3
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
4.8 First Supplemental Indenture, dated 4.3 to the Company's 1-6986
August 1, 1998, supplemental to Current Report on Form 8-K
Indenture, dated as of August 1, dated August 7, 1998.
1998, between the Company and the
Chase Manhattan Bank, as Trustee.
Material Contracts
10.1 Supplemental Indenture of Lease dated as 4-D to Registration Statement No. 2-26116
of July 19, 1966 between the Company 2-26116 of the Company.
and other participants in the Four Corners
Project and the Navajo Indian Tribal
Council.
10.1.1 Amendment and Supplement No. 1 to 10.1.1 to Annual Report of the 1-6986
Supplemental and Additional Indenture of Registrant on Form 10-K for fiscal
Lease dated April 25, 1985 between the year ended December 31, 1995.
Navajo Tribe of Indians and Arizona
Public Service Company, El Paso Electric
Company, Public Service Company of
New Mexico, Salt River Project
Agricultural Improvement and Power
District, Southern California Edison
Company, and Tucson Electric Power
Company (refiled).
10.2 Fuel Agreement, as supplemented, dated 4-H to Registration Statement No. 2-35042
as of September 1, 1966 between Utah 2-35042 of the Company.
Construction & Mining Co. and the
participants in the Four Corners Project
including the Company.
10.3 Fourth Supplement to Four Corners Fuel 10.3 to Annual Report of the 1-6986
Agreement No. 2 effective as of January Registrant on Form 10-K for fiscal
1, 1981, between Utah International Inc. year ended December 31, 1991.
and the participants in the Four Corners
Project, including the Company.
10.4 Contract between the United States and 5-L to Registration Statement No. 2-41010
the Company dated April 11, 1968, for 2-41010 of the Company.
furnishing water.
10.4.1 Amendatory Contract between the United 5-R to Registration Statement No. 2-60021
States and the Company dated September 2-60021 of the Company.
29, 1977, for furnishing water.
E-4
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.8 Arizona Nuclear Power Project 5-T to Registration Statement 2-50338
Participation Agreement among the No. 2-50338 of the Company.
Company and Arizona Public Service
Company, Salt River Project Agricultural
Improvement and Power District, Tucson
Gas & Electric Company and El Paso
Electric Company, dated August 23, 1973.
10.8.1 Amendments No. 1 through No. 6 to 10.8.1 to Annual Report of the 1-6986
Arizona Nuclear Power Project Registrant on Form 10-K for
Participation Agreement. fiscal year ended December 31,
1991.
10.8.2 Amendment No. 7 effective April 1, 10.8.2 to Annual Report of the 1-6986
1982, to the Arizona Nuclear Power Registrant on Form 10-K for
Project Participation Agreement (refiled). fiscal year ended December 31,
1991.
10.8.3 Amendment No. 8 effective September 12, 10.58 to Annual Report of the 1-6986
1983, to the Arizona Nuclear Power Registrant on Form 10-K for
Project Participation Agreement (refiled). fiscal year ended December 31,
1993.
10.8.4 Amendment No. 9 to Arizona Nuclear 10.8.4 to Annual Report of the 1-6986
Power Project Participation Agreement Registrant on Form 10-K for
dated as of June 12, 1984 (refiled). fiscal year ended December 31,
1994.
10.8.5 Amendment No. 10 dated as of November 10.8.5 to Annual Report of the 1-6986
21, 1985 and Amendment No. 11 dated as Registrant on Form 10-K for
of June 13, 1986 and effective January 10, fiscal year ended December 31,
1987 to Arizona Nuclear Power Project 1994.
Participation Agreement (refiled).
10.8.7 Amendment No. 12 to Arizona Nuclear 19.1 to the Company's Quarterly 1-6986
Power Project Participation Agreement Report on Form 10-Q for the
dated June 14, 1988, and effective quarter ended September 30, 1990.
August 5, 1988.
10.8.8 Amendment No. 13 to the Arizona 10.8.10 to Annual Report of 1-6986
Nuclear Power Project Participation Registrant on Form 10-K for the
Agreement dated April 4, 1990, and fiscal year ended December 31,
effective June 15, 1991. 1990.
10.9 Coal Sales Agreement executed August 18, 10.9 to Annual Report of the 1-6986
1980 among San Juan Coal Company, Registrant on Form 10-K for
the Company and Tucson Electric fiscal year ended December 31,
Power Company, together with 1991.
Amendments No. One, Two, Four, and
Six thereto.
E-5
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.9.1 Amendment No. Three to Coal Sales 10.9.1 to Annual Report of the 1-6986
Agreement dated April 30, 1984 among Registrant on Form 10-K for
San Juan Coal Company, the Company fiscal year ended December 31,
and Tucson Electric Power Company. 1994 (confidentiality treatment
was requested at the time of
filing the Annual Report of the
Registrant on Form 10-K for
fiscal year ended December 31,
1984; exhibit was not filed
therewith based on the same
confidentiality request).
10.9.2 Amendment No. Five to Coal Sales 10.9.2 to Annual Report of the 1-6986
Agreement dated May 29, 1990 among Registrant on Form 10-K for
San Juan Coal Company, the Company fiscal year ended December 31,
and Tucson Electric Power Company. 1991 (confidentiality treatment
was requested as to portions of
this exhibit, and such portions
were omitted from the exhibit
filed and were filed separately
with the Securities and Exchange
Commission).
10.9.3 Amendment No. Seven to Coal Sales 19.3 to the Company's Quarterly 1-6986
Agreement, dated as of July 27, 1992 Report on Form 10-Q for the
among San Juan Coal Company, the quarter ended September 30, 1992
Company and Tucson Electric Power (confidentiality treatment was
Company. requested as to portions of this
exhibit, and such portions were
omitted from the exhibit filed
and were filed separately with
the Securities and Exchange
Commission).
E-6
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.9.4 First Supplement to Coal Sales 19.4 to the Company's Quarterly 1-6986
Agreement, dated July 27, 1992 among Report on Form 10-Q for the
San Juan Coal Company, the Company quarter ended September 30, 1992
and Tucson Electric Power Company. (confidentiality treatment was
requested as to portions of this
exhibit, and such portions were
omitted from the exhibit as of
filed and were filed separately
with the Securities and Exchange
Commission).
10.9.5 Amendment No. Eight to Coal Sales 10.9.5 to Annual Report of the 1-6986
Agreement, dated as of September 1, Registrant on Form 10-K for
1995, among San Juan Coal Company, fiscal year ended December 31,
the Company and Tucson Electric 1995.
Power Company .
10.9.6 Amendment No. Nine to Coal Sales 10.9.6 to Annual Report of the 1-6986
Agreement, dated as of December 31, 1995, Registrant on Form 10-K for
among San Juan Coal Company, the Company fiscal year ended December 31,
and Tucson Electric Power Company. 1996.
10.11 San Juan Unit 4 Early Purchase and 10.11 to the Company's Quarterly 1-6986
Participation Agreement dated as of Report on Form 10-Q for the
September 26, 1983 between the quarter ended March 31, 1994.
Company and M-S-R Public Power
Agency, and Modification No. 2 to the
San Juan Project Agreements dated
December 31, 1983 (refiled).
10.11.1 Amendment No. 1 to the Early Purchase 10.11.1 to Annual Report of the 1-6986
and Participation Agreement between Registrant on Form 10-K for
Public Service Company of New Mexico fiscal year ended December 31,
and M-S-R Public Power Agency, 1997.
executed as of December 16, 1987, for
San Juan Unit 4 (refiled).
10.11.3 Amendment No. 3 to the San Juan Unit 10.11.3 to Annual Report of 1-6986
4 Early Purchase and Participation the Registrant on Form 10-K
Agreement between Public Service for fiscal year ended
Company of New Mexico and M-S-R December 31, 1999.
Public Power Agency, dated as of
October 27, 1999.
E-7
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.12 Amended and Restated San Juan Unit 4 10.12 to Annual Report of the 1-6986
Purchase and Participation Agreement Registrant on Form 10-K for
dated as of December 28, 1984 between fiscal year ended December
the Company and the Incorporated County 31, 1994.
of Los Alamos (refiled).
10.12.1 Amendment No. 1 to the Amended and 10.12.1 to Annual Report of 1-6986
Restated San Juan Unit 4 Purchase and the Registrant on Form 10-K
Participation Agreement between Public for fiscal year ended
Service Company of New Mexico and December 31, 1999.
M-S-R Public Power Agency, dated as of
October 27, 1999.
10.13 Amendment No. 2 to the San Juan 10.13 to Annual Report of 1-6986
Unit 4 Purchase Agreement and the Registrant on Form 10-K
Participation Agreement between for fiscal year ended
Public Service Company of New December 31, 1999.
Mexico and The Incorporated County
of Los Alamos, New Mexico, dated
October 27, 1999.
10.14 Participation Agreement among the 10.14 to Annual Report of the 1-6986
Company, Tucson Electric Power Registrant on Form 10-K for
Company and certain financial institutions fiscal year ended December 31,
relating to the San Juan Coal Trust dated 1992.
as of December 31, 1981 (refiled).
10.16 Interconnection Agreement dated 10.16 to Annual Report of the 1-6986
November 23, 1982, between the Registrant on Form 10-K for
Company and Southwestern Public fiscal year ended December 31,
Service Company (refiled). 1992.
10.18* Facility Lease dated as of December 16, 10.18 to Annual Report of the 1-6986
1985 between The First National Bank Registrant on Form 10-K for
of Boston, as Owner Trustee, and Public fiscal year ended December 31,
Service Company of New Mexico 1995.
together with Amendments No. 1, 2 and 3
thereto (refiled).
10.18.4* Amendment No. 4 dated as of March 8, 10.18.4 to the Company's 1-6986
1995, to Facility Lease between Public Quarter Report on Form
Service Company of New Mexico and 10-Q for the quarter ended March
the First National Bank of Boston, dated 31, 1995.
as of December 16, 1985.
10.19 Facility Lease dated as of July 31, 1986, 10.19 to Annual Report of the 1-6986
between the First National Bank of Registrant on Form 10-K for
Boston, as Owner Trustee, and Public fiscal year ended December 31,
Service Company of New Mexico 1996.
together with Amendments No. 1, 2 and 3
thereto (refiled).
E-8
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.20* Facility Lease dated as of August 12, 10.20 to Annual Report of the 1-6986
1986, between The First National Bank Registrant on Form 10-K for
of Boston, as Owner Trustee, and Public fiscal year ended December 31,
Service Company of New Mexico 1996.
together with Amendments No. 1 and 2
thereto (refiled).
10.20.2 Amendment No. 2 dated as of April 10, 1987 to 10.20.2 to Annual Report of the 1-6986
Facility Lease dated as of August 12, 1986, Registrant on Form 10-K for
as amended, between The First National Bank fiscal year ended December 31,
of Boston, not in its individual capacity, 1998.
but solely as Owner Trustee under a Trust
Agreement, dated as of August 12, 1986,
with MFS Leasing Corp., Lessor and Public
Service Company of New Mexico, Lessee
(refiled)
10.20.3 Amendment No. 3 dated as of March 8, 10.20.3 to the Company's 1-6986
1995, to Facility Lease between Public Quarterly Report on Form
Service Company of New Mexico and 10-Q for the quarter ended March
the First National Bank of Boston, 31, 1995.
dated as of August 12, 1986.
10.21 Facility Lease dated as of December 15, 10.21 to Annual Report of the 1-6986
1986, between The First National Bank Registrant on Form 10-K for
of Boston, as Owner Trustee, and Public fiscal year ended December 31,
Service Company of New Mexico (Unit 1 1996.
Transaction) together with Amendment No. 1
thereto (refiled).
10.22 Facility Lease dated as of December 15, 10.22 to Annual Report of the 1-6986
1986, between The First National Bank Registrant on Form 10-K for
of Boston, as Owner Trustee, and Public fiscal year ended December 31,
Service Company of New Mexico 1996.
Unit 2 Transaction) together with
Amendment No. 1 thereto (refiled).
10.23** Restated and Amended Public Service Company of 10.23 to Annual Report of the 1-6986
New Mexico Accelerated Management Performance Registrant on Form 10-K for
Plan (1988) (August 16, 1988) (refiled). fiscal year ended December 31,
1998.
10.23.1** First Amendment to Restated and Amended Public 10.23.1 to Annual Report of the 1-6986
Service Company of Registrant on Form 10-K for
New Mexico Accelerated Management Performance fiscal year ended December 31,
Plan (1988) (August 30, 1988) (refiled). 1998.
E-9
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.23.2** Second Amendment to Restated and Amended Public 10.23.2 to Annual Report of the 1-6986
Service Company of New Mexico Accelerated Registrant on Form 10-K
Management Performance Plan (1988)(December 29, for fiscal year
1989) (refiled). ended December 31, 1998.
10.23.4** Fourth Amendment to the Restated and Amended 10.23.4 to the Company's 1-6986
Public Service Company of New Mexico Quarterly Report on Form 10-Q
Accelerated Management Performance Plan, as for the quarter ended March 31,
amended effective December 7, 1998 1999.
10.24** Management Life Insurance Plan (July 10.24 to Annual Report of the 1-6986
1985) of the Company (refiled). Registrant on Form 10-K for
fiscal year ended December 31,
1995.
10.25.1** Second Restated and Amended Public 10.25.1 to Annual Report for the 1-6986
Service Company of New Mexico Registrant on Form 10-K for
Executive Medical Plan as amended on fiscal year ended December 31,
December 28, 1995. 1997.
10.27 Amendment No. 2 dated as of April 10, 10.53 to Annual Report of the 1-6986
1987, to the Facility Lease dated as of Registrant on Form 10-K for
August 12, 1986, between The First fiscal year ended December 31,
National Bank of Boston, as Owner 1987.
Trustee, and Public Service Company of New
Mexico. (Unit 2 Transaction.) (This is an
amendment to a Facility Lease which is
substantially similar to the Facility Lease
filed as Exhibit 28.1 to the Company's
Current Report on Form 8-K dated August 18,
1986.)
10.32** Supplemental Employee Retirement 10.32 to Annual Report of 1-6986
Agreements dated August 4, 1989, the Registrant on Form 10-K
Between Public Service Company of for fiscal year ended
New Mexico and John R. Ackerman December 31, 1999.
and Max Maerki (refilled).
10.32.1** First Amendment to the Supplemental 10.32.1 to the Company's 1-6986
Employee Retirement Agreement. Quarterly Report on Form 10-Q
for the quarter ended September
30, 1998.
10.32.2** Second Amendment to the Supplemental Employee 10.32.2 to the Company's 1-6986
Retirement Agreement for Max H. Maerki, as Quarterly Report on Form 10-Q
amended effective December 7, 1998 for the quarter ended March 31,
1999.
E-10
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.32.3** First Amendment to the Supplemental Employee 10.32.3 to the Company's 1-6986
Retirement Agreement for John T. Ackerman, as Quarterly Report on Form 10-Q
amended effective December 7, 1998 for the quarter ended March 31,
1999.
10.34 Settlement Agreement between Public 10.48 to Annual Report of the 1-6986
Service Company of New Mexico and Registrant on Form 10-K for
Creditors of Meadows Resources, Inc. fiscal year ended December 31,
dated November 2, 1989. 1989.
10.34.1 First amendment dated April 24, 1992 to 19.1 to the Company's Quarterly 1-6986
the Settlement Agreement dated Report on Form 10-Q for the
November 2, 1989 among Public Service quarter ended September 30, 1992.
Company of New Mexico, the lender
parties thereto and collateral agent.
10.35 Amendment dated April 11, 1991 among 19.1 to the Company's Quarterly 1-6986
Public Service Company of New Mexico, Report on Form 10-Q for the
certain banks and Chemical Bank and quarter ended September 30, 1991.
Citibank, N.A., as agents for the banks.
10.36 San Juan Unit 4 Purchase and 19.2 to the Company's Quarterly 1-6986
Participation Agreement Public Service Report on Form 10-Q for the
Company of New Mexico and the City of quarter ended March 31, 1991.
Anaheim, California dated April 26, 1991.
10.36.1 Amendment No. 1 to the San Juan Unit 10.36.1 to Annual Report of 1-6986
4 Purchase and Participation Agreement the Registrant on Form 10-K for
between Public Service Company of New fiscal year ended
Mexico and The City of Anaheim, December 31, 1999.
California, dated October 27, 1999
10.38 Restated and Amended San Juan Unit 4 10.2.1 to the Company's 1-6986
Purchase and Participation Agreement Quarterly Report on Form 10-Q
between Public Service Company of for the quarter ended September
New Mexico and Utah Associated Municipal 30, 1993.
Power Systems.
10.38.1 Amendment No. 1 to the Restated and 10.38.1 to Annual Report of 1-6986
Amended San Juan Unit 4 Purchase the Registrant on Form 10-K
And Participation Agreement between for fiscal year ended
Public Service Company of New Mexico December 31, 1999.
And Utah Associated Municipal Power
Systems, dated October 27, 1999.
10.40** First Restated and Amended Public Service 99.1 to Registration Statement 333-03303
Company of New Mexico No. 333-03303 filed May 8, 1996.
Director Retainer Plan.
E-11
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.41 Waste Disposal Agreement, dated as of July 27, 19.5 to the Company's Quarterly 1-6986
1992 among San Juan Coal Company, the Company Report on Form 10-Q for the
and Tucson Electric Power Company. quarter ended September 30, 1992
(confidentiality treatment was
requested as to portions of this
exhibit, and such portions were
omitted from the exhibit and were
filed separately with the
Securities and Exchange
Commission).
10.42 Stipulation in the matter of the application 10.42 to Annual Report of the 1-6986
of Gas Company of New Mexico for an Registrant on Form 10-K for
order authorizing recovery of MDL costs fiscal year ended December 31,
through Rate Rider Number 8. 1992.
10.44.2** Second Restated and Amended Non-Union Severance 10.44.2 to the Company's 1-6986
Pay Plan of Public Service Company of New Mexico Quarterly Report on Form 10-Q
dated August 1, 1999 for the quarter ended September
30, 1999.
10.45** Second Amendment to the Public Service Company 10.45 to the Company's Quarterly 1-6986
of New Mexico Service Bonus Plan, as Report on Form 10-Q for the
amended effective December 7, 1998 quarter ended March 31, 1999.
10.47** Compensation Arrangement with Chief 10.3 to the Company's Quarterly 1-6986
Executive Officer, Benjamin F. Montoya Report on Form 10-Q for the
effective June 23, 1993. quarter ended June 30, 1993.
10.47.1** Pension Service Adjustment Agreement 10.3.1 to the Company's 1-6986
for Benjamin F. Montoya. Quarterly Report on Form 10-Q
for the quarter ended September
30, 1993.
10.47.2** Severance Agreement for Benjamin F. 10.3.2 to the Company's 1-6986
Montoya. Quarterly Report on Form 10-Q
for the quarter ended September
30, 1993.
10.47.4** First Amendment to the Pension Service 10.47.4 to the Company's 1-6986
Adjustment Agreement for Benjamin F. Quarterly Report on Form 10-Q
Montoya. for the quarter ended June 30,
1998.
10.47.6** Second Amendment to the Pension Service 10.47.6 to the Company's 1-6986
Adjustment Agreement for Benjamin F. Montoya, as Quarterly Report on Form 10-Q
amended effective December 7, 1998 for the quarter ended March 31,
1999.
E-12
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.48** Public Service Company of New Mexico 10.4 to the Company's Quarterly 1-6986
OBRA `93 Retirement Plan. Report on Form 10-Q for the
quarter ended September 30, 1993.
10.48.1** First Amendment to the Public Service Company of 10.48.1 to the Company's 1-6986
New Mexico OBRA '93 Retirement Plan, as amended Quarterly Report on Form 10-Q
effective December 7, 1998 for the quarter ended March 31,
1999.
10.49** Employment Contract By and Between 10.49 to Annual Report of the 1-6986
Public Service Company of New Mexico and Roger Registrant on Form 10-K for
J. Flynn. fiscal year ended December 31,
1994.
10.50** Public Service Company of New Mexico 10.50 to Annual Report of the 1-6986
Section 415 Plan dated January 1, 1994. Registrant on Form 10-K for
fiscal year ended December 31,
1993.
10.51.2** First Restated and Amended Executive Retention 10.51.2 to the Company's 1-6986
Plan, as amended effective December 7, 1998 Quarterly Report on Form 10-Q
for the quarter ended March 31,
1999.
10.53 January 12, 1994 Stipulation. 10.53 to Annual Report of the 1-6986
Registrant on
Form 10-K for
fiscal year
ended December
31, 1993.
10.54.1** Health Care and Retirement Benefit 10.54.1 to the Company's 1-6986
Agreement By and Between the Public Quarterly Report on Form 10-Q
Service Company of New Mexico and for the quarter ended March 31,
John T. Ackerman dated February 1, 1994. 1994.
10.56.1 Amended and Restated Receivables Purchase 10.56.1 to the Company's 1-6986
Agreement dated May 20, 1996, between Public Quarterly Report on
Service Company of New Mexico, Citibank and Form 10-Q for the
Citicorp North America, Inc. and Amended quarter ended June 30,
Restated Collection Agent Agreement dated 1996.
May 20, 1996, between Public Service Company
of New Mexico, Corporate Receivables
Corporation and Citibank, N.A.
10.59* Amended and Restated Lease dated as of 10.59 to Annual Report of the 1-6986
September 1, 1993, between The First Registrant on Form 10-K for
National Bank of Boston, Lessor, and fiscal year ended December
31, the Company, Lessee (EIP Lease). 1993.
E-13
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.61 Participation Agreement dated as of June 10.61 to Annual Report of the 1-6986
30, 1983 among Security Trust Company, Registrant on Form 10-K for
as Trustee, the Company, Tucson Electric fiscal year ended December 31,
Power Company and certain financial 1993.
institutions relating to the San Juan Coal
Trust (refiled).
10.62 Agreement of the Company pursuant to 10.62 to Annual Report of the 1-6986
Item 601(b)(4)(iii) of Regulation S-K Registrant on Form 10-K for
(refiled). fiscal year ended December 31,
1993.
10.64** Results Pay 10.64 to the Company's Quarterly 1-6986
Report on Form 10-Q for the
quarter ended March 31, 1995.
10.65 Agreement for Contract Operation and 10.64 to the Company's Quarterly 1-6986
Maintenance of the City of Santa Fe Report on Form 10-Q for the
Water Supply Utility System, dated quarter ended June 30, 1995.
July 3, 1995.
10.67 New Mexico Public Service Commission 10.67 to Annual Report of the 1-6986
Order dated July 30, 1987, and Exhibit I Registrant on Form 10-K for
thereto, in NMPUC Case No. 2004, fiscal year ended December 31,
regarding the PVNGS decommissioning 1997.
trust fund (refiled).
10.68 Master Decommissioning Trust Agreement 10.68 to the Company's Quarterly 1-6986
for Palo Verde Nuclear Generating Station Report on Form 10-Q for the
dated March 15, 1996, between Public quarter ended March 31, 1996.
Service Company of New Mexico and
Mellon Bank, N.A.
10.68.1 Amendment Number One to the Master 10.68.1 to Annual Report of the 1-6986
Decommissioning Trust Agreement for Registrant on Form 10-K for
Palo Verde Nuclear Generating Station fiscal year ended December 31,
dated January 27, 1997, between Public 1997.
Service Company of New Mexico and
Mellon Bank, N.A.
10.69* Refunding Agreement No. 3 dated as 10.69 to the Company's 1-6986
of September 27, 1996 between Public Quarterly Report on Form
Service Company of New Mexico, The 10-Q for the quarter ended
Owner Participant named therein, September 30, 1996.
State Street Bank and Trust Company,
as Owner Trustee, The Chase Manhattan,
Bank, as Indenture Trustee, and First PV
Funding Corporation.
E-14
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.72 Revolving Credit Agreement dated as of 10.72 to the Company's Quarterly 1-6986
March 11, 1998, among the Company, Report on Form 10-Q for the
the Chase Manhattan Bank, Citibank, quarter ended March 31, 1998.
N.A., Morgan Guaranty Trust Company
of New York, and Chase Securities, Inc.,
and the Initial Lenders Named Therein.
10.73 Refunding Agreement No. 8A, dated as 10.73 to the Company's Quarterly 1-6986
of December 23, 1997, among the Report on Form 10-Q for the
Company, the Owner Participant Named quarter ended March 31, 1998.
Therein, State Street Bank and Trust
Company, as Owner Trustee, The Chase
Manhattan Bank, as Indenture Trustee,
and First PV Funding Corporation.
10.74** Third Restated and Amended Public 10.74 to the Company's Quarterly 1-6986
Service Company of New Mexico Report on Form 10-Q for the
Performance Stock Plan effective March quarter ended March 31, 1998.
10, 1998.
10.74.1** First Amendment to the Third Restated 10.74.1 to the Company's 1-6986
and Amended Public Service Company Quarterly Report on Form
of New Mexico Performance Stock Plan 10-Q for the quarter ended
Dated February 7, 2000 March 31, 2000.
10.75** Executive Savings Plan effective July 1, 10.75 to the Company's Quarterly
1998. Report on Form 10-Q for the
quarter ended June 30, 1998.
10.76 PVNGS Capital Trust--Variable Rate 10.76 to the Company's Quarterly 1-6986
Trust Notes--PVNGS Note Agreement Report on Form 10-Q for the
dated as of July 31, 1998. quarter ended September 30, 1998.
10.77 San Juan Project Participation Agreement dated 10.77 to the Company's Quarterly 1-6986
as of October 27, 1999, among Public Service Report on Form 10-Q for the
Company of New Mexico, Tucson Electric Power quarter ended September 30, 1999.
Company, The City of Farmington, New Mexico,
M-S-R Public Power Agency, The Incorporated
County of Los Alamos, New Mexico, Southern
California Public Power Authority, City of
Anaheim, Utah Associated Municipal Power
System and Tri-State Generation and
Transmission Association, Inc.
E-15
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.78 Stipulation in the matter of the Commission's 10.78 to the Company's Quarterly 1-6986
investigation of the rates for electric Report on Form 10-Q for the
service of Public Service Company of New quarter ended September 30, 1999.
Mexico, Rate Case No. 2761, dated May 21, 1999
10.78.1 Stipulation in the matter of the Commission's 10.78.1 to the Company's 1-6986
investigation of the rates for electric service Quarterly Report on Form
of Public Service Company of New Mexico, 10-Q the quarter ended
Rate for Case No. 2761, dated May 27, 1999 September 30, 1999.
10.79 Asset Sale Agreement between Tri-State 10.79 to the Company's Quarterly 1-6986
Generation and Transmission Association, Inc., Report on Form 10-Q for the
a Colorado Cooperative Association and Public quarter ended September 30, 1999.
Service Company of New Mexico, a New Mexico
Corporation, dated September 9, 1999
10.80** Supplemental Employee Retirement 10.80 to the Company's 1-6986
Agreement, dated March 14, 2000 for Quarterly Report on Form
Patrick T. Ortiz 10-Q for the quarter ended
March 31, 2000.
10.81** Supplemental Employee Retirement 10.81 to the Company's 1-6986
Agreement, dated March 22, 2000 for Quarterly Report on Form
Jeffry E. Sterba 10-Q for the quarter ended
March 31, 2000.
10.82 Manzano Corporation Omnibus Performance 10 to Registration Statement No. 333-32170
Equity Plan 333-32170 of the Company filed
April 18, 2000.
Additional Exhibits
21 Certain subsidiaries of the registrant. 22 to Annual Report of the 1-6986
Registrant on
Form 10-K for
fiscal year
ended December
31, 1992.
E-16
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.2* Participation Agreement dated as of 99.2 to Annual Report of the 1-6986
December 16, 1985, among the Owner Registrant on Form 10-K for
Participant named therein, First PV fiscal year ended December 31,
Funding Corporation. The First National 1995.
Bank of Boston, in its individual capacity
and as Owner Trustee (under a Trust
Agreement dated as of December 16, 1985
with the Owner Participant), Chemical
Bank, in its individual capacity and as
Indenture Trustee (under a Trust
Indenture, Mortgage, Security Agreement
and Assignment of Rents dated as of
December 16, 1985 with the Owner
Trustee), and Public Service Company of
New Mexico, including Appendix A
definitions together with Amendment No.
1 dated July 15, 1986 and Amendment No.
2 dated November 18, 1986 (refiled).
99.3 Trust Indenture, Mortgage, Security 99.3 to the Company's Quarterly 1-6986
Agreement and Assignment of Rents Report on Form 10-Q for the
dated as of December 16, 1985, between quarter ended March 31, 1996.
the First National Bank of Boston, as
Owner Trustee, and Chemical Bank, as
Indenture Trustee together with
Supplemental Indentures Nos. 1 and 2
(refiled).
99.3.3 Supplemental Indenture No. 3 dated as 99.3.3 to the Company's 1-6986
of March 8, 1995, to Trust Indenture Quarterly Report on Form 10-Q
Mortgage, Security Agreement and for the quarter ended March 31,
Assignment of Rents between The First 1995.
National Bank of Boston and Chemical
Bank dated as of December 16, 1985.
99.4* Assignment, Assumption and Further 99.4 to Annual Report of the 1-6986
Agreement dated as of December 16, Registrant on Form 10-K for
1985, between Public Service Company fiscal year ended December
of New Mexico and The First National Bank 31, 1995.
of Boston, as Owner Trustee (refiled).
E-17
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.5 Participation Agreement dated as of July 99.5 to Annual Report of the 1-6986
31, 1986, among the Owner Participant named Registrant on Form 10-K for
herein, First PV Funding Corporation, The fiscal year ended December 31,
First National Bank of Boston, in its 1996.
individual capacity and as Owner Trustee
(under a Trust Agreement dated as of July 31,
1986, with the Owner Participant), Chemical
Bank, in its individual capacity and as
Indenture Trustee (under a Trust Indenture,
Mortgage, Security Agreement and Assignment of
Rents dated as of July 31, 1986, with the
Owner Trustee), and Public Service Company of
New Mexico, including Appendix A definitions
together with Amendment No. 1 thereto
(refiled).
99.6 Trust Indenture, Mortgage, Security 99.6 to Annual Report of the 1-6986
Agreement and Assignment of Rents Registrant on Form 10-K for
dated as of July 31, 1986, between The fiscal year ended December
First National Bank of Boston, as Owner 31, 1996.
Trustee, and Chemical Bank, as Indenture
Trustee together with Supplemental Indenture
No. 1 thereto (refiled).
99.7 Assignment, Assumption, and Further 99.7 to Annual Report of the 1-6986
Agreement dated as of July 31, 1986, Registrant on Form 10-K for
between Public Service Company of fiscal year ended December 31,
New Mexico and The First National Bank 1996.
of Boston, as Owner Trustee (refiled).
99.8 Participation Agreement dated as of 99.8 to the Company's Quarterly 1-6986
August 12, 1986, among the Owner Report on Form 10-Q for the
Participant named therein, First PV quarter ended March 31, 1997.
Funding Corporation. The First National
Bank of Boston, in its individual capacity and
as Owner Trustee (under a Trust Agreement
dated as of August 12, 1986, with the Owner
Participant), Chemical Bank, in its individual
capacity and as Indenture Trustee (under a
Trust Indenture, Mortgage, Security Agreement
and Assignment of Rents dated as of August 12,
1986, with the Owner Trustee), and Public
Service Company of New Mexico, including
Appendix A definitions (refiled).
E-18
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.8.1* Amendment No. 1 dated as of November 99.8.1 to the Company's 1-6986
18, 1986, to Participation Agreement Quarterly Report on Form 10-Q
dated as of August 12, 1986 (refiled). for the quarter ended March 31,
1997.
99.9* Trust Indenture, Mortgage, Security 99.9 to Annual Report of the 1-6986
Agreement and Assignment of Rents dated Registrant on Form 10-K for
as of August 12, 1986, between the First fiscal year ended
National Bank of Boston, as Owner Trustee, December 31, 1996.
and Chemical Bank, as Indenture Trustee
together with Supplemental Indenture No. 1
thereto (refiled).
99.9.2 Supplemental Indenture No. 2 dated as 99.9.1 to the Company's 1-6986
of March 8, 1995, to Trust Indenture, Quarterly Report on Form 10-Q
Mortgage, Security Agreement and for the quarter ended March 31,
Assignment of Rents between The First 1995.
National Bank of Boston and Chemical
Bank dated as of August 12, 1986.
99.10* Assignment, Assumption, and Further 99.10 to the Company's Quarterly 1-6986
Agreement dated as of August 12, 1986, Report on Form 10-Q for the
between Public Service Company of New quarter ended March 31, 1997.
Mexico and The First National Bank of
Boston, as Owner Trustee (refiled).
99.11* Participation Agreement dated as of 99.1 to the Company's Quarterly 1-6986
December 15, 1986, among the Owner Report on Form 10-Q for the
Participant named therein, First PV quarter ended March 31, 1997.
Funding Corporation, The First National
Bank of Boston, in its individual capacity
and as Owner Trustee (under a Trust
Agreement dated as of December 15, 1986,
with the Owner Participant), Chemical Bank,
in its individual capacity and as Indenture
Trustee (under a Trust Indenture, Mortgage,
Security Agreement and Assignment of Rents
dated as of December 15, 1986, with the
Owner Trustee), and Public Service Company
of New Mexico, including Appendix A
definitions (Unit 1 Transaction) (refiled).
99.12 Trust Indenture, Mortgage, Security 99.12 to the Company's Quarterly 1-6986
Agreement and Assignment of Rents Report on Form 10-Q for the
dated as of December 15, 1986, between quarter ended March 31, 1997.
The First National Bank of Boston, as
Owner Trustee, and Chemical Bank, as
Indenture Trustee (Unit 1 Transaction)
(refiled).
E-19
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.13 Assignment, Assumption and Further 99.13 to the Company's 1-6986
Agreement dated as of December 15, Quarterly Report on Form
1986, between Public Service Company 10-Q for the quarter ended
of New Mexico and The First National March 31, 1997.
Bank of Boston, as Owner Trustee
(Unit 1 Transaction) (refiled).
99.14 Participation Agreement dated as of 99.14 to the Company's 1-6986
December 15, 1986, among the Owner Quarterly Report on Form
Participant named therein, First PV 10-Q for the quarter ended
Funding Corporation, The First National March 31, 1997.
Bank of Boston, in its individual capacity
and as Owner Trustee (under a Trust
Agreement dated as of December 15, 1986,
with the Owner Participant), Chemical Bank,
in its individual capacity and as Indenture
Trustee (under a Trust Indenture, Mortgage,
Security Agreement and Assignment of Rents
dated as of December 15, 1986, with the
Owner Trustee), and Public Service Company
of New Mexico, including Appendix A
definitions (Unit 2 Transaction) (refiled).
99.15 Trust Indenture, Mortgage, Security 99.15 to Annual Report of the 1-6986
Agreement and Assignment of Rents dated Registrant on Form 10-K
as of December 31, 1986, between the for fiscal year ended
First National Bank of Boston, as Owner December 31, 1996.
Trustee, and Chemical Bank, as Indenture
Trustee (Unit 2 Transaction) (refiled).
99.16 Assignment, Assumption, and Further 99.16 to the Company's Quarterly 1-6986
Agreement dated as of December 15, Report on Form 10-Q for the
1986, between Public Service Company quarter ended March 31, 1997.
of New Mexico and The First National
Bank of Boston, as Owner Trustee
(Unit 2 Transaction) (refiled).
99.17* Waiver letter with respect to "Deemed 99.17 to Annual Report of the 1-6986
Loss Event" dated as of August 18, 1986, Registrant on Form 10-K
between the Owner Participant named for fiscal year ended December
therein, and Public Service Company of 31, 1996.
New Mexico (refiled).
99.18* Waiver letter with respect to Deemed 99.18 to Annual Report of the 1-6986
Loss Event" dated as of August 18, 1986, Registrant on Form 10-K
for between the Owner Participant named for fiscal year ended December
therein, and Public Service Company of 31, 1996.
New Mexico (refiled).
E-20
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.19 Agreement No. 13904 (Option and 99.19 to Annual Report of the 1-6986
Purchase of Effluent), dated April 23, Registrant on Form 10-K for
1973, among Arizona Public Service fiscal year ended December 31,
Company, Salt River Project Agricultural 1996.
Improvement and Power District, the
Cities of Phoenix, Glendale, Mesa,
Scottsdale, and Tempe, and the Town of
Youngtown (refiled).
99.20 Agreement for the Sale and Purchase of 99.20 to Annual Report of the 1-6986
Wastewater Effluent, dated June 12, 1981, Registrant on Form 10-K
Among Arizona Public Service Company, for fiscal year ended
Salt River Project Agricultural Improvement December 31, 1996.
and Power District and the City of Tolleson,
as amended (refiled).
99.21* 1996 Supplemental Indenture dated as of 99.21 to the Company's Quarterly 1-6986
September 27, 1996 to Trust Indenture, Report on Form 10-Q for the
Mortgage, Security Agreement and quarter ended September 30, 1996.
Assignment of Rents dated as of December
16, 1985 between State Street Bank and
Trust Company, as Owner Trustee, and
The Chase Manhattan Bank, as Indenture
Trustee.
99.22 1997 Supplemental Indenture, dated as of 99.22 to the Company's Quarterly 1-6986
December 23, 1997, to Trust Indenture, Report on Form 10-Q for the
Mortgage, Security Agreement and quarter ended March 30, 1998.
Assignment of Rents, dated as of August
12, 1986, between State Street Bank and
Trust, as Owner Trustee, and The Chase
Manhattan Bank, as Indenture Trustee.
- -----------
* One or more additional documents, substantially identical in all material
respects to this exhibit, have been entered into, relating to one or more
additional sale and leaseback transactions. Although such additional
documents may differ in other respects (such as dollar amounts and
percentages), there are no material details in which such additional
documents differ from this exhibit.
** Designates each management contract or compensatory plan or arrangement
required to be identified pursuant to paragraph 3 of Item 14(a) of
Form 10-K.
E-21
(b) Reports on Form 8-K:
During the quarter ended December 31, 2000 and during the period
beginning January 1, 2001 and ending February 20, 2001, the Company filed, on
the date indicated, the following reports on Form 8-K.
Dated: Filed: Relating to:
------ ------ ------------
July 31, 2000 September 6, 2000 The Company Reports its Comparative
Operating Statistics for July 2000 and 1999
September 14, 2000 September 19, 2000 The Company Projects a Strong Third Quarter
Ups Earnings Estimate for 2000, 2001
October 2, 2000 October 3, 2000 The Company Names New Chairman
September 14, 2000 October 3, 2000 The Company's CEO Encourages NM
Regulators to Press on Toward Electric Choice
August 31, 2000 October 3, 2000 The Company Reports Comparative
Operating Statistics for August 2000 and 1999
September 30, 2000 October 16, 2000 The Company Reports Comparative
Operating Statistics for September 2000 and
1999
October 16, 2000 October 16, 2000 The Company Hosts Third Quarter Earnings
Conference Call on the Web
October 18, 2000 October 19, 2000 The Company Reports Quarter and Nine
Months Ended September 30, 2000 Earnings
Announcement and Consolidated Statement
of Earnings
October 17, 2000 October 20, 2000 The Company Negotiates Cost-Saving
Revisions to San Juan Coal Contract
October 31, 2000 October 31, 2000 The Company `Boutique" Strategy Key to
Wholesale Success, CEO Tells Analysts
November 9, 2000 November 9, 2000 The Company Reports it will Acquire Western
Resources Electric Utility Operations in a
Tax-Free, Stock-for-Stock Transaction
November 9, 2000 November 9, 2000 The Company Reports it will Purchase the
Electric Utility Operations of Western
Resources
November 9, 2000 November 13, 2000 The Company Reports the Acquisition of
Western Resources Expected to Provide
Immediate Earnings Boost
November 14, 2000 November 14, 2000 The Company Provides More Detail on
Proposed Western Resources Acquisition
E-22
Dated: Filed: Relating to:
------ ------ ------------
November 9, 2000 November 16, 2000 The Company Reports Press Conference
Transcript to Discuss the Acquisition of
Western Resources
November 8, 2000 November 17, 2000 The Company Enters a Merger Agreement
With Western and Westar Industries
November 14, 2000 November 16, 2000 The Company Provides Information to Utility
Investment Analysts about A High-Voltage
Combination - The Company and Western
Resources
November 27, 2000 November 30, 2000 Western Resources Asks Kansas Regulators
to Approve a $151 million in Retail Rate
Increases for KPL and KGE
October 31, 2000 November 29, 2000 The Company Reports Comparative
Operating Statistics for October 2000 and 1999
December 12, 2000 December 13, 2000 The Company Declares Common and
Preferred Stock Dividend
November 30, 2000 December 15, 2000 The Company Reports Comparative
Operating Statistics for November 2000 and
1999
December 12, 2000 December 27, 2000 The Company Declares Common and
Preferred Stock Dividend
December 19, 2000 December 27, 2000 The Company's Subsidiary to Invest
$10 Million in Internet Gateway Services
Company
December 31, 2000 January 18, 2001 The Company Reports Comparative
Operating Statistics for December 2000 and
1999
January 25, 2001 January 25, 2001 The Company Reports Quarter and Nine
Months Ended December 31, 2000 Earnings
Announcement and Consolidated Statement
of Earnings
January 25, 2001 January 25, 2001 The Company Reports Fourth Quarter and
Year End 2000 Earnings
E-23
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW MEXICO
(Registrant)
Date: February 21, 2001 By /s/ J. E. Sterba
-------------------------------
J. E. Sterba
Chairman, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Capacity Date
--------- -------- ----
/s/ J. E. STERBA Principal Executive Officer and February 21, 2001
- ---------------------------------------------- Chairman of the Board
J. E. STERBA
Chairman, President and
Chief Executive Officer
/s/ M. H. MAERKI Principal Financial Officer February 21, 2001
- ----------------------------------------------
M. H. Maerki
Senior Vice President and
Chief Financial Officer
/s/ J. R. LOYACK Principal Accounting Officer February 21, 2001
- ----------------------------------------------
J. R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
/s/ J. T. ACKERMAN Chairman of the Board February 21, 2001
- ----------------------------------------------
J. T. Ackerman
/s/ R. G. ARMSTRONG Director February 21, 2001
- ----------------------------------------------
R. G. Armstrong
/s/ J. A. GODWIN Director February 21, 2001
- ----------------------------------------------
J. A. Godwin
/s/ M. LUJAN JR. Director February 21, 2001
- ----------------------------------------------
M. Lujan Jr.
/s/ B. F. MONTOYA Director February 21, 2001
- ----------------------------------------------
B. F. Montoya
/s/ T. F. PATLOVICH Director February 21, 2001
- ----------------------------------------------
T. F. Patlovich
/s/ R. M. PRICE Director February 21, 2001
- ----------------------------------------------
R. M. Price
/s/ P. F. ROTH Director February 21, 2001
- ----------------------------------------------
P. F. Roth
E-24