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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, 2001
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- ------------------
333-32170 PNM Resources, Inc. 85-0468296
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
1-6986 Public Service Company of New Mexico 85-0019030
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
Securities Registered Pursuant To Section 12(b) Of The Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
- ---------- ------------------- ---------------------
PNM Resources, Inc. Common Stock, No Par Value New York Stock Exchange
Securities Registered Pursuant To Section 12(g) Of The Act:
Registrant Title of Each Class
- ---------- -------------------
Public Service Company 1965 Series, 4.58% Cumulative Preferred Stock
of New Mexico ($100 stated value without sinking fund)
Indicate by check mark whether each registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. YES |X| NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrants' 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 Common Stock of PNM Resources, Inc. ("PNM
Resources") outstanding as of January 31, 2002 was 39,117,799. On such date, the
aggregate market value of the voting stock held by non-affiliates of PNM
Resources, as computed by reference to the New York Stock Exchange composite
transaction closing price of $27.01 per share reported by The Wall Street
Journal, was $1,056,571,751.
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 by PNM Resources with the Securities and Exchange
Commission pursuant to Regulation 14A relating to the annual meeting of
stockholders of PNM Resources to be held on May 14, 2002 - PART III.
This combined Form 10-K represents separate filings by PNM Resources and PNM.
Information combined herein relating to an individual registrant is filed by
that registrant on its own behalf. PNM makes no representations as to the
information relating to PNM Resources and its subsidiaries other than PNM. When
this combined Form 10-K is incorporated by reference into any filing with the
SEC made by PNM, the portions of this Form 10-K that relate to PNM Resources and
its subsidiaries other than PNM are not incorporated by reference therein.
ii
TABLE OF CONTENTS
Page
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GLOSSARY................................................................... v
PART I
ITEM 1. BUSINESS.......................................................... 1
THE COMPANY.................................................. 1
UTILITY OPERATIONS........................................... 2
Electric Services........................................ 2
Gas Services............................................. 3
GENERATION AND TRADING OPERATIONS............................ 4
Power Sales............................................... 4
Sources of Power......................................... 5
Fuel and Water Supply.................................... 6
UNREGULATED OPERATIONS....................................... 8
RATES AND REGULATION......................................... 9
Electric Rates and Regulation............................ 10
Gas Rates and Regulation................................. 11
ENVIRONMENTAL MATTERS........................................ 12
COMPETITION.................................................. 15
EMPLOYEES.................................................... 16
ITEM 2. PROPERTIES........................................................ 16
ELECTRIC..................................................... 16
Fossil-Fueled Plants..................................... 17
Nuclear Plant............................................ 17
Other Electric Properties................................ 22
NATURAL GAS.................................................. 22
OTHER INFORMATION............................................ 22
ITEM 3. LEGAL PROCEEDINGS................................................. 23
PVNGS Water Supply Litigation............................. 23
San Juan River Adjudication............................... 23
Republic Savings Bank Litigation.......................... 23
Purported Navajo Environmental Regulation................. 24
Royalty Claims............................................ 24
KAFB Contract............................................. 25
Avistar Severence......................................... 26
Western Resources......................................... 27
Reeves Station Environmental Matters...................... 28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............... 29
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE COMPANY....................... 29
iii
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.......................................... 74
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 E-1
AND MANAGEMENT.............................................
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-28
iv
GLOSSARY
Act.......................... The Clean Air Act - Amendments of 1990
Afton........................ Afton Generating Station
Avistar...................... Avistar, Inc., an unregulated subsidiary of PNM
Resources, Inc.
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 Holdings (Operations)
BLM.......................... Bureau of Land Management
BNCC......................... BHP Navajo Coal Company
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
FASB......................... Financial Accounting Standards Board
Farmington................... City of Farmington, New Mexico
FERC......................... Federal Energy Regulatory Commission
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 PNM Resources, Inc
ISO.......................... Independent System Operator
KAFB......................... Kirtland Air Force Base
Kv........................... Kilovolt
KW........................... Kilowatt
KWh.......................... Kilowatt Hour
Lordsburg.................... Lordsburg Generating Station
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
v
NMPUC........................ New Mexico Public Utility Commission
NRC.......................... United States Nuclear Regulatory Commission
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 Co.
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 PNM Resources, Inc.
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
vi
PART I
ITEM 1. BUSINESS
THE COMPANY
PNM Resources, Inc. (the "Company") was incorporated in the State of New
Mexico on March 3, 2000. PNM Resources' principal subsidiary Public Service
Company of New Mexico ("PNM") was incorporated in the State of New Mexico on May
9, 1917. The Company has its principal offices at Alvarado Square, Albuquerque,
New Mexico 87158 (telephone number 505-241-2700). The Company is a holding
company of energy and energy-related companies. Its principal subsidiary 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.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Company, the Company became the parent company of PNM. Prior
to the share exchange, the Company had existed as a subsidiary of PNM. The new
holding company began trading on the New York Stock Exchange under the same PNM
symbol beginning on December 31, 2001.
This filing for the Company and PNM is presented on a combined basis.
The Company as an unconsolidated holding company ("Holding Company") had no
material operations for the year ended December 31, 2001. Except for its
consolidated investment in PNM, the Holding Company's only assets were cash of
$11 million, short-term investments of $10 million and long-term investments of
$106 million at December 31, 2001. In addition, the Holding Company had no
liabilities at December 31, 2001. Accordingly, the reader should assume that the
information presented applies to both the Company and PNM, except where the
context or references clearly indicate otherwise.
The Company operates as three distinct business units: (1) Utility
Operations, (2) Generation and Trading Operations and (3) Unregulated
Operations. Utility Operations and Generation and Trading Operations are
business units of Public Service Company of New Mexico. Utility Operations
include the Electric Services ("Electric") and the Gas Services ("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. 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. On
January 11, 2002, the Company's primary subsidiary engaged in unregulated
activities, Avistar, was dividended to the Company by its subsidiary, Public
Service Company of New Mexico.
Financial information relating to amounts of sales, revenue, net income
and total assets of the Company's business units or reportable segments is
contained in Part II, Item 7 - "Management's Discussion and Analysis of
Financial Condition and Results of Operations" or note 1 of the notes to
consolidated financial statements.
1
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. The largest retail electric customer
served by the Company accounted for approximately 4.2% of the Company's total
retail electric revenues for the year ended December 31, 2001.
For the years 1997 through 2001, retail KWh sales have grown at a
compound annual rate of approximately 2.65%. The Company's system peak demands
for its retail customers and firm requirements customers in summer and winter
for the last three years are shown in the following table:
SYSTEM PEAK DEMAND
(Megawatts)
2001 2000 1999
--------- --------- ---------
Summer....................... 1,397 1,368 1,291
Winter....................... 1,294 1,211 1,161
The Company holds long-term, non-exclusive franchise agreements for its
electric retail operations, expiring between June 2002 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, San Miguel
County, Village of Bosque Farms and Village of Tijeras franchises have expired.
The COA metropolitan area accounted for approximately 52% of the Company's 2001
total electric utility operating revenues, and no other franchise area
represents more than approximately 8%. The Company continues to collect and pay
franchise fees to the COA, City of Santa Fe, the Town of Cochiti Lake, Village
of Bosque Forms and Village of Tijeras. 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 2,890 circuit miles of transmission lines,
interconnected with other utilities in New Mexico and east and south 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 and the lack of transmission
development, most of the capacity on this transmission system is fully committed
and there is very little or no additional access available on a firm commitment
basis. These factors result in physical constraints in the system and limit the
ability to wheel power into the Company's service area from outside the state.
2
Gas
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. The COA
metropolitan area accounted for approximately 33% of the total gas revenues. No
single sales-service customer accounted for more than approximately 4% of the
Company's therm sales in 2001. The Company holds long-term, non-exclusive
franchises with varying expiration dates in all incorporated communities
requiring franchise agreements except for the COA, City of Santa Fe, Aztec,
Village of Bosque Farms, Town of Cochiti Lake, Los Ranchos de Albuquerque and
Tatum. The Company remains obligated to serve the franchise areas pursuant to
state law even in the absence of a franchise agreement.
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 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 1,360 gas marketers, producers and end users during 2001.
During 2001, approximately 52% 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.
Cost-of-gas revenues, received from sales-service and off-system customers, and
other PGAC-related revenues accounted for approximately 65% of the Company's
total gas operating revenues in 2001. Since a major portion of the Company's
load is related to heating, levels of therm sales are affected by weather.
Approximately 54% of the Company's total therm sales in 2001 occurred in the
months of January, February, November and December.
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
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
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 was, and
continues to be, 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 niche business strategy of providing
electric power customized to meet the special needs of customers. This niche
marketing strategy is based on the Company's 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 jurisdictional 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.
Certain of the Company's generation assets are excluded from
jurisdictional electric rates. In 1988, the NMPUC excluded 130MW of SJGS Unit 4
and all of PVNGS Unit 3. 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 the scope of its trading activities. During
2001, 2000 and 1999, the Company's sales in the off-system markets accounted for
approximately 64%, 64% and 62%, respectively, of its total KWh sales. Of the
total off-system sales made in 2001 and 2000, 77% and 75% respectively were
transacted through purchases for resale.
In 1990, the NMPUC established an off-system sales methodology that
provided for a sharing mechanism whereby a certain amount of revenues from
off-system sales were credited to reduce retail cost of service. Subsequent rate
cases continued to utilize this methodology. As a result, electric customers
have received over $300 million in rate benefits since 1990 from the Company's
4
wholesale power marketing activities. 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
froze rates until January 1, 2003.
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. The Company has committed to purchase five
combustion turbines at a total cost of $151.3 million. The plants' estimated
cost of construction is approximately $400.3 million of which the Company has
expended $103.4 million as of December 31, 2001. In November 2001, the Company
broke ground for Afton, a 135 MW gas fired generating plant on a site in
Southern New Mexico. This facility is expected to be operational by October
2002. Currently, the Company plans to expand the facility to 225 MW by the end
of 2003. In February 2002, the Company also broke ground to build Lordsburg, an
80 MW natural gas fired generating plant in Southwestern New Mexico. This
facility is expected to be operational by July 2002. The planned plants are part
of the Company's ongoing competitive strategy of increasing generation capacity
over time.
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, which required SDG&E to purchase 100 MW from the Company
expired on April 30, 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. For
2001, APPA invoked its option to increase its peak demand to 92 MW. The APPA
demand will drop to 15 MW in June 2002. The Company furnished firm-requirements
wholesale power in New Mexico in 2001 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 2001 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 50 MW. The Company began
serving a partial requirements contract with the Texas-New Mexico Power Company
in July 2001 for 62 MW. The contract service drops to 32 MW for 2002, then
becomes a full requirements contract in January 2003 and continues through 2006.
The full requirements demand is expected to be 107 MW in 2003, 109 MW in 2004,
111 MW in 2005 and 114 MW in 2006. No firm requirements wholesale customer
accounted for more than 0.01% of the Company's total electric sales for resale
revenues for the year ended December 31, 2001.
Sources of Power
As of December 31, 2001, 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 operated by the Company. In 2001, the plant's capacity factor
performance ranked in the 90th percentile of the 403 coal-fired power plants in
the nation. SJGS's equivalent availability and capacity factor were 84.7% and
82.1% respectively, for the twelve months ended December 31, 2001, as compared
to 88.9% and 85.6%, respectively for 2000. Capacity factors for Four Corners and
PVNGS were 83.75% and 88.12%, respectively, in 2001, as compared to 84.2% and
92.7%, respectively, in 2000. Four Corners and PVNGS are operated by APS. (See
Item 2. Properties).
5
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 per year and expires in May 2011. The
Company may reduce its purchases from SPS by 25 MW annually upon three years
notice. The Company provided notice to reduce the purchase by 25 MW in 1999 and
by an additional 25 MW in 2000. The Company also is party to a master power
purchase and sale agreement with SPS, dated August 2, 1999 pursuant to which the
Company has agreed to purchase 72 MW of firm power from SPS from 2002 through
2005. In addition, the Company has 70 MW of contingent capacity obtained from El
Paso under a transmission capacity for generation capacity trade arrangement
through September 2004. Beginning October 2004 and continuing through June 2005,
the capacity amount is 39 MW. The Company holds a PPA with Tri-State for 50 MW
through June 30, 2010. 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 the new Delta gas-fired generating plant for 20 years. 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 the 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.
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 three
years were as follows:
Coal Nuclear Gas and Oil
Percent of Average Percent of Average Percent of Average
---------------------- --------------------- ---------------------
2001...... 66.9 179.6 28.4 45.7 4.7 524.5
2000...... 68.0 165.3 29.8 45.4 2.2 482.6
1999...... 67.6 165.3 31.0 47.4 1.4 331.9
The estimated generation mix for 2002 is 66.8% coal, 29.1% nuclear and
4.2% 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 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 Minerals International,
Inc. has guaranteed the obligations of SJCC under the agreement, which
contemplates the delivery of approximately 103 million tons of coal during its
remaining term. That amount would supply substantially all the requirements of
the SJGS through approximately 2017.
6
In August 2001, the Company signed an agreement with SJCC and Tucson to
replace 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.
The revised coal contract, entered into as a result of the move to an
underground mine, is expected to save the Company between $400 million and $500
million in fuel costs over the next 16 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. The plant is expected to realize
some of the benefits of the higher quality coal in 2002, as the existing surface
mines are phased out and the underground mine is developed.
Four Corners is supplied with coal under a fuel agreement between the
owners and BNCC, under which BNCC agreed to supply all the coal requirements for
the life of the plant. The current fuel agreement expires December 31, 2004.
Negotiations for an extension have been initiated. BNCC 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.
Natural Gas
The natural gas used as fuel for the Company's COA electric generating
plant (Reeves Station and the PPA) is delivered by Gas. (See "Gas Services"). In
the second quarter of 2001, the Company's Generation and Trading Operations
began procuring its gas supply independent of the Company and contracting with
the Utility Operations for transportation services only. The Company's
Generation and Trading Operations commenced a hedging program to reduce its
exposure to fluctuations in prices for natural gas as a fuel source for its
generation. (See Note 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 uranium concentrates contracts
and options could be utilized to meet approximately 67% of requirements in 2003.
Spot purchases on the uranium concentrates market will be made, as appropriate.
Through the enriched uranium product ("EUP") contract, and through
conversion services contracts, the PVNGS participants have arranged for uranium
conversion services that will meet 100% of requirements in 2002 and 2003. The
PVNGS participants have an enrichment services contract and an EUP contract that
furnish enrichment services required for the operation of the three PVNGS units
through 2003.
7
The PVNGS participants have a new EUP contract that will furnish up to
100% of PVNGS's requirements for uranium, conversion services and enrichment
services from 2004 through 2008. This contract could also provide 100% of
enrichment services in 2009 and 2010.
In addition, existing contracts will provide 100% of fuel assembly
fabrication services until at least 2015 for each PVNGS unit.
Water Supply
Water for SJGS and Four Corners is obtained from the San Juan River. (See
Item 3. - "Legal Proceedings- San Juan River Adjudication".) 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 BNCC. The Company is of the
opinion that sufficient water is under contract for the SJGS through 2005. BNCC
holds rights to San Juan River water and committed a portion of those rights to
Four Corners through the life of the plant.
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 has received all requisite approvals.
Additionally, the Company has entered into an agreement 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. This
settlement with the Navajo Nation will not have a material adverse effect on the
Company's financial position or its results of operations.
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's wholly-owned subsidiary, Avistar, was formed in August 1999
as a New Mexico corporation and is currently engaged in certain unregulated,
non-utility business ventures.
In July 2001, the Board of Directors of Avistar decided to wind down all
operations except for Avistar's Reliadigm business unit, which provides
maintenance solutions to the electric power industry. Avistar had previously
divested itself of its Energy Partners business unit and liquidated Axon Field
services and Pathways Integration. In addition, the transfer of operation to the
Sangre de Cristo Water Company to the City of Santa Fe was completed in the
third quarter of 2001. All remaining non-Reliadigm investments were written-off
with the exception of Avistar's investment in Nth Power, an energy related
venture capital fund. The Company recorded charges of $13.1 million to reflect
these activities and the impairment of its Avistar investments.
RATES AND REGULATION
PNM 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 regarding retail
8
utility services provided in New Mexico. The FERC has jurisdiction over rates
and other matters related to wholesale electric sales and cost recovery of its
transmission network.
In April 1999, New Mexico's Electric Utility Industry Restructuring Act
of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act
opens the state's electric power market to customer choice. In March 2001,
amendments to the Restructuring Act were passed which delay the original
implementation dates by approximately five years, including the requirement for
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets. In addition, the PRC will have the
authority to delay implementation for another year under certain circumstances.
The Restructuring Act, as amended, will give schools, residential and small
business customers the opportunity to choose among competing power suppliers
beginning in January 2007. Competition would be expanded to include all
customers starting in July 2007. The Company is unable to predict the form its
further restructuring will take under the delayed implementation of customer
choice. In addition, the Restructuring Act, as amended, 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"). (See Item 7. "Management's Discussion and Analysis
of Financial Condition And Results of Operations - Other Issues Facing The
Company - Recovery of Certain Costs Under The Restructuring Act" below).
The amendments to the Restructuring Act required that the PRC approve a
holding company, subject to terms and conditions in the public interest, without
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets, by July 1, 2001. In addition, the
amendments allow utilities to engage in unregulated power generation business
activities until corporate separation is implemented (see Item 7. "Management's
Discussion and Analysis of Financial Condition And Results of Operations - Other
Issues Facing the Company - Merchant Plant Filing.")
On December 31, 2001, the Company implemented the holding company
structure without corporate separation of supply service and energy-related
services assets from distribution and transmission services assets. This
structure provides for a holding company whose current holdings will be Public
Service Company of New Mexico, Avistar and other inactive unregulated
subsidiaries. This was effected through the share exchange between existing
Company shareholders and the holding company, PNM Resources. Avistar and most of
the inactive unregulated subsidiaries became wholly-owned subsidiaries of the
holding company in January 2002. There are no current plans to provide the
holding company with significant debt financing.
9
Because of its ownership of PNM, the Company is a "public utility holding
company" under the Public Utility Holding Company Act of 1935 ("PUHCA").
However, the Company is exempt from the provisions of PUHCA, except Section
9(a)(2) thereof, which requires the approval of the SEC for a direct or indirect
acquisition by a public utility holding company of five percent or more of the
voting securities of any electric or gas utility company subject to PUHCA.
Electric Rates and Regulation
Proceeding Related to the Restructuring Act
In November 2001, the Company began settlement negotiations with the
PRC's utility staff and intervenors in PRC proceedings related to the
Restructuring Act in order to resolve a number of matters. Those matters include
issues being examined in the Company's merchant plant filing at the PRC, the
future framework for restructuring the electric industry in New Mexico under the
Restructuring Act, and a future retail electric rate path. The negotiations
include the potential implementation and effective date of rates that would
replace those approved under the rate freeze stipulation that remains in effect
until January 1, 2003.
FERC Mandated Regional Transmission Organizations
With the passage of the Public Utility Regulatory Policies Act of 1978
and 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. Barriers
have been reduced for companies wishing to build, own and operate electric
generating facilities. In 1996, the FERC issued Order 888 which required
electric utilities controlling transmission facilities to file open access
transmission tariffs, which opened the utility transmission systems to wholesale
sellers and buyers of electric energy on a non-discriminatory basis.
Order 888 also encouraged utilities to investigate the formation of
independent system operators ("ISOs") to operate transmission assets and
provided guidance for the formation, operation and governance of ISOs. In 1999,
the FERC issued Order 2000 on Regional Transmission Organizations ("RTOs"),
which established timelines for transmission owning entities to join an RTO and
defined the minimum characteristics and functions of an RTO.
The Company, along with other regional transmission owners ("TO's"),
originally pursued the formation of an RTO through Desert STAR, a non-profit
organization. Later because of FERC's acceptance of a for-profit RTO model and
because a for-profit RTO was viewed as having the proper motivation to
efficiently facilitate competitive markets, the Company and the TO's formed
WestConnect RTO, LLC ("WestConnect"), a for-profit transmission company.
On October 16, 2001, WestConnect filed its complete RTO package with FERC
requesting a Declaratory Order confirming the WestConnect filing satisfies
FERC's Order 2000 requirements. There were over 50 intervenors in the
WestConnect docket including the New Mexico Attorney General, New Mexico
Industrial Energy Consumers and the New Mexico Public Regulation Commission.
WestConnect filed a response to the intervenors' concerns on December 17, 2001.
10
Uncertainty exists regarding FERC's evolving RTO policy. WestConnect is
participating in various workshops and rulemakings before the FERC and is
pursuing avenues to expand its scope so as to enhance its chances for approval
as one of the RTOs in the West.
FERC Rulemakings
Over the past few months, FERC has issued numerous rulemakings. The Company
is following the rulemakings and will submit its comments or will comment in
conjunction with the Edison Electric Institute ("EEI"). WestConnect is also
following, attending workshops and commenting on the rulemakings, which affect
the member companies, including the Company. The rulemakings of particular
interest to the Company include:
o Standardizing Generation Interconnection Agreements and Procedures; o
Electricity Market Design and Structure; o Standards of Conduct for Transmission
Providers; and o Standards for Business Practices of Interstate Natural Gas
Pipelines.
PRC Transmission Investigation
In July 2001, the AG filed a petition requesting that the PRC initiate an
investigation of electric transmission issues including FERC versus PRC
jurisdiction and the effect of RTO formation on PRC jurisdiction. The Company
suggested workshops to inform the PRC and other interested parties on the
issues. The PRC held workshops for three days, and subsequently issued an order
requiring that the Company and other transmission-owning entities in the
proceeding file comments on jurisdictional issues.
PRC Renewable Resources Rulemakings
By Notice of Proposed Rulemaking dated February 26, 2002, the PRC
proposed the adoption of a new Rule 572 to encourage the development of
renewable energy in New Mexico. The Notice provided for the filing of public
comments and scheduled a public hearing for April 23, 2002. Among other things,
proposed new Rule 572 would establish a renewable portfolio standard of two
percent by September 1, 2003, increasing to five percent by September 1, 2005
and ten percent by September 1, 2007. No more than fifty percent of a utility's
renewable energy resources portfolio would be allowed to be from any single type
of renewable resource for purposes of compliance with the portfolio standard.
The Company will submit comments to the PRC. The Company is unable to predict
the outcome of this rulemaking proceeding.
Gas Rates and Regulation
Purchase Gas Adjustment Clause
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 2001, the Company presented workshops to the PRC, advocating that
the PGAC balancing account be reconciled on a monthly basis, rather than
annually. The Company also advocated that it be allowed to earn a return on the
balancing account balance. A final order was issued in July 2001 that approves
an agreement among the parties regarding the Company's hedging strategy and the
implementation of a price management fund program which includes a continuous
monthly balancing account adjustment factor including a carrying charge set at
the pre-tax cost of capital approved by the PRC in the Company's last gas rate
proceeding. This carrying charge has the effect of keeping the Company whole on
gas purchase transactions whereby the Company is now compensated for the time
value of money.
11
Gas Hedging
On November 7, 2000, the PRC issued an order allowing but not requiring
the Company to implement a financial hedging strategy. The Company utilized gas
options as a hedging tool for the 2001-2002 heating season. Due to the
tremendous increase in natural gas prices during the previous heating season,
the transaction costs relating to hedging activities increased three-fold.
Through a series of workshops and hearings held with the PRC and intervening
parties, the Company proposed without opposition, a hedging budget up to $12
million for the 2001-2002 heating season. The Company recovered the actual
hedging expenditures as a component of the PGAC during the months of October
2001 through February 2002 in equal allotments of $1.88 million. As winter
2001-2002 gas prices were substantially lower than the previous year, the hedges
placed for this winter expired unexercised.
Discounted Transportation Fee Recovery
The Company made a request to begin the recovery of discounted
transportation fee amounts from sales and transportation customers. Discounted
transportation fee recovery is a holdover issue from the New Mexico State
Supreme Court's ruling leaving open that the amounts passing the PRC's cost
benefit test were collectible and only the issue of allocation between
customers. The discounts passing the PRC's cost benefit test total $4.3 million.
A hearing date of April 17, 2002 has been set.
Notice of Inquiry on Pipeline Safety
In May 2001, the PRC issued a notice of inquiry into whether the PRC
should consider adopting new rules including quality of service standards, to
protect the public health and safety, public and private property, and the
environment by ensuring the integrity of pipeline systems. The PRC requested
information from all pipeline operators with underground or above ground
facilities in the state. The Company participated in the comments and hearings
in this inquiry. Subsequent PRC action is pending.
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. (See "Management's Discussion and
Analysis - Critical Accounting Policies - Contingencies - Environmental Issues"
for a discussion of applicable accounting policies).
12
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 compliance with these potential 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
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. Discovery continues in
the pending litigation. 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 the 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 not yet known what changes in EPA policy, if any, may occur in the NSR area
as a result of the change in administrations in Washington. The National Energy
Policy released May 2001 by the National Energy Policy Development Group, called
for a review of the pending NSR enforcement actions and that review continues by
the EPA. 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.
Threatened Citizen Suit Under the Clean Air Act
By letter dated January 9, 2002, counsel for the Grand Canyon Trust and
Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a
so-called "citizen suit" under the Clean Air Act, alleging that the Company and
co-owners of the SJGS violated the Clear Air Act, and the implementing federal
13
and state regulations at SJGS. The notice indicates that penalties and
injunctive relief may be sought. Under the Clear Air Act, GCT must wait at least
60 days after affording the Company notice (i.e., until March 9, 2002) before
filing a lawsuit. GCT has not yet filed suit. The allegations contained in GCT's
notice of intent to sue fall into three categories. First, GCT contends that the
plant has violated, and is currently in violation, of the federal New Source
Performance Standards ("NSPS") at all four units at SJGS. Second, GCT argues
that the plant has violated, and is currently in violation, of the federal PSD
rules, as well as the corresponding provisions of the New Mexico Administrative
Code, at all four units. Third, GCT alleges that the plant has "regularly
violated" the 20% opacity limit contained in SJGS' operating permit and set
forth in federal and state regulations at Units 1, 3 and 4. The Company is
currently investigating the allegations contained in the notice of intent to
sue. Based on its investigation to date, the Company firmly believes that the
allegations are without merit. By letter to GCT's counsel dated February 22,
2002, the Company vigorously disputed the allegations. The Company adheres to
high environmental standards as evidenced by its International Standards
Organization ratings. In that letter, the Company also stated that the GCT has
failed to provide sufficient information to permit full examination of the
allegations and affirmed its compliance with the laws in question. If a lawsuit
is filed by GCT, as threatened, the Company will respond on behalf of the
co-owners and vigorously defend in the litigation. However, the Company is
unable to predict the ultimate outcome of the matter.
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
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.
14
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. On
October 5, 2001, the bioremediation injection system was shut down so that
testing could be conducted to determine the reduction of the contaminant
concentrations that has been achieved.
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 $4.2 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. In November 2001, the NMED approved the Company's
permit modification request to terminate the trust fund. This approval allowed
the Company to use an alternative method rather than the trust fund to satisfy
the financial assurance requirements for post-closure care. This change was
possible due to an improvement in the Company's financial condition. 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 $148.2 million stated in 2001 dollars, including
approximately $24.0 million (of which $18.1 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.
COMPETITION
Under current law, the Company is not in any direct retail competition
with any other regulated electric and gas utility, except for sales of natural
gas. 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 by rural electric
cooperatives and municipal utilities.
15
As a result of the Restructuring Act, as amended, the Company may face
competition from companies with greater financial and other resources when
customer choice is implemented in 2007. There can be no assurance that the
Company will not face competition in the future that would adversely affect its
results.
EMPLOYEES
As of December 31, 2001, the Company had 2,675 full-time employees. The
following table sets forth the number of employees by business segment as of
December 31, 2001:
Number
---------
Corporate (1)........................................ 411
Electric Services.................................... 746
Gas Services......................................... 932
Generation and Trading Operations.................... 569
Unregulated Operations............................... 17
---------
Total............................................. 2,675
=========
(1) These employees reside at the Holding Company at December 31, 2001.
The number of employees of PNM Resources, Inc. and its subsidiaries who
are represented by unions or other collective bargaining groups include (i)
Electric Services, 213; (ii) Gas Services, 87; and (iii) Generation and Trading
Operations, 339.
ITEM 2. PROPERTIES
ELECTRIC
The Company's ownership and capacity in electric generating stations in
commercial service as of December 31, 2001, were as follows:
Total Net
Generation
Capacity
Type Name Location (MW)
- -------------- ----------------- --------------------------- -------------
Coal........ SJGS (a) Waterflow, New Mexico 765
Coal........ Four Corners (b) Fruitland, New Mexico 192
Gas/Oil..... Reeves Albuquerque, New Mexico 154
Gas/Oil..... Las Vegas Las Vegas, New Mexico 20
Nuclear..... PVNGS (c) 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 has a long term PPA for the rights to all output of a gas
fired generating plant with maximum dependable capacity of 132 MW.
16
(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.
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
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 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.
17
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 all 38 indicators green
(the best possible 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
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.
APS, the Company and the other PVNGS participants are currently
considering issues related to the potential replacement of the steam generators
in Units 1 and 3. Although a final determination of whether Units 1 and 3 will
require steam generator replacements to operate over their current full licensed
lives has not yet been made, the Company and the other participants have
approved an expenditure of $25.6 million (of which the Company's share is $2.6
million) in 2002 and 2003 to procure long lead-time materials for fabrication of
a spare set of steam generators for either Unit 1 or 3. This action will provide
the PVNGS participants an option to replace the steam generators at either Unit
1 or 3 as early as fall 2005 should they ultimately choose to do so. If the
participants decide to proceed with steam generator replacement at both Units 1
and 3, the Company has estimated that its portion of the fabrication and
installation costs and associated power uprate modifications would be
approximately $47 million over the next five years.
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 an 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
18
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 the 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 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 in 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. 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 $181 million (in 1998 dollars).
The Company funded an additional $6.1 million, $3.9 million and $3.1
million in 2001, 2000 and 1999, respectively, into the qualified and
non-qualified trust funds. The estimated market value of the trusts at the end
of 2001 was approximately $57 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
19
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 has filed 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 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 domestic power reactors. The NRC, pursuant to the Waste Act,
requires operators of nuclear power reactors to enter into spent fuel disposal
contracts with the DOE. Under the Waste Act, the DOE was to develop 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 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 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 11 of Notes to the Consolidated Financial
Statements in Item 8 for a discussion of interim spent fuel storage costs).
On February 15, 2002, the President of the United States approved a
recommendation of the Secretary of Energy that the Yucca Mountain site in
Southern Nevada be developed for the storage of nuclear spent fuel. The State of
Nevada has opposed this site selection and the Company anticipates that there
will be a protracted process to address the Yucca Mountain issues. The Company
cannot predict the ultimate outcome of this process.
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 approximately 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.
20
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
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.
Aspects of the Federal law referred to above (the "Price-Anderson Act"),
which provides for payment of public liability claims in case of a catastrophic
accident involving a nuclear power plant, is up for renewal in August 2002.
While existing nuclear power plants would continue to be covered in any event,
the renewal would extend coverage to future nuclear power plants and could
contain amendments that would affect existing plants. A renewal bill was passed
by the House with unanimous consent on November 27, 2001. The House proposed a
change in the annual retrospective premium limit from $10 million to $15 million
per reactor per incident. Additionally, the House proposed to amend the maximum
potential assessment from $88.1 million to $98.7 million per reactor per
incident, taking into account effects of inflation. On March 7, 2002 the Senate
approved a Price-Anderson Act amendment as a part of the overall energy bill.
The Senate version is substantially the same as the Price-Anderson Act in its
current form. In the event the energy bill does not pass, it is possible that
the Price Anderson amendment will be passed as a stand-alone bill. In a report
issued in 1998, the NRC had made a number of recommendations regarding the
Price-Anderson Act, including a recommendation 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 renew the Price-Anderson Act or act
on the NRC's recommendations. However, if adopted, certain changes in the law
could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases,
absent waiver by the lessors. Such an occurrence could require the Company to,
among other things, (i) pay the lessor and the equity investor, in return for
the investor's interest in PVNGS, cash in the amount as provided in the lease
and (ii) assume debt obligations relating to the PVNGS lease (see "Sale and
Leaseback Transactions of PVNGS Units 1 and 2" above).
21
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, 2002, 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 $4.8 million per
year.
Other Electric Properties
As of December 31, 2000, the Company owned, jointly owned or leased 2,890
circuit miles of electric transmission lines, 4,488 miles of distribution
overhead lines, 3,741 cable miles of underground distribution lines (excluding
street lighting) and 222 substations.
The Company and 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 COA, and an
office building in Albuquerque. The purchase price was $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. On February 28, 2001, the second phase relating to the
transmission assets was completed and the Company acquired ownership of the
transmission assets.
NATURAL GAS
The natural gas properties as of December 31, 2001, 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 1,465 miles of pipe with appurtenant compression
facilities. The distribution systems consisted of approximately 11,121 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 areas throughout its service territory.
22
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 those 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 and the petition was
denied. In addition, the Arizona Supreme Court issued a decision in September
2000 affirming the lower court's criteria for resolving groundwater claims. APS
and other parties filed motions for reconsideration on one aspect of that
decision. Those motions have been denied by the Arizona Supreme Court. APS and
other parties petitioned the United States Supreme Court for review of the
Arizona Supreme Court's decision affirming the lower court's criteria for
resolving groundwater claims, and that petition was denied. 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.
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
23
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. 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 scope of tribal authority
over reservations. 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. The Company as a participant in Four Corners and
as operating agent and joint owner of SJGS, and owners of other facilities
located on other reservations located in New Mexico, filed appeals to contest
the EPA's authority under the regulations.
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 the EPA of tribal authority under the Clean Air Act. The
Company filed a petition for writ of certiorari to the United States Supreme
Court, which was denied on April 16, 2001. The Company does not expect any
immediate impacts as a result of this decision but will continue to monitor
developments with the Navajo Nation and the EPA.
On October 30, 2001, the DC Circuit issued its opinion granting the
Company's appeal concerning the federal operating permits. The Court remanded
the proceeding to the EPA for a new rulemaking on the EPA's authority to issue
federal operating permits in areas in which status as Indian Country may be in
dispute. The United States did not file a petition for rehearing in the appeal.
The Company will continue to monitor developments in connection with the remand
of this appeal and cannot predict the outcome of this matter.
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 the "Company," for
purposes of this discussion), by purportedly failing to properly measure natural
24
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. On May 18, 2001, the Wyoming court denied defendants' motion to
dismiss the complaint. A motion has been filed by the plaintiff asking the court
to hold a conference to schedule further procedural steps, but no such
conference has yet been set.
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.
Quinque Operating Co. et al. v. Gas Pipelines, et al
A class action lawsuit against several hundred defendants, including
the Company, formerly captioned as Quinque Operating Co. et al. v. Gas
Pipelines, et al., C.A. No. 99-CV-30, now captioned as Will price et al., v. Gas
Pipelines et al., 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.
On January 23, 2002, the plaintiffs filed a Notice of Dismissal with the
Kansas court dismissing all claims against the Company without prejudice.
KAFB CONTRACT
In 1999, 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 date that 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 October 1, 1999, WAPA filed a petition
requesting the FERC, on an expedited basis, to order the Company to provide
network transmission service to WAPA on behalf of DOE and several other entities
located on KAFB under the Company's Open Access Transmission Tariff. The
petition claimed KAFB is a wholesale customer of the Company, not a retail
customer. By order entered on April 13, 2001 the FERC denied the WAPA
transmission application. The FERC order determined, among other things, that
WAPA had failed to demonstrate that its sales to DOE are sales for resale and
also that WAPA failed to qualify for certain claimed exemptions under the
Federal Power Act that would have entitled it to provide expanded service to
DOE. WAPA requested rehearing of FERC's April 13, 2001 order.
25
In a proposed order issued on June 13, 2001, FERC granted WAPA's request
for rehearing. FERC determined that WAPA qualified for an exemption to the
prohibition against an order requiring service to retail customers and that FERC
therefore could require the Company to provide the requested service. FERC
directed the Company and WAPA to engage in negotiations concerning rates, terms
and conditions of service, including compensation. On January 18, 2002, the
parties submitted a settlement agreement resolving most of the issues relating
to the rates, terms and conditions of service. The partial settlement reserved
one issue for FERC decision or further proceedings. The reserved issue relates
to whether WAPA is entitled to a credit against payments for transmission
service for certain facilities located near KAFB. The June 13 order is a
"proposed" order, and is not subject to requests for rehearing or judicial
review. FERC may establish terms and conditions in a "final" order that would be
subject to requests for rehearing and to judicial review. The settlement
agreement filed at FERC on January 18, 2002 reserves the Company's rights to
seek rehearing and judicial review of any final order and to present other legal
claims. On February 14, 2002, the FERC administrative judge who supervised the
negotiations leading to the partial settlement recommended that FERC approve the
settlement. The Company is evaluating its legal options in relation to the
"proposed" order or any resulting "final" order.
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 and KAFB continues to purchase
retail service pending resolution of all relevant issues. The PRC case has been
held in abeyance, pending the outcome of the FERC proceeding.
AVISTAR SEVERANCE
When the Company sold its water utility assets to the City of Santa Fe
("City") in 1995, the parties also entered into a Maintenance and Operations
Agreement ("Agreement"), agreeing that the City would offer employment to the
water utility employees when the Agreement expired. The Agreement was assigned
to Avistar, Inc., and it expired in July 2001. The City assumed all maintenance
and operations, and offered employment to the employees.
Because the employees would continue performing the same jobs at the same
location(s), the Company had previously excluded the non-union employees from
eligibility for severance benefits under the Company's non-union severance
plans. Similarly, the IBEW Local 611 had been on notice that the Company had
negotiated for the continued employment of the IBEW-represented employees,
making them ineligible for severance benefits under Article 24 of the Collective
Bargaining Agreement ("CBA") between the Company and the IBEW.
In July 2001, the Agreement ended, and most of the water operations
employees accepted employment with the City. However, on March 27, 2001, the
IBEW began an internal grievance claiming that about twenty-eight represented
employees now employed by the City are nonetheless eligible for severance
benefits under Article 24 of the CBA. The Company has denied their eligibility.
Local 611 has demanded arbitration of the dispute under the CBA. The Company is
unaware of an arbitration date being scheduled. Local 611 seeks to ensure that
all laid-off employees receive severance benefits as provided for in Article 24.
The Company is evaluating its options, and the parties are pursuing informal
settlement discussions pending the selection of an arbitrator. The Company is
unable to predict the outcome of this matter.
26
WESTERN RESOURCES
On November 9, 2000, the Company and Western Resources announced that
both companies' Boards of Directors approved an agreement under which the
Company would acquire the Western Resources electric utility operations in a
tax-free, stock-for-stock transaction. The agreement required that Western
Resources split-off its non-utility businesses to its shareholders prior to
closing.
In July, 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for $151 million increase. After rehearing the KCC established the rate
decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001 in New York state court
seeking declarations that the transaction could not be accomplished as designed
due to the KCC's determination that the split-off condition of the transaction
is unlawful; that the Company is not obligated to pursue approvals of the
transaction as designed; that the transaction is terminated effective December
31, 2001, without an automatic extension; and that the KCC rate case order
constitutes a material adverse effect under the agreement. The Company also
seeks monetary damages for breach of contract because Western Resources
represented and warranted that the split-off did not require approval of the
KCC.
On November 19, 2001, Western Resources filed a complaint against the
Company in New York state court alleging breach of contract and breach of
implied covenant of good faith and fair dealing. Western Resources alleged that
the Company brought about the KCC orders, failed to assist in efforts to reverse
the KCC orders, refused to renegotiate within the terms of the agreement,
interfered with Western Resources's efforts to satisfy the terms of the
agreement, and effected an unauthorized de facto termination of the agreement by
filing its complaint. Western Resources alleges damages in excess of $650
million. The Company believes that the complaint filed by Western Resources is
without merit and intends to vigorously defend itself against the complaint. The
Company also intends to vigorously pursue its own complaint.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect.
27
On February 5, 2002, the District Court for Shawnee County, Kansas,
dismissed without prejudice Western Resources' appeal of the KCC's split-off
orders. The Court ruled that, by filing a new financial plan in compliance with
the orders, Western Resources accepted certain portions of the orders thereby
creating a situation where further administrative action became necessary. As a
result, the Court concluded that the matter was not ripe for judicial review and
remanded the case to the KCC.
On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate
order.
The Company is unable to predict the ultimate outcome of its litigation
with Western Resources.
REEVES STATION ENVIRONMENTAL MATTERS
On August 15, 2001, the COA Air Quality Division of the Environmental
Health Department issued a Notice of Violation to the Company, alleging that in
the period of March 10, 1998 through June 30, 2001, the Company had exceeded the
pound-per-hour NOx limitations in the operating permit for the Reeves Station.
The Company was assessed a proposed penalty in the amount of $1.8 million. The
Company disagreed with the alleged violations and entered into discussions with
the COA to attempt to achieve a resolution of the matter. The parties have
entered into a settlement agreement that resolves the matter without the
admission of liability by the Company. The Company's consolidated financial
statements for the year ended December 3, 2001 reflect this settlement
agreement.
28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF PNM RESOURCES
Executive officers, their ages, offices held with PNM Resources as
follows on December 31, 2001:
Name Age Office Initial Effective Date
---- --- ------ ----------------------
J. E. Sterba............ 46 Chairman, President and Chief Executive
Officer December 31, 2001
R.J. Flynn.............. 59 Executive Vice President, Electric and Gas
Services December 31, 2001
W.J. Real............... 53 Executive Vice President, Power Production
and Marketing December 31, 2001
B. L. Barsky............ 57 Senior Vice President, Communications Investor
Services and Community Relations December 31, 2001
M. D. Christensen*...... 53 Senior Vice President, Enterprise Solutions December 31, 2001
A. A. Cobb.............. 54 Senior Vice President, Peoples Services and
Development December 31, 2001
M. H. Maerki............ 61 Senior Vice President and Chief Financial Officer
and President and Chief
Executive Officer, Avistar, Inc. December 31, 2001
P. T. Ortiz............. 51 Senior Vice President, General Counsel
and Secretary December 31, 2001
E. Padilla, Jr.......... 48 Senior Vice President, Bulk Power
Marketing and Development December 31, 2001
R. B. Ridgeway.......... 43 Senior Vice President, Energy Services December 31, 2001
J. R. Loyack............ 38 Vice President, Corporate Controller and Chief
Accounting Officer December 31, 2001
(See Public Service Company of New Mexico on pages 30-31 for prior year
positions held).
- ---------------------
All officers are elected annually by the Board of Directors of the Company.
* As of February 4, 2002, M.D. Christensen stepped down as Senior Vice
President of Enterprise Solutions as a result of the dissolution of
Enterprise Solutions.
29
EXECUTIVE OFFICERS OF PUBLIC SERVICE COMPANY OF NEW MEXICO
Executive officers, their ages, offices held with Public Service Company
of New Mexico in the past five years and initial effective dates thereof, except
as otherwise noted:
Name Age Office Initial Effective Date
---- --- ------ ----------------------
J. E. Sterba........... 46 Chairman, President and Chief Executive October 1, 2000
Officer
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............ 59 Executive Vice President, Electric and Gas
Services January 18, 1999
Senior Vice President, Electric Services December 1, 1994
W. J. Real............. 53 Executive Vice President, Power Production and
Marketing January 18, 1999
Senior Vice President, Gas Services December 6, 1994
B. L. Barsky........... 57 Senior Vice President, Communications Investor
Services and Community Relations July 3, 2001
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
M. D. Christensen*..... 53 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
30
Name Age Office Initial Effective Date
---- --- ------ ----------------------
A. A. Cobb............. 54 Senior Vice President, Peoples Services and
Development September 11, 2001
Global Human Resources Officer,
Clientlogic November 22, 1999
Executive Vice President, Human Resources,
Aames Financial February 2, 1999
Senior Vice President, Human Resources,
Aames Financial November 1, 1996
M. H. Maerki........... 61 Senior Vice President and Chief Financial Officer,
and President and Chief Executive Officer,
Avistar, Inc. September 14, 2001
Senior Vice President and Chief Financial Officer December 7, 1993
P. T. Ortiz............ 51 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
E. Padilla, Jr......... 48 Senior Vice President, Bulk Power Marketing and
Development February 8, 2000
Vice President, Bulk Power Marketing and
Development December 14, 1996
R. B. Ridgeway......... 43 Senior Vice President, Energy Services September 14, 2001
Senior Vice President and President and Chief
Operating Officer, Avistar August 11, 1999
Senior Vice President, Energy Services December 14, 1996
Vice President, Corporate Planning August 10, 1996
J. R. Loyack........... 38 Vice President, Corporate Controller and Chief
Accounting Officer July 19, 1999
Director, Financial Reporting,
Union Pacific Corporation October 1, 1998
Senior Manager, Business Analysis,
Union Pacific Corporation January 1, 1996
- ---------------------
All officers are elected annually by the Board of Directors of PNM.
* As of February 4, 2002, M.D. Christensen stepped down as Senior Vice
President of Enterprise Solutions as a result of the dissolution of
Enterprise Solutions.
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 and its predecessor's common stock,
reported as composite transactions (Symbol: PNM), and dividends declared on the
common stock for 2001 and 2000, by quarters, are as follows:
Range of
Quarter Ended Sales Prices
--------------- -------------------------- Dividends
High Low Per Share
-------------------------- ------------
2001
December 31 ................ 28 17/25 24 7/20 $0.20
September 30 ............... 33 11/20 24 18/25 0.20
June 30 .................... 37 4/5 28 7/10 0.20
March 31 ................... 29 7/20 22 7/8 0.20
-----
Fiscal Year .............. 37 4/5 22 7/8 $0.80
=====
2000
December 31 ................ 28 5/16 203/4 $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
=====
On December 31, 2001, the Company's Board of Directors ("Board") declared
a quarterly cash dividend of 20 cents per share of common stock payable
February 15, 2002, to shareholders of record as of February 4, 2002.
On January 31, 2002, there were 15,389 holders of record of the Company's
common stock.
See Management's Discussion and Analysis of Results of Operations and
Financial Condition - "Liquidity and Capital Resources - Dividends," for a
discussion on the payment of future dividends.
32
Cumulative Preferred Stock
While isolated sales of PNM's cumulative preferred stock have occurred in
the past, PNM is not aware of any active trading market for its cumulative
preferred stock. Quarterly cash dividends were paid on PNM's cumulative
preferred stock at the stated rates during 2001 and 2000.
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.
2001 2000 1999 1998 1997
------------- ------------- ------------- ------------ -------------
(In thousands except per share amounts and ratios)
Total Operating Revenues............................. $2,352,098 $1,611,274 $1,157,543 $1,092,445 $1,020,521
Earnings from Continuing Operations.................. $ 150,433 $ 100,946 $ 79,614 $ 95,119 $ 86,497
Net Earnings......................................... $ 150,433 $ 100,946 $ 83,155 $ 82,682 $ 80,995
Earnings per Common Share:
Continuing Operations.............................. $ 3.83 $ 2.54 $ 1.93 $ 2.27 $ 2.05
Basic.............................................. $ 3.83 $ 2.54 $ 2.01 $ 1.97 $ 1.92
Diluted............................................ $ 3.77 $ 2.53 $ 2.01 $ 1.95 $ 1.91
Cash Flow Data:
Net cash flows provided from operating activities.. $ 324,995 $ 240,947 $ 213,045 $ 210,988 $ 213,122
Net cash flows used in investing activities........ $ (407,014) $ (158,932) $ (55,886) $ (340,992) $ (182,067)
Net cash flows generated (used)
by financing activities......................... $ 385 $ (94,723) $ (98,040) $ 173,089 $ (33,112)
Total Assets......................................... $2,934,638 $2,894,233 $2,723,268 $2,668,603 $2,407,410
Long-Term Debt, including current maturities......... $ 953,884 $ 953,823 $ 988,489 $1,008,614 $ 714,345
Common Stock Data:
Market price per common share at year end.......... $ 27.950 $ 26.813 $ 16.250 $ 20.438 $ 23.688
Book value per common share at year end............ $ 25.87 $ 23.64 $ 21.79 $ 20.63 $ 19.26
Average number of common shares outstanding........ 39,118 39,487 41,038 41,774 41,774
Cash dividend declared per common share............ $ 0.80 $ 0.80 $ 1.00 $ 0.60 $ 0.68
Return on Average Common Equity.................... 14.8% 11.1% 9.5% 9.9% 10.2%
Capitalization:
Common stock equity................................ 50.8% 48.6% 46.7% 45.4% 52.6%
Preferred stock without mandatory redemption
Requirements..................................... 0.6 0.7 0.7 0.7 0.8
Long-term debt, less current maturities............ 48.6 50.7 52.6 53.9 46.6
------------- -------------- ------------- ------------- -------------
100.00% 100.00% 100.00% 100.00% 100.00%
============= ============== ============= ============= =============
(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 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 Management's Discussion and Analysis of Financial Condition and
Results of Operations for PNM Resources, Inc. (the "Company") and Public Service
Company of New Mexico ("PNM") is presented on a combined basis. The Company as
an unconsolidated holding company ("Holding Company") had no material operations
for the year ended December 31, 2001. Except for its consolidated investment in
PNM, the Holding Company's only assets were cash of $11 million, short-term
investments of $10 million and long-term investments of $106 million at December
31, 2001. In addition, the Holding Company had no liabilities at December 31,
2001. Accordingly, the reader of this Management's Discussion and Analysis of
Financial Condition and Results of Operations should assume that the information
presented applies to consolidated results of operations and financial position
of both the Company and PNM, except where the context or references clearly
indicate otherwise. Discussions regarding specific contractual obligations
generally reference the company that is legally obligated. In the case of
contractual obligations of PNM, these obligations are consolidated with the
Company under Generally Accepted Accounting Principles. Broader operational
discussion references the Company.
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. Trends and contingencies of a material nature are
discussed to the extent known and considered relevant.
OVERVIEW
The Company is an investor-owned holding company of energy and energy
related companies. Its principal subsidiary, PNM, is an integrated public
utility primarily engaged in the generation, transmission, distribution and sale
and trading of electricity; transmission, distribution and sale of natural gas
within the State of New Mexico and the sale and trading of electricity in the
Western United States. The Company's principal business segments are Utility
Operations, which include Electric Services ("Electric") and Gas Services
("Gas"), and Generation and Trading Operations ("Generation and Trading").
Electric consists of two major business lines that include distribution and
transmission. The transmission business line 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 business line. The
Company's wholly-owned subsidiary, Avistar, Inc. ("Avistar"), provides
unregulated energy services.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Company, the Company became the parent company of PNM. Prior
to the share exchange, the Company had existed as a subsidiary of PNM. The new
holding company began trading on the New York Stock Exchange under the same PNM
symbol beginning on December 31, 2001.
COMPETITIVE STRATEGY
The Company is positioned as a "merchant utility," primarily operating as
a regulated energy service provider also engaged in the sale and trading of
electricity in the competitive energy market place. As a utility, the Company
has an obligation to serve its customers under the jurisdiction of the New
Mexico Public Regulation Commission ("PRC"). As a merchant, the Company markets
34
excess production from the utility, as well as, unregulated generation and its
purchases for resale into a competitive market place. The merchant operations
utilize an asset-backed trading strategy, whereby the Company's aggregate net
open position for the sale of electricity is covered by the Company's excess
generation capabilities. The benefits of the merchant operations are shared with
retail customers based on a negotiated settlement in proportion to capacity
owned, expended effort, and risk assumed. Non-regulated assets may be part of
the utility company or owned by an affiliate of the utility company, which could
be a subsidiary of the holding company. Currently, all non-regulated assets,
except Avistar, are part of the utility. Both retail customers and shareholders
benefit from this combination.
The Electric and Gas Services strategy is directed at supplying
reasonably priced and reliable energy to retail customers through customer
driven operational excellence, quality processes, and improved overall
organizational performance.
The Generation and Trading strategy calls for increased asset-backed
trading and generation capacity supported by long-term contracts, as well as
improved risk management strategies. The Company's plans to increase generation
calls for approximately 50% of its wholesale activity to be committed through
long-term contracts, including its sales to jurisdictional customers. Such
growth will be dependent on market developments, and upon the Company's ability
to generate funds for the Company's expansion.
(Intentionally left blank)
35
RESULTS OF OPERATIONS
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Consolidated
The Company's net earnings available to common shareholders for the year
ended December 31, 2001 were $149.8 million, a 49.3% increase over net earnings
of $100.4 million in 2000. This increase reflects strong market pricing in the
Western United States in the first half of 2001 and continuing growth in utility
operations. Earnings in both 2001 and 2000 were affected by certain special
gains and non-recurring charges. These special items are detailed in the
individual business segment discussions below. The following table enumerates
these special gains and non-recurring charges and shows their effect on diluted
earnings per share, in thousands, except per share amounts.
2001 2000
------------------------ -------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
------------ ----------- ------------ ------------
(Income)/Expense
Net Earnings Available for Common
Shareholders.................................. $149,847 $3.77 $100,360 $2.53
------------ ----------- ------------ ------------
Adjustment for Special Gains and Charges
(net of income tax effects):
Contribution to PNM Foundation................. 3,021 0.08 - -
Nonrecoverable coal
mine decommissioning costs................... 7,840 0.20 - -
Write-off of Avistar investments............... 7,907 0.20 - -
Settlement of lawsuit.......................... - - (8,306) (0.21)
Resolution of two gas rate cases............... - - (2,808) (0.07)
Impairment of certain
tax related regulatory assets................ - - 6,552 0.16
Costs for the acquisition of long-term
wholesale customer........................... - - 2,740 0.07
Western Resources acquisition costs............ 10,859 0.27 4,047 0.10
------------ ----------- ------------ ------------
Total........................................ 29,627 0.75 2,225 0.05
------------ ----------- ------------ ------------
Net Earnings Available For Common
Shareholders Excluding Special Gains
and Charges................................... $179,474 $4.52 $102,585 $2.58
============ =========== ============ ============
To adjust reported net earnings and diluted earnings per share to exclude
the special gains and non-recurring charges, special gains, net of income tax
expense, are subtracted from reported net earnings under Generally Accepted
Accounting Principles ("GAAP") and non-recurring charges, net of income tax
benefit, are added back to reported net earnings under GAAP.
36
The following discussion is based on the financial information presented
in the Consolidated Financial Statements - Segment Information note. The tables
below set forth the operating results for each business segment.
Year Ended December 31, 2001
Utility
---------------------------------- Generation
Electric Gas and Trading
--------------- --------------- ----------------
Operating revenues:
External customers....................... $ 559,226 $385,418 $1,405,916
Intersegment revenues.................... 707 - 341,608
--------------- --------------- ----------------
Total revenues........................... 559,933 385,418 1,747,524
--------------- --------------- ----------------
Cost of energy sold........................ 5,102 251,296 1,280,168
Intersegment purchases..................... 341,608 - 707
--------------- --------------- ----------------
Total cost of energy..................... 346,710 251,296 1,280,875
--------------- --------------- ----------------
Gross margin............................... 213,223 134,122 466,649
--------------- --------------- ----------------
Administrative and other costs............. 41,275 45,973 27,969
Energy production costs.................... 924 1,946 149,585
Depreciation and amortization.............. 32,666 21,465 42,766
Transmission and distribution costs........ 37,376 31,072 553
Taxes other than income taxes.............. 12,247 6,812 8,777
Income taxes............................... 27,264 5,957 82,629
--------------- --------------- ----------------
Total non-fuel operating expenses........ 151,752 113,225 312,279
--------------- --------------- ----------------
Operating income........................... $ 61,471 $20,897 $ 154,370
--------------- --------------- ----------------
Year Ended December 31, 2000
Utility
---------------------------------- Generation
Electric Gas and Trading
--------------- --------------- ----------------
Operating revenues:
External customers....................... $538,758 $319,924 $750,434
Intersegment revenues.................... 707 - 324,744
--------------- --------------- ----------------
Total revenues........................... 539,465 319,924 1,075,178
--------------- --------------- ----------------
Cost of energy sold........................ 5,048 195,334 749,499
Intersegment purchases..................... 324,744 - 707
--------------- --------------- ----------------
Total cost of energy..................... 329,792 195,334 750,206
--------------- --------------- ----------------
Gross margin............................... 209,673 124,590 324,972
--------------- --------------- ----------------
Administrative and other costs............. 38,975 37,963 27,355
Energy production costs.................... 1,208 1,485 137,202
Depreciation and amortization.............. 31,480 19,994 41,558
Transmission and distribution costs........ 33,092 27,206 30
Taxes other than income taxes.............. 13,819 8,295 11,219
Income taxes............................... 30,516 7,605 26,083
--------------- --------------- ----------------
Total non-fuel operating expenses........ 149,090 102,548 243,447
--------------- --------------- ----------------
Operating income........................... $60,583 $22,042 $81,525
--------------- --------------- ----------------
37
Year Ended December 31, 1999
Utility
---------------------------------- Generation
Electric Gas and Trading
--------------- --------------- ----------------
Operating revenues:
External customers....................... $540,868 $236,711 $371,109
Intersegment revenues.................... 707 - 318,872
--------------- --------------- ----------------
Total revenues........................... 541,575 236,711 689,981
--------------- --------------- ----------------
Cost of energy sold........................ 4,493 112,925 414,534
Intersegment purchases..................... 318,872 - 707
--------------- --------------- ----------------
Total cost of energy..................... 323,365 112,925 415,241
--------------- --------------- ----------------
Gross margin............................... 218,210 123,786 274,740
--------------- --------------- ----------------
Administrative and other costs............. 52,586 49,716 26,791
Energy production costs.................... 2,632 1,504 132,787
Depreciation and amortization.............. 30,183 19,210 41,183
Transmission and distribution costs........ 31,013 28,227 23
Taxes other than income taxes.............. 19,014 6,915 9,006
Income taxes............................... 24,451 2,112 6,951
--------------- --------------- ----------------
Total non-fuel operating expenses........ 159,879 107,684 216,741
--------------- --------------- ----------------
Operating income........................... $58,331 $16,102 $57,999
--------------- --------------- ----------------
Utility Operations
Electric - Operating revenues increased $20.5 million or 3.8% for the
period to $559.9 million. Retail electricity delivery grew 2.3% to 7.3 million
MWh in 2001 compared to 7.1 million MWh delivered in the prior year period,
resulting in increased revenues of $8.9 million year-over-year. This volume
increase was the result of load growth from economic expansion in New Mexico. In
addition, revenues from third party use of the Company's transmission system
increased $9.6 million as a result of additional contracts, while revenues also
benefited from a $1.1 million increase in revenue from property leasing.
The following table shows electric revenues by customer class and average
customers:
Electric Revenues
(Thousands of dollars)
2001 2000
------------ ------------
Residential.................... $187,600 $186,133
Commercial..................... 242,372 238,243
Industrial..................... 82,752 79,671
Other.......................... 47,209 35,418
------------ ------------
$559,933 $539,465
============ ============
Average Customers.............. 378,000 369,000
============ ============
38
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
2001 2000
---------- ----------
Residential..................... 2,198 2,172
Commercial...................... 3,213 3,134
Industrial...................... 1,603 1,544
Other........................... 241 239
---------- ----------
7,255 7,089
========== ==========
The gross margin, or operating revenues minus cost of energy sold,
increased $3.6 million, which reflects the increased energy sales, transmission
revenue and property leasing revenue, partially offset by higher cost for the
electricity sold to retail customers. Electric exclusively purchases power from
Generation and Trading at Company developed prices which are not based on market
rates. These intercompany revenues and expenses are eliminated in the
consolidated results.
Administrative and general costs increased $2.3 million or 5.9% for the
period. This increase is primarily due to increased pension and post-retirement
benefits expense resulting primarily from a reduction in expected investment
returns on plan assets. Consulting expenses focused on cost control and process
improvement initiatives also contributed to the increase. These increases were
partially offset by lower bad debt and collection expense. By December 2000, the
Company had resolved most of the problems associated with the implementation of
its new billing system. As a result bad debt expense was significantly lower in
2001.
Transmission and distribution costs increased $4.3 million or 12.9%
primarily due to a non-recurring increase in maintenance to improve reliability
for the transmission and distribution systems.
Taxes other than income decreased $1.6 million or 11.4% reflecting
favorable audit outcomes by certain tax authorities and tax planning strategies.
Gas - Operating revenues increased $65.5 million or 20.5% for the period
to $385.4 million. The Company purchases natural gas in the open market and
resells it at cost to its distribution customers. As a result, increased gas
revenues driven by increased gas costs do not impact the Company's gross margin
or earnings. The revenue increase was driven primarily by a 17.6% increase in
average gas prices in the first half of 2001, resulting from increased market
demand. In addition, a 3.1% volume increase and a gas rate increase, which
became effective October 30, 2000 contributed to the increase. The gas rate
increase added $7.8 million of revenue. Transportation volume increased 14.7% or
$6.1 million. This growth was primarily attributed to gas transportation
customers whose increased demand was driven by the strong power market in the
Western United States during the first half of 2001. This increase is not
expected to recur in 2002. Approximately $28.1 million of gas revenue in 2001
was attributable to the Company's Generation and Trading Operations and is
eliminated in the consolidated results.
39
The following table shows gas revenues by customer and average customers:
Gas Revenues
(Thousands of dollars)
2001 2000
----------- ------------
Residential......................... $232,321 $191,231
Commercial.......................... 68,895 52,964
Industrial.......................... 27,519 24,206
Transportation*..................... 20,188 14,163
Other............................... 36,495 37,360
----------- ------------
$385,418 $319,924
=========== ============
Average customers................... 443,000 435,000
=========== ============
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
2001 2000
---------- ----------
Residential.......................... 27,848 28,810
Commercial........................... 10,421 9,859
Industrial........................... 3,920 5,038
Transportation*...................... 51,395 44,871
Other................................ 4,355 6,426
---------- ----------
97,939 95,004
========== ==========
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
increased $9.5 million or 7.7%. This increase is due to the rate increase and
higher transportation volumes, which will likely not recur in 2002, as discussed
above.
Administrative and general costs increased $8.0 million or 21.1%. This
increase is due to increased pension and post-retirement benefits expense
resulting primarily from a reduction in expected investment returns on plan
assets, consulting expenses in connection with cost control and process
improvement initiatives, partially offset by decreased bad debt and collection
costs.
Depreciation and amortization increased $1.5 million or 7.4% for the
period due to a higher depreciable plant base.
Transmission and distribution costs increased $3.9 million or 14.2%
primarily due to a non-recurring increase in maintenance to improve reliability
for the transmission and distribution systems, as the Company continues to focus
on improving reliability and effectiveness of its retail distribution system.
40
Taxes other than income decreased $1.5 million or 17.9% due to favorable
audit outcomes by certain tax authorities and tax planning strategies.
Generation and Trading Operations
A spike in regional wholesale electric prices occurred in the first half
of 2001 and the second half of 2000. This spike was caused by the power
supply/demand imbalance in the Western United States, limited power generation
capacity and increased natural gas prices. The Company does not believe that the
high wholesale prices seen in 2001 and 2000 will recur in 2002. At the end of
the second quarter of 2001, the market experienced falling price levels. This
trend continued in the last half of 2001. As a result, market liquidity - the
opportunity to buy and resell power profitably in the marketplace - also
declined reflecting the bankruptcy of a major market trader and limited price
volatility. The Company believes that current weak market pricing is not
sustainable and that prices will adjust to more normal historical levels in the
second half of 2002.
Operating revenues grew $672.3 million or 62.5% for the period to $1.7
billion. This increase in wholesale electricity sales primarily reflects the
strong regional wholesale electric prices in the first half of 2001. The Company
delivered wholesale (bulk) power of 12.6 million MWh of electricity this period,
compared to 12.4 million MWh in the prior period. Wholesale revenues from
third-party customers increased from $750.4 million to $1.4 billion, an 87.3%
increase.
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
(Thousands of dollars)
2001 2000
----------------- ------------------
Intersegment sales................. $ 341,608 $ 324,744
Firm-requirements wholesale........ 24,754 15,540
Other wholesale sales*............. 1,381,162 734,894
----------------- ------------------
$ 1,747,524 $ 1,075,178
================= ==================
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
2001 2000
-------------- ---------------
Intersegment sales.................. 7,255,297 7,088,943
Firm-requirements wholesale......... 616,703 330,003
Other wholesale sales............... 11,960,397 12,022,125
-------------- ---------------
19,832,397 19,441,071
============== ===============
*Includes mark-to-market gains/(losses).
41
The gross margin, or operating revenues minus cost of energy sold,
increased $141.7 million or 43.6%. The Company's margins benefit significantly
from rising gas prices as most of the Company's generation portfolio is fueled
by stable priced fuel sources, such as coal and uranium. As the increase in gas
prices puts upward pressure on electricity prices, the profitability of the
Company's stable low-cost generation increases significantly. Margins also
benefited from the Company's power trading activities. The Company buys and then
resells electricity in the market generating incremental margin by taking
advantage of price changes in the electricity sales market. In addition, the
Company also tailors electric deliveries for its wholesale customers creating
incremental margin opportunities. Generally, as market prices decline, trading
volumes rise supporting margin levels in lower price electric markets. These
higher margins were partially offset by a year-over-year increase in unrealized
mark-to-market losses of $21.0 million which the Company recognized relating to
its power trading contracts.
Administrative and general costs increased $0.6 million or 2.2% for the
period. This increase is primarily due to increased pension and post-retirement
benefits expense, higher power marketing expenses of $1.0 million mainly for
additional incentive bonuses and certain consulting fees, and other expenses
related to business development and process improvement. This increase was
partially offset by lower year-over-year Generation and Trading business
development costs due to significant costs related to the acquisition of a
long-term wholesale customer.
Energy production costs increased $12.4 million or 9.0% for the year. The
increase is primarily due to higher maintenance costs in 2001 resulting from
scheduled and unscheduled outages at Palo Verde Nuclear Generating Station
("PVNGS"), San Juan Generating Station ("SJGS") and Reeves Generating Station
("Reeves"), additional incentive bonuses at SJGS, and increased generation at
Reeves, one of the Company's gas generation facilities, which has a higher cost
of production than the Company's coal and nuclear facilities. This increase was
partially offset by lower maintenance costs at Four Corners Power Plant ("Four
Corners") as a result of decreased outage time. A significant unscheduled outage
occurred in the fall of 2001 at SJGS. The Company took advantage of the outage
to accelerate its outage scheduled for the spring of 2002. As a result,
maintenance costs and the related lost market potential of the accelerated
outage will be avoided in the spring of 2002.
Depreciation and amortization increased $1.2 million or 2.9% for the
period due to a higher depreciable plant base.
Taxes other than income decreased $2.4 million or 21.8% as a result of
favorable audit outcomes by certain tax authorities and tax planning strategies.
Unregulated Businesses
In July 2001, the Board of Directors of Avistar decided to wind down all
unregulated operations except for Avistar's Reliadigm business unit, which
provides maintenance solutions and technologies to the electric power industry.
Avistar had previously divested itself of its Energy Partners business unit and
liquidated Axon Field Services and Pathways Integration. This divestiture was
largely in response to market disruptions caused by the California energy
crisis. In addition, the transfer of operation of the Sangre de Cristo Water
Company to the City of Santa Fe was completed in the third quarter. All
remaining non-Reliadigm investments were written-off with the exception of
Avistar's investment in Nth Power, an energy related venture capital fund. These
write-downs reflect the significant decline in the technology market and
bankruptcy of these investees. The Company recorded non-operating charges of
$13.1 million to reflect these activities and the impairment of its Avistar
investments.
42
Due to the cessation of much of Avistar's historic operations, business
activity declined significantly. Revenues decreased 30.8% for the period to $1.5
million. Operating losses for Avistar decreased from $4.6 million in the prior
year period to $4.2 million in the current year period primarily due to
decreased costs as a result of the shutdown of certain operations. In January
2002, Avistar was dividended to PNM Resources by PNM.
Corporate
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, decreased $1.4 million for
the period to $32.1 million. This decrease was due to lower bonus expense in
2001 and reorganizational costs incurred in 2000 that did not occur in 2001 due
to the delay in separating Utility Operations from Generation and Trading
Operations. These cost improvements were partially offset by higher legal costs
associated with routine business operations and increased pension and
post-retirement benefit expense.
Other Non-Operating Costs
Other income and deductions, net of taxes, decreased $41.3 million for
the period to a loss of $7.4 million. On a pre-tax basis in 2000, the Company
recognized gains of $13.8 million related to the settlement of a lawsuit, $4.5
million for the reversal of certain reserves associated with the resolution of
two gas rate cases and $2.4 million related to the Company's hedge of certain
non-qualified retirement plan trust assets. In the current year, the Company
recorded pre-tax charges of $13.1 million to write-off certain permanently
impaired Avistar investments and $13.0 million of non-recoverable coal mine
decommissioning costs previously established as a regulatory asset. The Company
will continue to evaluate the recoverability of regulatory assets as the rate
making process occurs and will identify its stranded costs, if any, when it
files its new transition plan that is due by January 1, 2005. The current year
results also include the following pre-tax items: a donation of $5.0 million to
the PNM Foundation; unrecoverable costs of $2.3 million related to an abandoned
transmission line expansion project; a year-over-year decrease in investment
income of $5.6 million on the PVNGS decommissioning trust assets; and increased
costs of $5.5 million related to the Company's terminated acquisition of Western
Resources' electric utility operations, partially offset by $3.4 million of
equity income from a passive investment. Total costs for the year ended December
31, 2001 related to the Company's terminated acquisition of Western Resources
were $18.0 million pre-tax. The Company has expensed all costs related to the
terminated transaction to date.
The Company's consolidated income tax expense was $81.1 million in the
twelve months ended December 31, 2001, an increase of $6.7 million for the year.
The impact of higher earnings was partially mitigated by the reversal of $6.6
million of valuation allowances taken against certain income tax related
regulatory assets in 2000 that the Company determined would continue to be
recoverable in rates largely due to the delay in the implementation of
deregulation. The Company's effective income tax rates for the years ended 2001
and 2000 were 35.02% and 42.41%, respectively. Excluding the impact of the
valuation reserve changes, the Company's effective income tax rates for the
years ended 2001 and 2000 were 37.85% and 38.67%, respectively. The decrease in
the effective rate was primarily due to the favorable tax treatment received on
the 2001 equity earnings discussed above.
43
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Consolidated
The Company's net earnings available to common shareholders for the year
ended December 31, 2000 were $100.4 million, a 22% increase over net earnings of
$82.6 million in 1999. This increase reflects strong market pricing in the
Western United States in the second half of 2000 and continuing growth in
utility operations. Earnings in both 2000 and 1999 were affected by certain
special gains and charges. These special items are detailed in the individual
business segment discussions below. The following table enumerates these special
gains and charges and shows their effect on diluted earnings per share, in
thousands, except per share amounts.
2000 1999
------------------------- --------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
------------ ------------ ------------- ------------
(Income)/Expense
Net Earnings Available for Common
Shareholders................................... $100,360 $2.53 $82,569 $2.01
------------ ------------ ------------ ------------
Adjustment for Special Gains and Charges
(net of income tax effects):
Settlement of lawsuit........................... (8,306) (0.21) - -
Resolution of two gas rate cases................ (2,808) (0.07) - -
Impairment of certain tax related
regulatory assets............................. 6,552 0.16 - -
Costs for the acquisition of long-term
wholesale customer............................ 2,740 0.07 - -
Western Resources acquisition costs............. 4,047 0.10 - -
Equity income from a passive investment......... - - (4,180) (0.10)
Mine closure activities......................... - - (1,227) (0.03)
Bad debt costs associated with system
implementation problems....................... - - 4,890 0.12
Cumulative effect of an accounting change....... - - (3,541) (0.09)
------------ ------------ ------------ ------------
Total.......................................... 2,225 0.05 (4,058) (0.10)
------------ ------------ ------------ ------------
Net Earnings Available For Common
Shareholders Excluding Special Gains
and Charges.................................... $102,585 $2.58 $78,511 $1.91
============ ============ ============ ============
To adjust reported net earnings and diluted earnings per share to exclude
the special gains and non-recurring charges, special gains, net of income tax
expense, are subtracted from reported net earnings under GAAP and non-recurring
charges, net of income tax benefit, are added back to reported net earnings
under GAAP.
44
Utility Operations
Electric - Operating revenues declined $2.1 million or 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
warm temperatures and load growth.
The following table shows electric revenues by customer class:
Electric Revenues
(Thousands of dollars)
2000 1999
------------ ------------
Residential..................... $186,133 $184,088
Commercial...................... 238,243 238,830
Industrial...................... 79,671 85,828
Other........................... 35,418 32,829
------------ ------------
$539,465 $541,575
============ ============
Average Customers............... 369,000 361,000
============ ============
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
2000 1999
---------- ----------
Residential...................... 2,172 2,028
Commercial....................... 3,134 2,982
Industrial....................... 1,544 1,559
Other............................ 239 235
---------- ----------
7,089 6,804
========== ==========
The gross margin, or operating revenues minus cost of energy sold,
decreased $8.5 million. This decline reflects the rate reduction discussed
above. Electric exclusively purchases power from Generation and Trading at
Company developed prices which are not based on market rates.
Administrative and general costs decreased $13.6 million or 25.9% 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
significant increases 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.
45
Energy production costs decreased $1.4 million or 54.1% for the year
primarily due to non-recurring Y2K compliance costs in 2000.
Depreciation and amortization increased $1.3 million or 4.3% 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.
Transmission and distribution costs increased $2.1 million or 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 continued in 2001.
Taxes other than income decreased $5.2 million or 27.3% due to a change
in the recognition of electric franchise fees collected from customers and
payable 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 in expected tax liabilities. Franchise fees were a part of the
Company's rate structure in 1999. In 2000, they were unbundled from the rate
structure. As a result, the Company now passes through directly to customers the
franchise fees charged by municipalities and does not incur expense or generate
revenues as a result of collecting the fees.
Gas - Operating revenues increased $83.2 million or 35.2% for the year to
$319.9 million. The Company purchases natural gas in the open market and resells
it at cost to its distribution customers. As a result, increased gas revenues
driven by increased gas costs do not impact the Company's gross margin or
earnings. The increase was driven by a 31.3% increase in gas prices in the later
months of 2000 as a result of increased market demand, a 3.0% volume increase.
The following table shows gas revenues by customer class:
Gas Revenues
(Thousands of dollars)
2000 1999
------------ -------------
Residential......................... $191,231 $152,266
Commercial.......................... 52,964 37,337
Industrial.......................... 24,206 8,550
Transportation*..................... 14,163 12,390
Other............................... 37,360 26,168
------------ -------------
$319,924 $236,711
============ =============
Average customers................... 435,000 426,000
============ =============
46
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
2000 1999
---------- ----------
Residential........................... 28,810 32,121
Commercial............................ 9,859 11,106
Industrial............................ 5,038 2,338
Transportation*....................... 44,871 40,161
Other................................. 6,426 6,538
---------- ----------
95,004 92,264
========== ==========
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
increased $0.8 million or 0.7%. This increase is due to higher retail customer
distribution volumes on which the Company earns cost of service revenues.
Administrative and general costs decreased $11.8 million or 23.6%. 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 Services
share the same billing system, and Gas Services experienced the same delinquency
problems discussed above in the "Electric" results of operations. As a result,
in 1999, the Company incurred additional bad debt costs of $2.1 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 or 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 or 3.6%
primarily due to non-recurring Y2K compliance costs.
Taxes other than income increased $1.4 million or 20.0% primarily due to
higher tax liabilities and the impact of the implementation of the new customer
billing system on the collection of certain taxes.
Generation and Trading Operations
Operating revenues grew $385.2 million or 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
47
prices which the Company does not believe to be sustainable in the long-term,
although these factors continued to affect markets in the first half of 2001.
The Company delivered wholesale (bulk) power of 12.4 million MWh 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 following table shows revenues by customer class:
Generation and Trading Operations Revenues By Market
(Thousands of dollars)
2000 1999
---------------- ---------------
Intersegment sales...................... $ 324,744 $ 318,872
Firm-requirements wholesale............. 15,540 7,046
Other wholesale sales*.................. 734,894 364,063
---------------- ---------------
$ 1,075,178 $ 689,981
================ ===============
The following table shows sales by customer class:
Generation and Trading Operations Sales By Market
(Megawatt hours)
2000 1999
-------------- ---------------
Intersegment sales...................... 7,088,943 6,803,583
Firm-requirements wholesale............. 330,003 179,249
Other wholesale sales................... 12,022,125 10,992,372
-------------- ---------------
19,441,071 17,975,204
============== ===============
*Includes mark-to-market gains/(losses).
The gross margin, or operating revenues minus cost of energy sold,
increased $50.2 million or 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 and unrealized mark-to-market losses of $4.8 million which the
Company recognized relating to its power trading contracts. These items were
recorded as revenue adjustments.
Administrative and general costs increased $3.6 million or 2.1% 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 and an increase in
bad debt costs, partially offset by non-recurring Y2K compliance costs and lower
legal costs related to a lawsuit settlement involving the Company's
decommissioning trust which was settled in August 2000. The settlement was
recorded as other income.
Energy production costs increased $4.4 million or 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.
48
Taxes other than income increased $2.2 million or 24.6% due to higher tax
liabilities.
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.
Corporate
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, increased $8.0 million for
the year to $33.5 million. 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 Non-Operating Costs
Other income and deductions, net of taxes, increased $4.2 million for the
year to $34.4 million due to certain special gains. The Company recognized on a
pre-tax basis $13.2 million related to the settlement of a lawsuit and $4.6
million before income taxes associated with the resolution of two gas rate
cases. The current year also had increased mark-to-market gains on the Company's
hedge of its investments for nuclear decommissioning and certain post retirement
benefits. These gains were partially offset by $6.7 million of costs related to
the Company's terminated Western Resources transaction. 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, on a pre-tax basis, of $4.2 million of equity
income from a passive investment and $2.0 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 42.41%. Included in the
Company's 2000 income tax expense is the write-off of $6.6 million of income
tax-related regulatory assets. Excluding the write-off of income tax-related
regulatory assets, the Company's effective tax rate was 38.67%. The Company's
1999 effective tax rate was 34.70%. The increase in the rate was primarily due
to the favorable tax treatment received on the 1999 equity earnings in other
income and deductions discussed above.
49
FUTURE EXPECTATIONS
Because of the wholesale market price decline in the Western United
States that began in the second half of 2001, the Company's 2002 earnings are
not expected to reach 2001 levels. On January 23, 2002, the Company announced
that it expects its 2002 earnings to be at the lower end of the previously
identified range of $3.00 to $3.50 per share. Wholesale prices in the West
currently remain at lower levels than the Company believes likely to prevail
through the remainder of 2002; however, the Company expects this reduced pricing
environment to continue through much of the first and second quarters. The
Company's view is based on a return to normal weather, a beginning of economic
recovery by summer and the reemergence of liquidity in the wholesale market that
was impacted by the bankruptcy of a major trader and credit quality reduction of
other market traders. Accordingly, the Company believes that the lower end of
the range, $3.00 per share in earnings, is achievable for 2002, and the first
quarter earnings are likely to be consistent with trends from the first quarter
in 2000. However, if wholesale prices in the West do not increase as forecasted
by the Company, the Company's earnings are likely to be lower than its
identified range of $3.00 to $3.50. The calculation of future expected earnings
is subject to numerous variables, including, on and off-peak wholesale demand,
retail load needs, natural gas prices, generating resource availability, the
current position of the Company's trading portfolio and general economic
conditions.
As a result of the reduced pricing environment, many generators have
announced the cancellation of previously planned projects. The Company expects
that forward prices will again move upwards in future periods as result of under
building. As the Company adds new generation resources, it is expected that
earnings will trend upwards as sales volumes grow. This growth is expected to be
in high single digits over the long-term. The Company's strategic plan to add
generation resources will provide electric wholesale volume growth beginning in
2002 and in the later years of the forecast.
This discussion of future expectations is forward looking information
within the meaning of Section 21E of the Securities Exchange Act of 1934. 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 that could cause the Company's actual financial results to differ
materially from the expected results enumerated above.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with GAAP requires
the Company to select and apply accounting policies that best provide the
framework to report the Company's results of operations and financial position.
The selection and application of those policies require management to make
difficult subjective or complex judgments concerning reported amounts of revenue
and expenses during the reporting period and the reported amounts of assets and
liabilities at the date of the financial statements. The judgments and
uncertainties inherent in this process affect the application of those policies.
As a result, there exists the likelihood that materially different amounts would
be reported under different conditions or using different assumptions.
Management has identified the following accounting policies that it deems
critical to the portrayal of the Company's financial condition and results and
that involve significant subjectivity. Management believes that its selection
and application of these policies best represent the operating results and
financial position of the Company. The following discussion provides information
on the processes utilized by management in making judgments and assumptions as
they apply to its critical accounting policies.
50
Revenue Recognition
The Company recognizes revenues in the period of delivery. The Company's
Utility Operations are required to estimate revenues for unbilled services when
its billing cycle does not match the calendar-end reporting period. Management's
estimates are based on models which utilize actual units delivered and the
applicable rate structure.
Utility Operation's gas operating revenues exclude adjustments for
differences in gas purchase costs that are above or below levels included in
base rates but are recoverable under the mechanism established by the PRC.
Utility Operations recognize this adjustment when it is permitted to bill under
PRC guidelines. Utility Operations, also, periodically hedge 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.
The Company enters into energy trading contracts to take advantage of
market opportunities associated with the purchase and sale of electricity.
Unrealized gains and losses resulting from the impact of price movements on
Generation and Trading Operations' contracts are recognized as adjustments to
Generation and Trading Operations operating revenues. These adjustments are
based on market prices that are actively quoted.
Financial Instruments
Under the derivative accounting rules and the related accounting rules
for energy trading activities, the Company accounts for its various financial
derivative instruments for the purchase and sale of energy differently based on
Management's intent when entering into the contract. Energy trading contracts
are recorded at fair market value at each period end. The changes in fair market
value are recognized in earnings. Non-trading contracts must be accounted for as
derivatives and recorded in the balance sheet as either an asset or liability
measured at their fair value. Changes in the derivatives' fair value are
recognized currently in earnings unless specific hedge accounting or normal
purchase and sale criteria are met. Should an energy transaction qualify as a
hedge, fair market value changes from period to period are recognized on the
balance sheet with a corresponding charge to other comprehensive income. Gains
or losses are recognized when the hedged transaction occurs. Normal purchases
and sales are not marked-to-market but rather recorded in results of operations
when the underlying transaction occurs.
The market prices used to value the Company's energy trading contracts
are based on closing exchange prices and over-the-counter quotations. As of
December 31, 2001, the Company does not have any outstanding contracts that were
valued using methods other than quoted prices. The Company did not change its
methods for valuing its trading contracts in 2001 as compared to 2000. The
Company recognized a $25.8 million loss related to its mark-to-market adjustment
in 2001. This represents the net change in the Company's mark-to-market
51
adjustment for its trading contracts from December 31, 2000 to December
31, 2001. The following table summarizes the Company's trading portfolio at
December 31 (in thousands):
2001 2000
-------------- --------------
Face value of contracts................... $(41,193) $ (6,314)
Market value of contracts................. (10,753) (1,672)
-------------- --------------
Mark-to-market loss....................... $(30,440) $ (4,642)
============== ==============
The trading portfolio positions at December 31, 2001 and 2000 represent
net liabilities after netting all open purchase and sale contracts. Because the
contractual amounts required to settle the net liability were greater than the
current market values of the contracts, the Company recognized mark-to-market
losses for the differences in 2001 and 2000.
As of December 31, 2001, a decrease in market pricing of the Company's
trading contracts by 10% would have resulted in a decrease in net earnings of
less than 1%. Conversely, an increase in market pricing of the Company's trading
contracts by 10% would have resulted in an increase in net earnings of less than
1%.
At December 31, 2001, the market value of the Company's normal sales
and purchases of electricity was a $1.7 million liability using the valuation
methods described above. If these transactions were classified as trading or did
not meet the definition of normal under the accounting rules for derivatives,
the Company would have recognized unrealized gains of $18.2 million as an
adjustment to Generation and Trading Operations operating revenues based on the
change in fair value of these contracts from January 1, 2001 to December 31,
2001.
In addition to the fair market valuation described above, the Company
provides for losses due to market and credit risk in the electric wholesale
marketplace based on its assessment of counterparty default risk. This
assessment is based on a methodology that considers the credit ratings of the
Company's counterparties, the price volatility in the marketplace, the fair
market value of all contracts outstanding and management's evaluation of market
trends that are expected to impact market risk. The resulting amount is recorded
as an adjustment to revenue. Increases in market prices, increases in an
individual counterparty's credit position and general economic conditions which
may impact the credit ratings of the Company's counterparties will generally
result in an increased market volatility and credit risk and a corresponding
reduction to revenues.
Regulatory Assets and Liabilities
The accounting rules for rate regulated entities require a company to
reflect the effects of regulatory decisions in its financial statements. In
accordance with these accounting rules, the Company has deferred certain costs
that are rate recoverable and recorded certain liabilities for amounts to be
returned to retail customers pursuant to the rate actions of the PRC and its
predecesor and the Federal Energy Regulatory Commission ("FERC"). Substantially
all of the Company's regulatory assets and regulatory liabilities are reflected
in rates charged to retail customers or have been addressed in a regulatory
proceeding. To the extent that management concludes that the recovery of a
regulatory asset is no longer probable due to changes in 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 currently has
fixed electricity rates for jurisdictional service purposes until January 2003.
If the present rates were materially reduced, management would need to
re-evaluate the recoverability of its regulatory assets. If management were to
determine that the new rate structure would not be sufficient to recover these
regulatory assets, the Company would be required to record a charge for the
portion of the costs that were not recoverable.
The Company has discontinued the application of regulatory accounting as
of December 31, 1999, for the generation portion of its business effective with
the passage in New Mexico of the Electric Utility Industry Restructuring Act of
1999. The Company evaluates these assets under the same impairment rules that it
uses to evaluate tangible long-lived assets. In 2001, the Company determined
certain costs would not be recovered and recorded a charge of $13.1 million 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, or in
52
future rate cases prior to implementation of customer choice. If management were
to determine that the expected non-bypassable charge or other rate treatment
would not be sufficient to recover these costs, the Company would be required to
record a charge to earnings for that portion of the costs that were not
recoverable.
Asset Impairment
The Company regularly evaluates the carrying value of its tangible
long-lived assets in relation to their future undiscounted cash flows to assess
recoverability in accordance with accounting rules. Impairment testing of power
generation assets is performed periodically in response to changes in market
conditions resulting from industry deregulation and other market trends. 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 as prescribed by current GAAP. The Company's
estimate of future undiscounted cash flows is based on its assumptions of future
market trends for the price of electricity such as demand, pricing and
volatility. Adverse developments in the wholesale electricity market that lead
to less favorable assumptions about future market trends could result in an
impairment of the Company's power generation assets.
Contingent Liabilities
There are various claims and lawsuits pending against the Company and
certain of its subsidiaries. The Company has recorded a liability where the
effect of litigation can be estimated and where an outcome is considered
probable. Management's estimates are based on its knowledge of the relevant
facts at the time of the issuance of the Company's Consolidated Financial
Statements. Subsequent developments could materially alter management's
assessment of a matter's probable outcome and the estimate of the Company's
liability.
Environmental Issues
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
53
site using currently available information, including existing technology,
current 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).
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2001, the Company had cash and short-term and long-term
investments of $176.8 million compared to $107.7 million in 2000. The Company's
long-term investments are highly liquid though its intent is to hold them longer
than one year.
Cash provided from operating activities in the year ended December 31,
2001 was $325.0 million, an increase of $84.0 million from 2000. This increase
was primarily the result of increased profitability. Contributing to this
increase was the recovery of the cost of purchased gas from utility customers
deferred in accordance with PRC regulations. In addition, the Company was not
required to make the first quarter 2001 estimated federal income tax payment
because of an automatic extension granted by the IRS to taxpayers in several
counties in New Mexico as a result of wildfires in 2000. This payment was made
in January 2002. Partially offsetting these cash inflows was the impact of lower
wholesale electric and gas prices at year end 2001, resulting in a decrease in
accounts payable; however, these same price decreases led to an offsetting
decrease in accounts receivable. This market effect resulted in a net cash
outflow of $60.5 million, year-over-year.
Cash used for investing activities was $407.0 million in 2001 compared to
$158.9 million in 2000. This increase reflects the movement of $150.0 million of
cash to investments with longer maturities, ranging from one to three years, and
greater yields. In addition, cash used for investing activities includes
construction expenditures related to the Company's announced new generating
plants of $103.4 million in 2001 compared to $13.0 million for similar
expenditures in 2000 and expenditures of $14.0 million in 2001 related to the
acquisition of certain transmission assets and other related investing
activities compared to $5.8 million for similar expenditures in 2000. The
Company continues to make significant investments in its generation portfolio.
Cash generated by financing activities was $0.4 million compared to $94.7
million of cash used in 2000. Financing activities in 2001 were primarily
short-term borrowings for liquidity reasons, offset by cash payments for
dividend requirements. The use of cash in 2000 reflects the repurchase of $34.7
million of senior unsecured notes at a cost of $32.8 million and common stock
repurchases of $27.9 million.
Pension and Other Postretirement Benefits
In 2001, the investment market experienced significant declines due to
various reasons. In addition, the future outlook for the investment market is
not expected to improve in the short term. As a result, the Company adjusted the
expected rate of return on its pension and other postretirement benefit plans
assets. For the year ended December 31, 2001, the Company's net periodic benefit
54
cost assumed a 7.75% rate of return as compared to 9.00% in the prior year. The
rate adjustment reflects the Company's outlook for asset returns after
considering the events of September 11, 2001 and the impact of asset losses
recognized in the September 30, 2001 plan valuation. This change resulted in an
increase of $4.2 million in the Company's recorded net periodic benefit expense.
In addition, increases in the health care cost trend contributed an additional
$3.2 million of increased costs. Total net periodic benefit cost for all plans
was $11.3 million in 2001 as compared to $4.6 million in 2000. The actual return
on the plan's assets for the year ended December 31, 2001 was a loss of $36.2
million. As a result, the Company recorded a tax effected decrease in other
comprehensive income of $28.9 million.
The actual losses recorded in other comprehensive income will be
recognized in the Company's future results of operations to the extent that
future calculations of the net periodic benefit expense's assumed rate of return
reflects the losses. The accounting rules for pension plans and other
postretirement benefits allow investment gains and losses to be recognized in a
systematic and rational method. This methodology reduces the periodic impact of
market volatility.
In January 2002, the Company made an aggregate contribution of $23.5
million to fund the pension and other postretirement benefit plans. The effect
of this contribution will be to reduce the impact that the actual investment
losses will have on the Company's future net periodic benefit cost. In addition,
the Company believes that its expected rate of return in 2002 will be at
historical levels.
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 wholesale
generation capabilities. Projections for total capital requirements for 2002 are
$409 million and projections for construction expenditures for 2002 are $391
million. For 2002-2006 projections, total capital requirements are $1.9 billion
and construction expenditures are $1.8 billion, including the combustion
turbines discussed below. These estimates are under continuing review and
subject to on-going adjustment.
The Company has committed to purchase five combustion turbines at a total
cost of $151.3 million. The turbines for three planned power generation plants
with a combined capacity of 657 MWs.The estimated cost of construction of the
plants is approximately $400.3 million. The Company has expended $103.4 million
as of December 31, 2001. In November 2001, the Company broke ground for Afton
Generating Station ("Afton"), a 135 MW natural gas fired generating plant on a
site in Southern New Mexico. This facility is expected to be operational by
October 2002. Currently, the Company plans to expand the facility to 225 MW by
the end of 2003. In February 2002, the Company also broke ground to build
Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired
generating plant in Southwestern New Mexico. This facility is expected to be
operational by July 2002. The planned plants are part of the Company's ongoing
competitive strategy of increasing generation capacity over time. The costs of
these plants are not anticipated to be added to the rate base.
55
The Company's construction expenditures for 2001 were entirely funded
through cash generated from operations. To meet its capital needs for its
planned expansion of its generation capabilities, the Company expects that it
will have to access the capital markets. Otherwise, the Company anticipates that
internal cash generation and current debt capacity will be sufficient to meet
all its other capital requirements for the years 2002 through 2006. 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.
Liquidity
At March 1, 2002, PNM had $170 million of available liquidity
arrangements, consisting of $150 million from an unsecured revolving credit
facility ("Credit Facility"), and $20 million in local lines of credit. The
Credit Facility will expire in March 2003. There were $75.0 million in
borrowings as of March 1, 2002. In addition, the Holding Company has a $20
million reciprocal borrowing agreement with PNM and $25 million in local lines
of credit.
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 and wholesale 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.
PNM's credit outlook is considered positive by Moody's Investor Services
("Moody's") and Fitch Ratings ("Fitch") and stable by Standard and Poors
("S&P"). Previously, in connection with PNM's announcement of its agreement to
acquire Western Resources' electric utility operations, S&P, Moody's and Fitch
placed PNM's securities ratings on negative credit watch pending review of the
transaction. As a result of events which led the Company to conclude the
acquisition could not be accomplished, ultimately leading the Company to
terminate the transaction in January 2002, S&P, Moody's and Fitch removed the
Company from negative credit watch. The Company is committed to maintaining its
investment grade. S&P currently rates PNM's senior unsecured notes ("SUNs") and
its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its
preferred stock "BB". Moody's rates PNM's SUNs and senior unsecured pollution
control revenue bonds "Baa3"; and preferred stock "Ba1". The EIP senior secured
debt is also rated "Ba1". Fitch rates PNM's SUNs and senior unsecured pollution
control revenue bonds "BBB-," PNM's EIP lease obligation "BB+" and PNM'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.
56
Long-term Obligations and Commitments
The following table shows PNM's long-term debt and operating leases as of
December 31, 2001. As of March 1, 2002, the Holding Company has no long-term
obligations except those consolidated with PNM.
Payments Due
------------------------------------------------------------------
(In thousands)
Contractual Less than After 5
Obligations Total 1 year 2-3 years 4-5 years years
------------ ------------ ----------- ----------- ------------
Long-Term Debt.................... 953,884 - - 268,420 685,464
Operating Leases.................. 532,954 32,095 66,162 70,356 364,341
------------ ------------ ----------- ----------- ------------
Total Contractual Cash
Obligations.................... 1,486,838 32,095 66,162 338,776 1,049,805
============ ============ =========== =========== ============
PNM 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. In 1998, PNM established PVNGS Capital Trust ("Capital Trust")
for the purpose of acquiring all the debt underlying the PVNGS leases. PNM
consolidates Capital Trust in its consolidated financial statements. The
purchase was funded with the proceeds from the issuance of $435 million of SUNs,
which were loaned to Capital Trust. Capital Trust then acquired and now holds
the debt component of the PVNGS leases. For legal and regulatory reasons, the
PVNGS lease payment continues to be recorded and paid gross with the debt
component of the payment returned to PNM via Capital Trust. As a result, the net
cash outflows for the PVNGS lease payment were $12.4 million in 2001. The table
above reflects the net lease payment.
PNM's other significant operating lease obligations include the Eastern
Interconnect Project ("EIP"), a transmission line with annual lease payments of
$7.3 million and a power purchase agreement for the entire output of Delta
Persons Generating Station ("Delta"), a gas-fired generating plant in
Albuquerque, New Mexico with imputed annual lease payments of $6.0 million.
The Company's off-balance sheet obligations are limited to PNM's
operating leases and certain financial instruments related to the purchase and
sale of energy (see below). The present value of PNM's operating lease
obligations for PVNGS Units 1 and 2, EIP and the Delta PPA was $224 million as
of December 31, 2001.
PNM has entered various long-term power purchase agreements obligating it
to make aggregate fixed payments of $30.3 million plus the cost of production
and a return. These contracts expire December 2006 through July 2010. In
addition, PNM is obligated to sell electricity for $158.1 million in fixed
payments plus the cost of production and a return. These contracts expire
December 2003 through June 2010. PNM's trading portfolio as of December 31, 2001
included open contract positions to buy $66.9 million of electricity and to sell
$25.7 million of electricity. In addition, PNM had open contract positions
classified as normal sales of electricity under the derivative accounting rules
of $48.9 million and normal purchases of electricity of $8.1 million.
57
PNM has a coal supply contract for the needs of San Juan Generating
Station ("SJGS") until 2017. The contract contemplates the delivery of
approximately 103 million tons of coal during its remaining term. The pricing is
based on the cost of extraction plus a margin.
PNM contracts for the purchase of gas to serve its jurisdictional
customers. These contracts are short-term in nature supplying the gas needs for
the current heating season and the following off-season months. The price of gas
is a pass-through, whereby the Company recovers 100% of its cost of gas.
Contingent Provisions of Certain Obligations
The Holding Company and PNM have a number of debt obligations and other
contractual commitments that contain contingent provisions. Some of these, if
triggered, could affect the liquidity of the Company. The Holding Company and/or
PNM could be required to provide security, immediately pay outstanding
obligations or be prevented from drawing on unused capacity under certain credit
agreements, if the contingent requirements were to be triggered. The most
significant consequences resulting from these contingent requirements are
detailed in the discussion below.
PNM's master purchase agreement for the procurement of gas for its
jurisdictional customers contains a contingent requirement that could require
PNM to provide security for its gas purchase obligations if the seller were to
reasonably believe that PNM was unable to fulfill its payment obligations under
the agreement.
The master agreement for the sale of electricity in the Western System
Power Pool ("WSPP") contains a contingent requirement that could require PNM to
provide security if its' debt were to fall below the investment grade rating.
The WSPP agreement also contains a contingent requirement, commonly called a
material adverse change ("MAC") provision, which could require PNM to provide
security if a material adverse change in its financial condition or operations
were to occur.
PNM's committed Credit Facility contains a MAC provision which if
triggered could prevent PNM from drawing on its unused capacity under the Credit
Facility. In addition, the Credit Facility contains a contingent requirement
that requires PNM to maintain a debt-to-capital ratio of less than 70%. If PNM's
debt-to-capital ratio were to exceed 70%, PNM could be required to repay all
borrowings under the Credit Facility, be prevented from drawing on the unused
capacity under the Credit Facility, and be required to provide security for all
outstanding letters of credit issued under the Credit Facility. At December 31,
2001, the Company had $6.3 million of letters of credit outstanding.
If a contingent requirement were to be triggered under the Credit
Facility resulting in an acceleration of the outstanding loans under the Credit
Facility, a cross-default provision in the PVNGS leases could occur if the
accelerated amount is not paid. If a cross-default provision is triggered, the
lessors have the ability to accelerate their rights under the leases, including
acceleration of all future lease payments.
Planned Financing Activities
PNM has $268.4 million of long-term debt that matures in August 2005. All
other long-term debt matures in 2016 or later. The Company could enter into
other long-term financings for the purpose of strengthening its balance sheet,
funding growth 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 PNM'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 PNM's financial instruments would ultimately limit the amount of SUNs PNM
would issue.
PNM currently has $182.0 million of tax-exempt bonds outstanding that are
callable at a premium in December 2002 and August 2003. PNM intends to refinance
these bonds assuming the interest rate of the refinancing does not exceed the
current interest rate and has hedged the entire planned refinancing. In order to
58
take advantage of current low interest rates, PNM entered into two forward
starting interest rate swaps in November and December 2001 and three additional
contracts subsequent to December 31, 2001. PNM designated these swaps as cash
flow hedges. The hedged risks associated with these instruments are the changes
in cash flows related to general moves in interest rates expected for the
refinancing. The swaps effectively cap the interest rate on the refinancing to
4.9% plus an adjustment for PNM's and industry's credit rating. PNM's assessment
of hedge effectiveness is based on changes in the hedge interest rates. The
derivative accounting rules, as amended, provide 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 transactions affect earnings. Any hedge ineffectiveness is
required to be presented in current earnings. There was no material hedge
ineffectiveness in the year ended December 31, 2001.
A forward starting swap does not require any upfront premium and captures
changes in the corporate credit component of an investment grade company's
interest rate as well as the underlying Treasury benchmark. The five forward
starting interest rate swaps have termination dates and notional amounts as
follows: one with a termination date of September 17, 2002 for a notional amount
of $46.0 million and four with a termination date of May 15, 2003 for a combined
notional amount of $136.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transaction is cash settled on the
mandatory unwind date (strike date), corresponding to the refinancing date of
the underlying debt. The settlement will be capitalized as a cost of issuance
and amortized over the life of the debt as a yield adjustment. If the hedged
corporate interest rate along with the underlying benchmark were to decline
below the capped level of the hedge, PNM will have to pay to settle the forward
starting swap but would be able to issue the refinanced debt at the lower
interest rate. However, if the hedged corporate interest rate along with the
underlying benchmark were to decline but the interest rates available to PNM at
the time of refinancing are greater than the existing rate of the debt to be
refinanced due to credit issues, PNM will incur a loss on the hedge and not
refinance the debt.
Stock Repurchase
In March 1999, PNM's Board of Directors approved a plan to repurchase up
to 1,587,000 shares of its outstanding common stock with maximum purchase price
of $19.00 per share. In December 1999, PNM Board of Directors authorized PNM to
repurchase up to an additional $20.0 million of its common stock. As of December
31, 1999, PNM repurchased 1,070,700 shares of its previously outstanding common
stock at a cost of $18.8 million. From January 2000 through March 2000, PNM
repurchased an additional 1,167,684 shares of its outstanding common stock at a
cost of $18.8 million.
59
On August 8, 2000, PNM's Board of Directors approved a plan to repurchase
up to $35.0 million of its outstanding common stock through the end of the first
quarter of 2001. From August 8, 2000 through December 31, 2000, PNM repurchased
an additional 417,900 shares of its outstanding common stock at a cost of $9.0
million. The total cost of stock repurchased for the year ended December 31,
2000 was $27.9 million. There were no repurchases of common stock during the
year ended December 31, 2001. The Board of Directors has authorized additional
stock repurchases but the Company has not exercised that new authority.
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 ability of the Company's subsidiaries to pay
dividends. Currently, PNM is the Company's primary source of dividends. As part
of the order approving the formation of the holding company, the PRC placed
certain restrictions on the ability of PNM to pay dividends to its parent.
The PRC order imposed the following conditions regarding dividends paid
by PNM to the holding company: PNM can not pay dividends which cause its debt
rating to go below investment grade; and PNM can not pay dividends in any year,
as determined on a rolling four quarter basis, in excess of net earnings without
prior PRC approval. Additionally, PNM has various financial covenants which
limit the transfer of assets, through dividends or other means.
In addition, the ability of the Company to declare dividends is dependent
upon the extent to which cash flows will support dividends, the availability of
retained earnings, its financial circumstances and performance, the PRC's
decisions in various regulatory cases currently pending and which may be
docketed in the future, the effect of deregulating generation markets and market
economic conditions generally. The ability to recover stranded costs in
deregulation (as amended), conditions imposed on holding company formation,
future growth plans and the related capital requirements and standard business
considerations may also affect the Company's ability to pay dividends.
Consistent with the PRC's holding company order, PNM paid dividends of
$127.0 million to the Company on December 31, 2001. On March 4, 2002, the PNM
Board of Directors declared an additional dividend of approximately $5.5
million, which was paid March 19, 2002.
On February 19, 2002, the Company's Board of Directors approved a 10
percent increase in the common stock dividend. The increase raises the quarterly
dividend to $0.22 per share, for an indicated annual dividend of $0.88 per
share. The Company's Board of Directors approved a policy for future dividend
increases in the range of 8 to 10 percent annually, targeting a payout of
between 50 to 60 percent of regulated earnings. The Company believes that this
target is consistent with the Company's expectation of future operating cash
flows and the cash needs of its planned increase in generating capacity.
60
Capital Structure
The Company's capitalization, including current maturities of long-term
debt, at December 31 is shown below:
2001 2000
--------- ---------
Common Equity....................... 50.8% 48.6%
Preferred Stock..................... 0.6 0.7
Long-term Debt...................... 48.6 50.7
--------- ---------
Total Capitalization*............ 100.0% 100.0%
========= =========
*Total capitalization does not include as debt the present value of
PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and
the Delta PPA which was $224 million as of December 31, 2001 and $227
million as of December 31, 2000.
OTHER ISSUES FACING THE COMPANY
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
In April 1999, New Mexico's Electric Utility Industry Restructuring Act
of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act
opens the state's electric power market to customer choice. In March 2001,
amendments to the Restructuring Act were passed which delay the original
implementation dates by approximately five years, including the requirement for
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets. In addition, the PRC will have the
authority to delay implementation for another year under certain circumstances.
The Restructuring Act, as amended, will give schools, residential and small
business customers the opportunity to choose among competing power suppliers
beginning in January 2007. Competition would be expanded to include all
customers starting in July 2007. The Company is unable to predict the form its
further restructuring will take under the delayed implementation of customer
choice. In addition, the Restructuring Act, as amended, 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.
The amendments to the Restructuring Act required that the PRC approve a
holding company, subject to terms and conditions in the public interest, without
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets, by July 1, 2001. In addition, the
amendments allow utilities to engage in unregulated power generation business
activities until corporate separation is implemented.
On December 31, 2001, the Company implemented the holding company
structure without corporate separation of supply service and energy-related
services assets from distribution and transmission services assets. This
structure provides for a holding company whose current holdings will be PNM,
Avistar and other inactive unregulated subsidiaries. This was effected through
the share exchange between PNM shareholders and the holding company, PNM
Resources. Avistar and most of the inactive unregulated subsidiaries became
wholly-owned subsidiaries of the holding company in January 2002. The transfer
of certain corporate related assets to the holding company also occurred in
January 2002. There are no current plans to provide the holding company with
significant debt financing.
61
The 2002 session of the New Mexico Legislature resulted in enactment of
tax measures favorable to the construction of merchant generating plants and
plants fueled by renewable resources. The new laws provide authority for all
local governments in the state to issue industrial revenue bonds for merchant
generating plants smaller than 300 MW. The bonds provide exemptions from
property taxes. Also enacted into law was a 5% investment tax credit for
merchant generating plants smaller than 300 MW; tax credits for qualified
generators using renewable resources; and an exemption from gross receipts tax
for the cost of certain wind generation equipment.
There is a growing concern in New Mexico about the use of water for
merchant power plants, due to the increased activity in building these plants in
the state, which has an arid climate. The availability of sufficient water
supplies to meet all the needs of the state, including growth, is a major issue.
It is expected that the Legislature will appoint an interim committee to study
the impact of power plants on the state's water and other natural resources,
with a report to be issued for the 2003 session. In building the Afton and
Lordsburg plants, which are much smaller than other merchant plants under
construction or planned by other generating companies, the Company has secured
sufficient water rights.
Congress is currently considering a number of bills affecting the energy
industry, including comprehensive energy policy legislation that addresses
numerous electricity issues that are fundamental to the structure of the
industry. Among the provisions being considered are: granting FERC jurisdiction
over currently non-jurisdictional entities for transmission; granting FERC
authority to require participation in Regional Transmission Organizations
("RTO"); reliability standards; transmission pricing and siting; Public Utility
Holding Company Act repeal; Public Utility Regulatory Policies Act repeal; net
metering requirements; additional consumer protections; and renewable energy
requirements. In addition, proposed tax legislation contains provisions relating
to electric industry restructuring, primarily directing the Treasury Department,
in consultation with FERC, to conduct a study of tax issues resulting from
restructuring and to report to Congress annually. The tax legislation being
considered also contains provisions regarding tax credits for electricity
production from renewable resources, clean coal technologies and fuel cells, as
well as tax incentives for energy conservation and efficiency measures. On March
8, 2002, the Senate passed the Economic Stimulus Package previously passed by
the House of Representatives. The Package includes an extension to the federal
production tax credit until January 1, 2004. The President is expected to sign
the Package into law. The Company will continue to participate in the debate
regarding national energy policy and any legislation affecting the industry.
In August 2001, the FERC issued a series of orders requiring existing
independent system operators and developing RTOs in the Eastern United States to
enter into mediation to form a single RTO in the Northeast and a second in the
Southeast. The FERC expressed the desire that four RTO's be formed in the United
States, two in the East, one in the Midwest and one in the West. The Company
along with other Southwest transmission owners formed an RTO and made a filing
on October 16, 2001 with the FERC.
The FERC has indicated its intention to initiate a separate Notice of
Proposed Rulemaking that would require implementation of new Open Access
Transmission Tariffs by RTOs and by public utilities that own, operate, or
control interstate transmission facilities. The new tariffs would adopt
provisions to implement new transmission services and a standardized wholesale
market design. The new functions would be implemented by an independent entity,
which could be an RTO, that would perform services under the standard market
design under rules applicable to all transmission customers.
62
RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT
Stranded Costs
The Restructuring Act, as amended, 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.
These 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, as amended, 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 Nuclear Regulatory
Commission Prefunding below).
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. The Restructuring Act, as
amended, requires the Company to file a transition plan which includes
provisions for the recovery of stranded costs and other expenses associated with
the transition to a competitive market no later than January 1, 2005. The
Company is unable to predict the amount of stranded costs that it may seek to
recover at that time. The Company's previous proposal to recover its stranded
costs under the original customer choice implementation dates would not
accurately represent the Company's expected stranded costs under the amended
implementation dates of the Restructuring Act.
Approximately $142 million of costs associated with the power supply and
energy services businesses under the Restructuring Act were established as
regulatory assets. Because of the Company's belief that recovery is probable,
these assets continue to be classified as regulatory assets, although the
Company has discontinued the use of accounting for rate regulated activities.
The amendments to the Restructuring Act provide the opportunity for amortization
of coal mine decommissioning costs currently estimated at approximately $100
million. The Company intends to seek recovery of these costs in its next rate
case filing and believes that the costs are fully recoverable. The Company
believes that any remaining portion of the regulatory assets will be fully
recovered in future rates, including through a non-bypassable wires charge.
The Company believes that the Restructuring Act, as amended, if properly
applied, provides an opportunity for recovery of a reasonable amount of stranded
costs should such costs exist at the time of separation. If regulatory orders do
not provide for a reasonable recovery, the Company is prepared to vigorously
pursue judicial remedies. The PRC will make a determination and quantification
of stranded cost recovery prior to implementation of restructuring. The
determination may 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.
63
Transition Cost Recovery
In addition, the Restructuring Act, as amended, 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 from 2007 through 2012 by means of a separate wires charge. The
PRC may extend this date by up to one year. The Company may seek to recover
transition costs already incurred in future rate cases that may occur prior to
open access. The Company is unable to predict the amount of transition costs it
may incur. To date, the Company has capitalized $24.3 million of expenditures
that meet the Restructuring Act's definition of transition 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 public and
customer education and communications. These costs 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. Depending on the amount of non-recoverable transition costs,
if any, the resulting charge to earnings may have a material effect on the
future financial results and position of the Company.
Nuclear Regulatory Commission ("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.
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, as amended, allows for the recoverability of 50%
up to 100% of stranded costs including nuclear decommissioning costs. The
results of the 1998 triannual decommissioning cost study indicated that PNM's
share of the PVNGS decommissioning costs excluding spent fuel disposal will be
approximately $181 million (in 1998 dollars). The Restructuring Act, as amended,
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, as amended, states that it does not require 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. When final determination of stranded cost recovery is made
and 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.
64
MERCHANT PLANT FILING
Senate Bill ("SB") 266, enacted by the 2001 session of the New Mexico
legislature, allowed public utilities to "invest in, construct, acquire or
operate" a generating plant not intended to provide retail electric service,
free of certain otherwise applicable regulatory requirements contained in the
Public Utility Act. By order entered on March 27, 2001, the PRC found that these
provisions of SB 266 raised issues such as cost allocations for ratemaking,
revenue allocations for off-system sales, how the Commission can ensure the
utility will meet its duty to provide service when the utility invests in such
generating plant, how that plant will be financed and how transactions between
regulated services and merchant plants will be conducted. The Company has filed
a pleading addressing these issues and testimony in response to interested
parties' requests. The PRC has established a schedule for the filing of staff
and intervenor testimony and for the Company's rebuttal testimony, culminating
in a hearing scheduled for June 10, 2002.
In November 2001, the Company began settlement negotiations with the
PRC's utility staff and intervenors related to these PRC proceedings in order to
resolve a number of matters. In addition to the issues being examined in the
Company's merchant plant filing, discussions have included the future framework
for restructuring the electric industry in New Mexico under the Restructuring
Act, and a future retail electric rate path. The negotiations include the
potential implementation and effective date of rates that would replace those
approved under the rate freeze stipulation that remains in effect until January
1, 2003.
The Company is currently unable to predict the impact these proceedings
may have on its plans to expand its generating capacity and other operations.
WESTERN UNITED STATES WHOLESALE POWER MARKET
A significant portion of the Company's earnings in 2001 was derived from
the Company's wholesale power trading operations, which benefited from 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 during the first half of the year. As a result of the
supply imbalance, the wholesale power market in the Western United States became
extremely volatile and, while providing many marketing opportunities, presented
and continues to present significant risk to companies selling power into this
marketplace.
Moderate weather in California, as well as certain regulatory actions
(see below), have caused a significant decline in the price of wholesale
electricity in the Western United States wholesale power market. In addition,
conservation measures and new generation have or are expected to put downward
pressure on wholesale electricity prices. As a result of these trends, the
Company expects its earnings from wholesale power trading operations to be
significantly lower in the future than the levels seen during the last half of
2000 and the first half of 2001.
The power market in the Western United States has been the subject of
widespread national attention. At the heart of the situation were flaws in the
California deregulation legislation and a significant imbalance between electric
supply and demand. These circumstances were aggravated by other factors such as
increases in gas supply costs, weather conditions and transmission constraints.
65
The FERC and the California Public Utilities Commission ("CPUC") have entered a
series of orders addressing, respectively, the wholesale pricing of electricity
into the California market and the retail pricing of electricity to California
consumers. These initiatives put significant downward pressure on wholesale
prices. The Company cannot predict the ultimate outcome of these governmental
initiatives and their long-term effect on the Western United States power market
or on the Company's ability to market into the California market.
During 2001, regional wholesale electricity prices reached over $1,000
per MWh mainly due to the electric power shortages in the West although current
price levels are much depressed from this level. Two of California's major
utilities, Southern California Edison Company ("SCE") and Pacific Gas and
Electric Co. ("PG&E"), were unable to fully recover their wholesale power costs
from their retail customers. As a result, both utilities experienced severe
liquidity constraints. PG&E decided to seek bankruptcy protection while SCE was
forced to consider bankruptcy.
In response to the turmoil in the California energy market, the FERC
initially imposed a "soft" price cap of $150 per MWh for sales to the California
Power Exchange ("Cal PX") and the California Independent System Operator ("Cal
ISO") that required any wholesale sales of electricity into these markets be
capped at $150 per MWh unless the seller could demonstrate that its costs
exceeded the cap. This price cap was effectively modified by FERC orders issued
in March and April 2001 that directed certain power suppliers to provide refunds
for overcharges calculated on the basis of a formula that sanctioned wholesale
prices considerably in excess of the $150 per MWh level. On April 26, 2001, the
FERC adopted an order establishing prospective mitigation and a monitoring plan
for the California wholesale markets and which established a further
investigation of public utility rates in wholesale Western energy markets. The
plan reflected in the April 26 order, replaced the $150 per MWh soft cap
previously established and applied during periods of system emergency.
Thereafter, on June 19, 2001, the FERC issued still another order that changed
the previous orders and expanded the price mitigation approach of the April 26
order to all of the Western region. As a result of the price mitigation plan and
other factors, such as moderate weather in California and lower gas prices,
wholesale electric prices declined significantly by the end of the third quarter
and remained low through the fourth quarter. The Company is unable to predict
the impact the price mitigation plan will ultimately have on the wholesale
market, but expects that if wholesale electric prices remain at current levels,
future operating revenues from Generation and Trading will be significantly
lower than in the first half of 2001.
The June 19 order also directed a FERC administrative law judge to
convene a settlement conference to address potential refunds owed by sellers
into the California market. The settlement conference, in which the Company
participated, was ultimately unsuccessful, but the administrative law judge
called in his recommendation to the FERC for an evidentiary hearing to resolve
the dispute, suggesting that refunds were due; however, the estimated refunds
were significantly lower than demanded by California, and in most instances,
were offset by the amounts due suppliers from the Cal PX and Cal ISO. California
had demanded refunds of approximately $9 billion from power suppliers. On July
25, 2001, acting on the recommendation of the administrative law judge, the FERC
ordered an expedited fact-finding hearing to evaluate refunds for spot market
transactions in California. The FERC also ordered a preliminary hearing to
determine whether refunds were due resulting from wholesale sales into the
Pacific Northwest. The Pacific Northwest matter was heard by an administrative
law judge whose recommended decision declined to order refunds resulting from
sales into the Pacific Northwest, but the FERC has not yet acted on this
recommended decision. The hearing on potential California refund obligations has
not yet been completed and a recommended decision is not anticipated until the
second half of 2002. The Company is unable to predict the ultimate outcome of
these FERC proceedings, or whether the Company will be directed to make any
refunds as the result of a FERC order.
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In 2001, approximately $2 million in wholesale power sales by the Company
were made directly to the Cal PX, which was the main market for the purchase and
sale of electricity in the state in the beginning of 2001, or the Cal ISO which
manages the state's electricity transmission network. In January and February
2001, SCE and PG&E, major purchasers of power from the Cal PX and ISO, defaulted
on payments due the Cal PX for power purchased from the Cal PX in 2000. These
defaults caused the Cal PX to seek bankruptcy protection. The Company has filed
its proofs of claims in the Cal PX and PG&E bankruptcy proceedings. Total
amounts due from the Cal PX or Cal ISO for power sold to them in 2000 and 2001
total approximately $7 million. The Company has provided allowances for the
total amount due from the Cal PX and Cal ISO.
Prior to its bankruptcy filing, the Cal PX undertook to charge back the
defaults of SCE and PG&E to other market participants, in proportion to their
participation in the markets. The Company was invoiced for $2.3 million as its
proportionate share under the Cal PX tariff. The Company, as well as a number of
power marketers and generators, filed complaints with the FERC to halt the Cal
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 was unreasonable and destabilizing to the
California power market. The FERC has issued a ruling on these complaints
eliminating the "charge-back" mechanism.
With the demise of the Cal PX in February 2001, the California Department
of Water Resources ("Cal DWR") commenced a program of purchasing electric power
needed to supply California utility customers serviced by PG&E and SCE as these
utilities lacked the liquidity to purchase supplies. The purchases were financed
by legislative appropriation, with the expectation that this funding would be
replaced with the issuance of revenue bonds by the state. In the first quarter
of 2001, the Company began to sell power to the Cal DWR. The Company has
regularly monitored its credit risk with regard to its Cal DWR sales and
believes its exposure is prudent.
In addition to sales directly to California, the Company sells power to
customers in other jurisdictions who sell to California and whose ability to pay
the Company 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.
In 2001, in response to the increased credit risk and market price
volatility described above, the Company provided an additional allowance against
revenue of $3.5 million for anticipated losses to reflect management's estimate
of the increased market and credit risk in the wholesale power market and its
impact on 2001 revenues. Based on information available at December 31, 2001,
the Company believes the total allowance for anticipated losses, currently
established at $12.0 million, is adequate for management's estimate of potential
uncollectible accounts. The Company will continue to monitor the wholesale power
marketplace and adjust its estimates accordingly.
67
The 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 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 future in connection with this investigation. The
California Attorney General has filed a lawsuit against certain power marketers
for alleged unfair trade practices involving the reselling of reserved capacity.
The Company is not one of the named defendants. Other related investigations
have been commenced by other federal and state governmental bodies.
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.
The Company does not believe that these matters will have a material
adverse effect on its results of operations or financial position.
As noted above, SCE has been forced to consider a bankruptcy filing.
However, at the present time such a bankruptcy filing does not appear likely,
given the understanding that SCE has refinanced a significant portion of its
outstanding debt and cured many previously existing payment defaults under its
debt agreements and also with the Cal PX and other suppliers. 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 $7.8 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. SCE has not defaulted on its payment
obligations with respect to PVNGS and Four Corners.
TERMINATION OF WESTERN RESOURCES TRANSACTION
On November 9, 2000, PNM and Western Resources announced that both
companies' Boards of Directors approved an agreement under which PNM would
acquire the Western Resources electric utility operations in a tax-free,
stock-for-stock transaction. The agreement required that Western Resources
split-off its non-utility businesses to its shareholders prior to closing.
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In July 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for a $151 million increase. After rehearing the KCC established the
rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001, in New York state court
seeking declarations that the transaction could not be accomplished as designed
due to the KCC's determination that the split-off condition of the transaction
is unlawful; that the Company is not obligated to pursue approvals of the
transaction as designed; that the transaction is terminated effective December
31, 2001, without an automatic extension; and that the KCC rate case order
constitutes a material adverse effect under the agreement. The Company also
seeks monetary damages for breach of contract because Western Resources
represented and warranted that the split-off did not require approval of the
KCC.
On November 19, 2001, Western Resources filed a complaint against the
Company in New York state court alleging breach of contract and breach of
implied covenant of good faith and fair dealing. Western Resources alleged that
the Company brought about the KCC orders, failed to assist in efforts to reverse
the KCC orders, refused to renegotiate within the terms of the agreement,
interfered with Western Resources' efforts to satisfy the terms of the
agreement, and effected an unauthorized de facto termination of the agreement by
filing its complaint. Western Resources alleges damages in excess of $650
million. The Company believes that the complaint filed by Western Resources is
without merit and intends to vigorously defend itself against the complaint. The
Company also intends to vigorously pursue its own complaint.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect.
On February 5, 2002, the District Court for Shawnee County, Kansas,
dismissed without prejudice Western Resources' petition for judicial review of
the KCC's split-off orders. The Court ruled that by filing a new financial plan
in compliance with the orders, Western Resources accepted certain portions of
the orders thereby creating a situation where further administrative action
became necessary. As a result, the Court concluded that the matter was not ripe
for judicial review and remanded the case to the KCC.
On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate
order.
The Company is currently unable to predict the outcome of its litigation
with Western Resources.
69
IMPLEMENTATION OF 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. 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 and 2000.
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. Based upon information available at December 31, 2001, the Company
believes the allowance for doubtful accounts of $7.7 million is adequate for
management's estimate of potential uncollectible accounts.
The following is a summary of the allowance for doubtful accounts for the
Utility Operations which utilizes the customer billing system during 2001, 2000
and 1999:
2001 2000 1999
------------- ------------- ------------
(In thousands)
Allowance for doubtful accounts, beginning
of year................................................. $7,550 $12,504 $ 836
Bad debt expense.......................................... 5,682 8,567 11,496
Less: Write off (adjustments) of uncollectible accounts.. 5,566 13,521 (172)
------------- ------------- ------------
Allowance for doubtful accounts, end of year ............. $7,666 $7,550 $12,504
============= ============= ============
Note: Above schedule excludes bad debt allowance for the Generation and
Trading Operations
EFFECTS OF CERTAIN EVENTS ON FUTURE REVENUES
The Company's 100 MW power sale contract with San Diego Gas and Electric
Company ("SDG&E") expired on April 30, 2001 following FERC's acceptance for
filing of a cancellation notice filed by the Company. The Company expects to
replace these revenues, based on current 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 1, 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 WAPA under the Company's Open
Access Transmission Tariff on behalf of the United States Department of Energy
("DOE") as contracting agent for Kirtland Air Force Base ("KAFB").
In 2001, FERC issued a "proposed" order directing the Company to provide
transmission service, but left the terms of service to be negotiated by the
parties and subject to final FERC review and determination. In January 2002, the
parties submitted a settlement agreement resolving most of the issues relating
to the rates, terms and conditions of service. The "proposed" FERC order is not
70
subject to requests for rehearing or judicial review. An order establishing
terms and conditions (including compensation for transmission service) would be
a "final" order that would be subject to requests for rehearing and to judicial
review. The Company is evaluating its legal options in relation to the
"proposed" order or any resulting "final" order. The settlement agreement
reserves the Company's rights to seek rehearing and judicial review of any final
order and to present other legal claims. In February 2002, the FERC
administrative law judge who supervised the negotiations leading to the partial
settlement recommended that FERC issue a final order approving the agreement. A
related PRC proceeding has been stayed, pending the outcome of the FERC case.
The effect of the FERC's proposed order to provide transmission service,
instead of the current retail sale that the Company makes to DOE on behalf of
KAFB, depends upon the final terms of any FERC order as well as the Company's
ability to sell the power to a different customer and the price that the Company
would obtain if it makes such a sale. The Company believes that the impact will
be immaterial based on the facts above.
COAL FUEL SUPPLY
In 1996, the Company was notified by San Juan Coal Company ("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. On November 6, 2001, an administrative order was issued denying the
proposed selections. The Company is monitoring an appeal by the Navajo Nation
and other developments on this issue and will continue to assess, but cannot
estimate with any certainty the potential impacts to the SJGS and the Company's
operations.
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. Discovery continues in the pending
litigation. 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.
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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 not yet known what changes in EPA policy, if any, may occur in the NSR area
as a result of the change in administration in Washington. The National Energy
Policy released May 2001 by the National Energy Policy Development Group, called
for a review of the pending NSR enforcement actions and that review continues by
the EPA. 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.
Threatened Citizen Suit Under the Clean Air Act
By letter dated January 9, 2002, counsel for the Grand Canyon Trust and
Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a
so-called "citizen suit" under the Clean Air Act, alleging that the Company and
co-owners of the SJGS violated the Clean Air Act, and the implementing federal
and state regulations, at SJGS. The notice indicates that penalties and
injunctive relief may be sought. Under the Clean Air Act, GCT must wait at least
60 days after affording the Company notice (i.e., until March 9, 2002) before
filing a lawsuit. The allegations contained in GCT's notice of intent to sue
fall into three categories. First, GCT contends that the plant has violated, and
is currently in violation, of the federal NSPS at all four units at SJGS.
Second, GCT argues that the plant has violated, and is currently in violation,
of the federal PSD rules, as well as the corresponding provisions of the New
Mexico Administrative Code, at all four units. Third, GCT alleges that the plant
has "regularly violated" the 20% opacity limit contained in SJGS's operating
permit and set forth in federal and state regulations at Units 1, 3 and 4. The
Company is currently investigating the allegations contained in the notice of
intent to sue. Based on its investigation to date, the Company firmly believes
that the allegations are without merit. By letter to GCT's counsel dated
February 22, 2002, the Company vigorously disputed the allegations and affirmed
its compliance with the laws in question. The Company adheres to high
environmental standards as evidenced by its International Standards Organization
ratings. In that letter, the Company also stated that the GCT has failed to
provide sufficient information to permit full examination of the allegations. If
a lawsuit is filed by GCT, as threatened, the Company will respond on behalf of
the co-owners and vigorously defend in the litigation. The Company is, however,
unable to predict the ultimate outcome of the matter.
NATURAL GAS EXPLOSION
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New
Mexico. The apparent cause of the explosion was a leak from a Company line near
the location. The explosion destroyed a small building and injured two persons
who were working in the building. The Company's investigation indicates that the
leak was an isolated incident likely caused by a combination of corrosion and
increased pressure. The Company also is cooperating with an investigation of the
incident by the PRC's Pipeline Safety Bureau which issued its report on March
18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the
New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the
Company by the injured persons along with several claims for property and
business interruption damages have been resolved by the Company. At this time,
the Company is unable to estimate the potential liability, if any, that the
Company may incur as a result of the Pipeline Safety Bureau's investigation.
There can be no assurance that the outcome of this matter will not have a
material impact on the results of operations and financial position of the
Company.
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NAVAJO NATION TAX ISSUES
Arizona Public Service Company ("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 and
cannot estimate with any certainty the potential impact on the Company's
operations.
LANDOWNER ENVIRONMENTAL CLAIMS
Certain landowners owning property in the vicinity of the San Juan
Generating Station have given notice to the Company of their intent to file suit
against the Company and the other owners of the generating station. The asserted
bases for the threatened litigation encompass a broad spectrum of allegations,
including improper discharge of wastes and failure to remediate such discharges,
poisoning of drinking waters, wrongful death and injury to persons, harm to
landowner property, negligence, unnatural climate change, destruction of
documents, racial discrimination, hostile work environment for employees at the
plant and wrongful discharge of certain employees. The Company is in the process
of reviewing these allegations and to date no suit has been filed. The Company
has been informed that similar allegations have been made by the same landowners
against Arizona Public Service Company, as operator of the Four Corners Power
Plant, of which the Company is a co-owner.
NEW AND PROPOSED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" ("SFAS 143"). In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the
recognition of a liability for legal obligations associated with the retirement
of a tangible long-lived asset that result from the acquisition, construction or
development and/or the normal operation of a long-lived asset. The asset
retirement obligation is required to be recognized at its fair value when
incurred. The cost of the asset retirement obligation is required to be
capitalized by increasing the carrying amount of the related long-lived asset by
the same amount as the liability. This cost must be expensed using a systematic
and rational method over the related asset's useful life. SFAS 143 is effective
for the Company beginning January 1, 2003. The Company is currently assessing
the impact of SFAS 143 and is unable to predict its impact on the Company's
operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the
FASB issued SFAS 144. The statement retains the requirements of the previously
issued pronouncement on asset impairment, Statement of Financial Accounting
Standards No. 121 ("SFAS 121"); however the SFAS 144 removes goodwill from the
73
scope of SFAS 121, provides for a probability-weighted cash flow estimation
approach for estimating possible future cash flows, and establishes a "primary
asset" approach for a group of assets and liabilities that represents the unit
of accounting to be evaluated for impairment. In addition, SFAS 144 changes the
measurement of long-lived assets to be disposed of by sale, as accounted for by
Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued
operations are no longer measured on a net realizable value basis, and their
future operating losses are no longer recognized before they occur. The Company
does not believe SFAS 144 will have a material effect on its future operating
results or financial position.
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 all forward-looking statements are based upon current
expectations and are subject to risk and uncertainties. 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 the local and
national economy, changes in supply and demand in the market for electric power,
the outcome of litigation relating to the Company's terminated transaction with
Western Resources, the performance of generating units and transmission system,
and state and federal regulatory and legislative decisions and actions,
including the wholesale electric power pricing mitigation plan ordered by FERC
on June 18, 2001, rulings issued by the PRC pursuant to the Electric Utility
Industry Restructuring Act of 1999, as amended, and in other cases now pending
or which may be brought before the FERC and the PRC and any action by the New
Mexico Legislature to further 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 and wholesale power markets in the West, could cause the Company's
results or outcomes to differ materially from those indicated by such
forward-looking statements in this filing.
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, changes in interest rates
and, historically, 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 the Company's financial instruments is set forth in "Critical
Accounting Policies" section of Management's Discussion of Results of Operations
and Financial Condition and the Financial Instruments note in the Notes to the
Consolidated Financial Statements and incorporated by reference. The following
additional information is provided.
Risk Management
The Company controls the scope of its various forms of risk through a
comprehensive set of policies and procedures and oversight by senior level
management and the Board of Directors. The Company's Finance Committee of the
Board of Directors sets the risk limit parameters. An internal risk management
committee ("RMC"), comprised of corporate and business segment officers,
oversees all of the activities, which include commodity price, credit, equity,
interest rate and business risks. The RMC has oversight for the ongoing
evaluation of the adequacy of the risk control organization and policies. The
Company has a risk control organization, headed by the Director of Financial
Risk Management ("Risk Manager"), which is assigned responsibility for
establishing and enforcing the policies, procedures and limits and evaluating
the risks inherent in proposed transactions, on an enterprise-wide basis.
74
The RMC's responsibilities specifically include: establishment of a
general policy regarding risk exposure levels and activities in each of the
business units; recommendation of the types of instruments permitted for
trading; authority to establish a general policy regarding counterparty exposure
and limits; authorization and delegation of trading transaction limits for
trading activities; review and approval of controls and procedures for the
trading activities; review and approval of models and assumptions used to
calculate mark-to-market and risk exposure; authority to approve and open
brokerage and counterparty accounts for derivative trading; review for trading
and risk activities; and quarterly reporting to the Finance Committee and the
Board of Directors on these activities.
The RMC also proposes Value at Risk ("VAR") limits to the Finance
Committee. The Finance Committee ultimately sets the aggregate VAR limit.
It is the responsibility of each business unit to create its own control
and procedures policy for trading within the parameters established by the
Finance Committee. The RMC reviews and approves these policies, which are
created with the assistance of the Chief Accounting Officer, Director of
Internal Audit and the Risk Manager. Each business units' policies address the
following controls: authorized risk exposure limits; authorized trading
instruments and markets; authorized traders; policies on segregation of duties;
policies on marking to market; responsibilities for trade capture; confirmation
procedures; responsibilities for reporting results; statement on the role of
derivatives trading; and limits on individual transaction size (nominal value)
for traders.
To the extent an open position exists, fluctuating commodity prices can
impact financial results and financial position, either favorably or
unfavorably. As a result, the Company cannot predict with precision the impact
that its risk management decisions may have on its businesses, operating results
or financial position.
Commodity Risk
Trading and marketing operations often involve market risks associated
with managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis. These risks fall into three different
categories: price and volume volatility, credit risk of trading counterparties
and adequacy of the control environment for trading. The company routinely
enters into forward contracts and options to hedge purchase and sale
commitments, fuel requirements and to minimize the risk of market fluctuations
on the Generation and Trading Operations.
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.
75
The Company assesses the risk of these derivatives using the VAR method,
in order to maintain the Company's total exposure within management-prescribed
limits. The Company utilizes the variance/covariance model of VAR, which is a
probabilistic model that measures the risk of loss to earnings in market
sensitive instruments. The variance/covariance model relies on statistical
relationships to analyze how changes in different markets can affect a portfolio
of instruments with different characteristics and market exposure. VAR models
are relatively sophisticated; however, the quantitative risk information is
limited by the parameters established in creating the model. The instruments
being evaluated may trigger a potential loss in excess of calculated amounts if
changes in commodity prices exceed the confidence level of the model used. The
VAR methodology employs the following critical parameters: volatility estimates,
market values of open positions, appropriate market-oriented holding periods and
seasonally adjusted correlation estimates. The Company uses a holding period of
three days as the estimate of the length of time that will be needed to
liquidate the positions. The volatility and the correlation estimates measure
the impact of adverse price movements both at an individual position level as
well as at the total portfolio level. The confidence level established is 99%.
For example, if VAR is calculated at $10 million, it is estimated at a 99%
confidence level that if prices move against the Company's positions, the
Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10
million in the three days that it would take to liquidate the portfolio.
The Company accounts for the sale of its electric generation in excess of
its jurisdictional needs or the purchase of jurisdictional needs as non-trading.
Non-jurisdictional purchases for resale and subsequent resales are accounted for
as energy trading contracts. With respect to the Company's trading portfolio,
the VAR was $1.2 million. The Company calculates a portfolio VAR which in
addition to its trading portfolio includes all non-trading designated contracts,
its generation assets excluded from jurisdictional rates and any excess
jurisdictional capacity. This excess is determined using average peak forecasts
for the respective block of power in the forward market. The Company's portfolio
VAR was $12.4 million at December 31, 2001.
The Company's VAR is regularly monitored by the Company's RMC. The RMC
has put in place procedures to ensure that increases in VAR are reviewed and, if
deemed necessary, acted upon to reduce exposures. 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.
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 RMC. The
Company provides for losses due to market and credit risk. The Company's credit
risk with its largest counterparty as of December 31, 2001 and 2000 was $7.5
million and $16.7 million respectively.
76
The Company hedges certain portions of natural gas supply contracts in
order to protect its jurisdictional customers from adverse price fluctuations in
the natural gas market. The financial impact of all hedge gains and losses,
including the related costs of the program, is recoverable through the Company's
purchased gas adjustment clause as deemed prudently incurred by the PRC. As a
result, earnings are not affected by gains and losses generated by these
instruments.
Interest Rate Risk
As of December 31, 2001, the Company has an investment portfolio of
fixed-rate government obligations and corporate securities which is subject to
the risk of loss associated with movements in market interest rates. For
accounting purposes, the portfolio is classified as available-for-sale and is
marked-to-market. As a result, unrealized losses resulting from interest rate
increases are recorded as a component of comprehensive income. If interest rates
were to rise, 50 basis points from their levels at December 31, 2001, the fair
value of these instruments would decline by 0.6% or $0.9 million. In addition,
because of this interest rate sensitivity, early or unplanned redemption of
these investments in a period of increasing interest rates would subject the
Company to risk of a realized loss of principal as the fair market value of
these investments would be less than their carrying value. The Company employs
investment managers to mitigate this risk. As part of its investing strategies,
the Company has diversified its portfolio with investments of varying maturity,
obligors and limits credit exposure to high investment grade quality
investments.
The Company has long-term debt which subjects it to the risk of loss
associated with movements in market interest rates. All of the Company's
long-term debt is fixed-rate debt, and therefore, does not expose the Company's
earnings to a risk of loss due to adverse changes in market interest rates.
However, the fair value of these debts instruments would increase by
approximately 1.8% or $17.6 million if interest rates were to decline by 50
basis points from their levels at December 31, 2001. As of December 31, 2001,
the fair value of the Company's long-term debt was $974 million as compared to a
book-value of $954 million. In general, an increase in fair value would impact
earnings and cash flows if the Company were to re-acquire all or a portion of
its debt instruments in the open market prior to their maturity. Certain
issuances of the Company's debt have call dates in December 2002 and August
2003. To hedge against the risk of rising interest rates and their impact on the
economies of calling the debt, the Company has entered into two forward starting
swaps in 2001 and three additional contracts in 2002. These forward interest
rate swaps effectively lock-in interest rates for the notional amount of the
debt that is callable at a rate of approximately 4.9% plus an adjustment for the
Company's and industry's credit rating. At December 31, 2001, the fair market
value of these derivative financial instruments was approximately $2.0 million.
The Company contributed $6.1 million in 2001 to a trust established to
fund decommissioning costs for PVNGS. In January 2002, the Company contributed
$23.5 million for plan year 2001 to the trust for the Company's pension plan,
and other post retirement benefits. The securities held by the trusts had an
estimated fair value of $461.5 million as of December 31, 2001, of which
approximately 30% were fixed-rate debt securities that subject the Company to
risk of loss of fair value with movements in market interest rates. If rates
were to increase by 50 basis points from their levels at December 31, 2001, the
decrease in the fair value of the securities would be 3.0% or $4.0 million. The
Company does not currently recover or return in jurisdictional rates losses or
gains on these securities; therefore, the Company is at risk for shortfalls in
its funding of its obligations due to investment losses. However, the Company
does not believe that long-term market returns over the period of funding will
be less than required for the Company to meet its obligations.
77
Equity Market Risk
As discussed above under Interest Rate Risk, the Company contributes to
trusts established to fund its share of the decommissioning costs of PVNGS and
other post retirement benefits. The trust holds certain equity securities as of
December 31, 2001. These equity securities also expose the Company to losses in
fair value. Approximately 60% of the securities held by the various trusts were
equity securities as of December 31, 2001. Similar to the debt securities held
for funding decommissioning and certain pension and other postretirement costs,
the Company does not recover or return in jurisdictional rates losses or gains
on these equity securities.
In 2001, the Company implemented an enhanced cash management strategy
using derivative instruments based on the Standard & Poors 100 and 500 indices.
The strategy is designed to capitalize on high market volatility or benefit from
market direction. An investment manager is utilized to execute the program. The
program is carefully managed by the RMC and limited to a one-day VAR of $5
million and a loss limit of $7.5 million. Trades are closed-out before the end
of a reporting period and typically within the same day of execution. Recently,
the RMC recommended and the Finance Committee approved the use of derivatives
based on the Nasdaq composite index.
78
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Page
----
Management's Responsibility for Financial Statements................... F-1
Report of Independent Public Accountants............................... F-3
Financial Statements:
PNM Resources, Inc.
Consolidated Statements of Earnings............................. F-4
Consolidated Balance Sheets..................................... F-5
Consolidated Statements of Cash Flows........................... F-7
Consolidated Statements of Capitalization....................... F-8
Consolidated Statements of Comprehensive Income................. F-9
Public Service Company of New Mexico
Consolidated Statements of Earnings............................. F-10
Consolidated Balance Sheets..................................... F-11
Consolidated Statements of Cash Flows........................... F-13
Consolidated Statements of Capitalization....................... F-14
Consolidated Statements of Comprehensive Income................. F-15
Notes to Consolidated Financial Statements ......................... F-16
Supplementary Data:
Quarterly Operating Results......................................... F-53
Comparative Operating Statistics.................................... F-54
Report of Independent Public Accountants............................ F-56
Schedule I Condensed Financial Information of Parent Company........ F-57
Schedule II Valuation and Qualifying Accounts....................... F-59
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The accompanying financial statements, of PNM Resources, Inc. and its
subsidiaries and Public Service Company of New Mexico and its subsidiaries, a
wholly owned subsidiary of PNM Resources, Inc. 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 PNM Resources,
Inc.'s and Public Service Company of New Mexico'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.
F-1
The Audit Committee of the Board of Directors of PNM Resources, Inc., 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-2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- ----------------------------------------
To the Board of Directors and Stockholders of
PNM Resources, Inc. and Public Service Company of New Mexico:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of PNM Resources, Inc. (a New Mexico Corporation) and
subsidiaries and Public Service Company of New Mexico and subsidiaries (a New
Mexico Corporation) as of December 31, 2001 and 2000, and the related
consolidated statements of earnings, cash flows and comprehensive income for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Companies' 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 PNM Resources, Inc. and
subsidiaries and Public Service Company of New Mexico and subsidiaries as of
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001 in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
February 1, 2002
F-3
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
Year Ended December 31,
---------------------------------------
2001 2000 1999
------------ ------------ ------------
(In thousands, except per share amounts)
Operating Revenues: (note 1)
Electric................................................... $1,965,142 $1,289,192 $ 911,977
Gas........................................................ 385,418 319,924 236,711
Unregulated businesses..................................... 1,538 2,158 8,855
------------ ------------ ------------
Total operating revenues................................ 2,352,098 1,611,274 1,157,543
------------ ------------ ------------
Operating Expenses:
Cost of energy sold........................................ 1,536,566 949,880 531,952
Administrative and general................................. 155,392 147,268 153,709
Energy production costs.................................... 152,455 139,894 140,784
Depreciation and amortization.............................. 96,936 93,059 92,661
Transmission and distribution costs........................ 69,001 60,330 59,264
Taxes, other than income taxes............................. 30,302 34,405 34,084
Income taxes (note 7)...................................... 88,769 53,964 25,010
------------ ------------ ------------
Total operating expenses................................ 2,129,421 1,478,800 1,037,464
------------ ------------ ------------
Operating income........................................ 222,677 132,474 120,079
------------ ------------ ------------
Other Income and Deductions:
Other...................................................... (15,110) 54,296 47,500
Income tax expense (note 7)............................... 7,706 (20,382) (17,298)
------------ ------------ ------------
Net other income and deductions......................... (7,404) 33,914 30,202
------------ ------------ ------------
Income before interest charges.......................... 215,273 166,388 150,281
------------ ------------ ------------
Interest Charges:
Interest on long-term debt (note 3)........................ 62,716 62,823 65,899
Other interest charges..................................... 2,124 2,619 4,768
------------ ------------ ------------
Net interest charges.................................... 64,840 65,442 70,667
------------ ------------ ------------
Net Earnings from Continuing Operations...................... 150,433 100,946 79,614
Cumulative Effect of a Change in Accounting..................
Principle, Net of Tax..................................... - - 3,541
------------ ------------ ------------
Net Earnings................................................. 150,433 100,946 83,155
Preferred Stock Dividend Requirements........................ 586 586 586
------------ ------------ ------------
Net Earnings Applicable to Common Stock...................... $ 149,847 $ 100,360 $ 82,569
============ ============ ============
Net Earnings per Share of Common Stock (Basic) (note 6)...... $ 3.83 $ 2.54 $ 2.01
============ ============ ============
Net Earnings per Share of Common Stock (Diluted) (note 6).... $ 3.77 $ 2.53 $ 2.01
============ ============ ============
Dividends Paid per Share of Common Stock..................... $ 0.80 $ 0.80 $ 0.80
============ ============ ============
The accompanying notes are an integral part of these financial statements.
F-4
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
As of December 31,
-------------------------
2001 2000
----------- ------------
(In thousands)
Utility Plant, at original cost except PVNGS: (notes 10, 11)
Electric plant in service..................................................... $2,118,417 $2,030,813
Gas plant in service.......................................................... 575,350 553,755
Common plant in service and plant held for future use......................... 45,223 36,678
----------- ------------
2,738,990 2,621,246
Less accumulated depreciation and amortization................................ 1,234,629 1,153,377
----------- ------------
1,504,361 1,467,869
Construction work in progress................................................. 249,656 123,653
Nuclear fuel, net of accumulated amortization of $16,954 and $19,081.......... 26,940 25,784
----------- ------------
Net utility plant.......................................................... 1,780,957 1,617,306
----------- ------------
Other Property and Investments:
Other investments (notes 5, 11)............................................... 552,453 479,821
Non-utility property, net of accumulated depreciation of $1,580 and $1,644.... 1,784 3,666
----------- ------------
Total other property and investments....................................... 554,237 483,487
----------- ------------
Current Assets:
Cash and cash equivalents..................................................... 26,057 107,691
Accounts receivables, net of allowances of $18,025 and $13,279............... 147,787 238,426
Other receivables............................................................. 52,158 64,857
Inventories................................................................... 36,483 36,091
Regulatory assets (note 2).................................................... 10,473 47,604
Short-term investments........................................................ 45,111 -
Other current assets.......................................................... 31,428 11,417
----------- ------------
Total current assets....................................................... 349,497 506,086
----------- ------------
Deferred charges:
Regulatory assets (note 2).................................................... 197,948 228,255
Prepaid pension cost (note 8)................................................. 18,273 18,116
Other deferred charges........................................................ 33,726 36,667
----------- ------------
Total deferred charges..................................................... 249,947 283,038
----------- ------------
$2,934,638 $2,889,917
=========== ============
The accompanying notes are an integral part of these financial statements.
F-5
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILIITES
As of December 31,
--------------------------
2001 2000
------------ ------------
(In thousands)
Capitalization: (note 3)
Common stock equity:
Common stock outstanding--39,118 shares, no par value........................ $ 625,632 $ 627,811
Accumulated other comprehensive income, net of tax (note 3).................. (28,996) (27)
Retained earnings............................................................ 415,388 296,843
------------ ------------
Total common stock equity................................................. 1,012,024 924,627
Minority interest.............................................................. 11,652 12,211
Cumulative preferred stock without mandatory redemption requirements........... 12,800 12,800
Long-term debt, less current maturities (note 3)............................... 953,884 953,823
------------ ------------
Total capitalization........................................................ 1,990,360 1,903,461
------------ ------------
Current Liabilities:
Short-term debt................................................................ 35,000 -
Accounts payable............................................................... 120,918 257,991
Accrued interest and taxes..................................................... 72,022 36,889
Other current liabilities...................................................... 101,697 67,758
------------ ------------
Total current liabilities................................................... 329,637 362,638
------------ ------------
Deferred Credits:
Accumulated deferred income taxes (note 7)..................................... 120,153 166,249
Accumulated deferred investment tax credits (note 7)........................... 44,714 47,853
Regulatory liabilities (note 2)................................................ 52,890 65,552
Regulatory liabilities related to accumulated deferred income tax (note 2)..... 14,163 20,696
Accrued postretirement benefits cost (note 8).................................. 14,929 11,899
Other deferred credits (note 12)............................................... 367,792 311,569
------------ ------------
Total deferred credits...................................................... 614,641 623,818
------------ ------------
Commitments and Contingencies (note 11).......................................... - -
------------ ------------
$ 2,934,638 $ 2,889,917
============ ============
The accompanying notes are an integral part of these financial statements.
F-6
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
--------------------------------
2001 2000 1999
---------- ---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net earnings.......................................................... $150,433 $100,946 $ 83,155
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization..................................... 106,768 103,829 103,891
Gain on cumulative effect of a change in
accounting principle .......................................... - - (5,862)
Other............................................................. 34,874 33,268 26,170
Changes in certain assets and liabilities:
Accounts receivables............................................ 90,639 (90,680) (16,937)
Other assets.................................................... 32,481 (32,444) (20,189)
Accounts payable................................................ (137,073) 107,346 36,670
Other liabilities............................................... 46,873 18,682 6,147
---------- ---------- ----------
Net cash flows provided from operating activities......... 324,995 240,947 213,045
---------- ---------- ----------
Cash Flows From Investing Activities:
Utility plant additions............................................... (264,844) (146,878) (95,298)
Return of principal PVNGS lessor's notes.............................. 16,674 16,668 16,903
Merger acquisition costs.............................................. (11,567) (6,700) -
Short-term and long-term investments.................................. (156,107) (5,307) (3,076)
Other investing....................................................... 8,830 (16,715) 25,585
---------- ---------- ----------
Net cash flows used in investing activities............... (407,014) (158,932) (55,886)
---------- ---------- ----------
Cash Flows From Financing Activities:
Borrowings (note 3)................................................... 35,000 - 11,500
Repayments (note 3)................................................... - (32,800) (58,200)
Exercise of employee stock options (note 9)........................... (2,179) (1,232) 1,453
Common stock repurchase (note 3)...................................... - (27,867) (18,799)
Dividends paid........................................................ (31,876) (32,265) (33,359)
Other Financing....................................................... (560) (559) (635)
---------- ---------- ----------
Net cash flows generated (used) by financing activities... 385 (94,723) (98,040)
---------- ---------- ----------
Increase (Decrease) in Cash and Cash Equivalents........................ (81,634) (12,708) 59,119
Beginning of Year....................................................... 107,691 120,399 61,280
---------- ---------- ----------
End of Year............................................................. $ 26,057 $ 107,691 $ 120,399
========== ========== ==========
Supplemental cash flow disclosures:
Interest paid......................................................... $ 62,216 $ 64,045 $ 67,770
========== ========== ==========
Income taxes paid, net of refunds..................................... $ 72,146 $ 50,480 $ 36,575
========== ========== ==========
Acquired pipeline in exchange for transportation services............. $ - $ - $ 3,100
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
F-7
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,
--------------------------
2001 2000
------------ ------------
(In thousands)
Common Stock Equity: (note 3)
Common Stock, no par value............................................. $ 625,632 $ 627,811
Accumulated other comprehensive income, net of tax..................... (28,996) (27)
Retained earnings...................................................... 415,388 296,843
------------ ------------
Total common stock equity.......................................... 1,012,024 924,627
------------ ------------
Minority Interest.......................................................... 11,652 12,211
------------ ------------
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, 2001 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................................................. 100,025 100,025
Other, including unamortized discounts................................ (406) (467)
------------ ------------
Total long-term debt.......................................... 953,884 953,823
------------ ------------
Total Capitalization....................................................... $1,990,360 $ 1,903,461
============ ============
The accompanying notes are an integral part of these financial statements.
F-8
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
-----------------------------------
2001 2000 1999
----------- ----------- -----------
(In thousands)
Net Earnings............................................................. $150,433 $100,946 $83,155
----------- ----------- -----------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising from the period................... (111) 2,794 4,120
Less reclassification adjustment for gains included in net income.. (345) (5,173) (4,282)
Minimum pension liability adjustment................................. (28,858) - 1,387
Mark-to-market adjustment for certain derivative transactions
Initial implementation of SFAS 133 designated cash flow hedges..... 6,148 - -
Change in fair market value of designated cash flow hedges......... 345 - -
Less reclassification adjustment for gains (losses)
in cash flow hedges............................................ (6,148) - -
----------- ----------- -----------
Total Other Comprehensive Income......................................... (28,969) (2,379) 1,225
----------- ----------- -----------
Total Comprehensive Income............................................... $121,464 $ 98,567 $ 84,380
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
F-9
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
Year Ended December 31,
--------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
(In thousands, except per share amounts)
Operating Revenues: (note 1)
Electric........................................... $1,965,142 $1,289,192 $ 911,977
Gas................................................ 385,418 319,924 236,711
Unregulated businesses............................. 1,538 2,158 8,855
--------------- --------------- ---------------
Total operating revenues........................ 2,352,098 1,611,274 1,157,543
--------------- --------------- ---------------
Operating Expenses:
Cost of energy sold................................ 1,536,566 949,880 531,952
Administrative and general......................... 155,392 147,268 153,709
Energy production costs............................ 152,455 139,894 140,784
Depreciation and amortization...................... 96,936 93,059 92,661
Transmission and distribution costs................ 69,001 60,330 59,264
Taxes, other than income taxes..................... 30,302 34,405 34,084
Income taxes (note 7).............................. 88,769 53,964 25,010
--------------- --------------- ---------------
Total operating expenses........................ 2,129,421 1,478,800 1,037,464
--------------- --------------- ---------------
Operating income................................ 222,677 132,474 120,079
--------------- --------------- ---------------
Other Income and Deductions:
Other.............................................. (15,110) 54,296 47,500
Income tax expense (note 7)....................... 7,706 (20,382) (17,298)
--------------- --------------- ---------------
Net other income and deductions................. (7,404) 33,914 30,202
--------------- --------------- ---------------
Income before interest charges.................. 215,273 166,388 150,281
--------------- --------------- ---------------
Interest Charges:
Interest on long-term debt (note 3)................ 62,716 62,823 65,899
Other interest charges............................. 2,124 2,619 4,768
--------------- --------------- ---------------
Net interest charges............................ 64,840 65,442 70,667
--------------- --------------- ---------------
Net Earnings from Continuing Operations.............. 150,433 100,946 79,614
Cumulative Effect of a Change in Accounting..........
Principle, Net of Tax............................. - - 3,541
--------------- --------------- ---------------
Net Earnings Before Preferred Stock Dividends........ 150,433 100,946 83,155
Preferred Stock Dividend Requirements................ 586 586 586
--------------- --------------- ---------------
Net Earnings......................................... $ 149,847 $ 100,360 $ 82,569
=============== =============== ===============
The accompanying notes are an integral part of these financial statements.
F-10
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
As of December 31,
--------------------------
2001 2000
------------ ------------
(In thousands)
Utility Plant, at original cost except PVNGS: (notes 10, 11)
Electric plant in service..................................................... $2,118,417 $2,030,813
Gas plant in service.......................................................... 575,350 553,755
Common plant in service and plant held for future use......................... 45,223 36,678
------------ ------------
2,738,990 2,621,246
Less accumulated depreciation and amortization................................ 1,234,629 1,153,377
------------ ------------
1,504,361 1,467,869
Construction work in progress................................................. 249,656 123,653
Nuclear fuel, net of accumulated amortization of $16,954 and $19,081.......... 26,940 25,784
------------ ------------
Net utility plant.......................................................... 1,780,957 1,617,306
------------ ------------
Other Property and Investments:
Other investments (notes 5, 11)............................................... 446,784 479,821
Non-utility property, net of accumulated depreciation of $1,580 and $1,644.... 1,784 3,666
------------ ------------
Total other property and investments....................................... 448,568 483,487
------------ ------------
Current Assets:
Cash and cash equivalents..................................................... 14,677 107,691
Accounts receivables, net of allowances of $18,025 and $13,279............... 147,787 238,426
Other receivables............................................................. 52,158 64,857
Inventories................................................................... 36,483 36,091
Regulatory assets (note 2).................................................... 10,473 47,604
Short-term investments........................................................ 45,111 -
Other current assets.......................................................... 21,477 11,417
------------ ------------
Total current assets....................................................... 328,166 506,086
------------ ------------
Deferred charges:
Regulatory assets (note 2).................................................... 187,475 228,255
Prepaid pension cost (note 8)................................................. 18,273 18,116
Other deferred charges........................................................ 44,199 36,667
------------ ------------
Total deferred charges..................................................... 249,947 283,038
------------ ------------
$2,807,638 $2,889,917
============ ============
The accompanying notes are an integral part of these financial statements.
F-11
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILIITES
As of December 31,
----------------------------
2001 2000
------------- -------------
(In thousands)
Capitalization: (note 3)
Common Stock Equity:
Common stock outstanding 39,118 shares...................................... $195,589 $195,589
Paid-in capital............................................................. 430,043 432,222
Accumulated other comprehensive income, net of tax (note 3)................. (28,996) (27)
Retained earnings........................................................... 288,388 296,843
------------- -------------
Total equity............................................................. 885,024 924,627
Minority interest............................................................. 11,652 12,211
Cumulative preferred stock without mandatory redemption requirements.......... 12,800 12,800
Long-term debt, less current maturities (note 3).............................. 953,884 953,823
------------- -------------
Total capitalization....................................................... 1,863,360 1,903,461
------------- -------------
Current Liabilities:
Short-term debt............................................................... 35,000 -
Accounts payable.............................................................. 120,918 257,991
Accrued interest and taxes.................................................... 72,022 36,889
Other current liabilities..................................................... 101,697 67,758
------------- -------------
Total current liabilities.................................................. 329,637 362,638
------------- -------------
Deferred Credits:
Accumulated deferred income taxes (note 7).................................... 120,153 166,249
Accumulated deferred investment tax credits (note 7).......................... 44,714 47,853
Regulatory liabilities (note 2)............................................... 52,890 65,552
Regulatory liabilities related to accumulated deferred income tax (note 2).... 14,163 20,696
Accrued postretirement benefits cost (note 8)................................. 14,929 11,899
Other deferred credits (note 12).............................................. 367,792 311,569
------------- -------------
Total deferred credits..................................................... 614,641 623,818
------------- -------------
Commitments and Contingencies (note 11)......................................... - -
------------- -------------
$ 2,807,638 $ 2,889,917
============= =============
The accompanying notes are an integral part of these financial statements.
F-12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
-------------------------------------
2001 2000 1999
----------- ----------- -----------
(In thousands)
Cash Flows From Operating Activities:
Net earnings......................................................... $150,433 $100,946 $ 83,155
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization.................................... 106,768 103,829 103,891
Gain on cumulative effect of a change in
Accounting principle ......................................... - - (5,862)
Other............................................................ 34,874 33,268 26,170
Changes in certain assets and liabilities:
Accounts receivables........................................... 90,639 (90,680) (16,937)
Other assets................................................... 42,432 (32,444) (20,189)
Accounts payable............................................... (137,073) 107,346 36,670
Other liabilities.............................................. 46,873 18,682 6,147
----------- ----------- -----------
Net cash flows provided from operating activities........ 334,946 240,947 213,045
----------- ----------- -----------
Cash Flows From Investing Activities:
Utility plant additions.............................................. (264,844) (146,878) (95,298)
Return of principal PVNGS lessor's notes............................. 16,674 16,668 16,903
Merger acquisition costs............................................. (11,567) (6,700) -
Short-term and long-term investments................................. (50,438) (5,307) -
Other investing...................................................... 8,830 (16,715) 22,509
----------- ----------- -----------
Net cash flows used in investing activities.............. (301,345) (158,932) (55,886)
----------- ----------- -----------
Cash Flows From Financing Activities:
Borrowings (note 3).................................................. 35,000 - 11,500
Repayments (note 3).................................................. - (32,800) (58,200)
Exercise of employee stock options (note 9).......................... (2,179) (1,232) 1,453
Common stock repurchase (note 3)..................................... - (27,867) (18,799)
Dividends paid....................................................... (158,876) (32,265) (33,359)
Other Financing...................................................... (560) (559) (635)
----------- ----------- -----------
Net cash flows generated (used) by financing activities.. (126,615) (94,723) (98,040)
----------- ----------- -----------
(Decrease) Increase in Cash and Cash Equivalents....................... (93,014) (12,708) 59,119
Beginning of Year...................................................... 107,691 120,399 61,280
----------- ----------- -----------
End of Year............................................................ $ 14,677 $ 107,691 $ 120,399
=========== =========== ===========
Supplemental cash flow disclosures:
Interest paid........................................................ $ 62,216 $ 64,045 $ 67,770
=========== =========== ===========
Income taxes paid, net of refunds.................................... $ 72,146 $ 50,480 $ 36,575
=========== =========== ===========
Acquired DOE pipeline in exchange for transportation services........ $ - $ - $ 3,100
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
F-13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,
---------------------------------
2001 2000
--------------- ---------------
(In thousands)
Common Stock Equity: (note 3)
Common stock outstanding par value $ 5 per share...................... $ 195,589 $ 195,589
Paid-in capital....................................................... 430,043 432,222
Accumulated other comprehensive income, net of tax.................... (28,996) (27)
Retained earnings..................................................... 288,388 296,843
--------------- --------------
Total equity...................................................... 885,024 924,627
--------------- --------------
Minority Interest......................................................... 11,652 12,211
--------------- --------------
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, 2001 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................................................ 100,025 100,025
Other, including unamortized discounts............................... (406) (467)
--------------- --------------
Total long-term debt......................................... 953,884 953,823
--------------- --------------
Total Capitalization...................................................... $ 1,863,360 $ 1,903,461
=============== ==============
The accompanying notes are an integral part of these financial statements.
F-14
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
---------------------------------
2001 2000 1999
---------- ---------- ---------
(In thousands)
Net Earnings.............................................................. $150,433 $100,946 $83,155
---------- ---------- ---------
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains arising from the period.................... (111) 2,794 4,120
Less reclassification adjustment for gains included in net income... (345) (5,173) (4,282)
Minimum pension liability adjustment.................................. (28,858) - 1,387
Mark-to-market adjustment for certain derivative transactions
Initial implementation of SFAS 133 designated cash flow hedges...... 6,148 - -
Change in fair market value of designated cash flow hedges.......... 345 - -
Less reclassification adjustment for gains (losses)
in cash flow hedges............................................. (6,148) - -
---------- ---------- ---------
Total Other Comprehensive Income.......................................... (28,969) (2,379) 1,225
---------- ---------- ---------
Total Comprehensive Income................................................ $121,464 $ 98,567 $84,380
========== ========== =========
The accompanying notes are an integral part of these financial statements.
F-15
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Summary of Significant Accounting Policies
Nature of Business
PNM Resources, Inc. (the "Company") is a holding company of energy and
energy related activities. Its principal subsidiary, Public Service Company of
New Mexico ("PNM"), is an integrated public utility primarily engaged in the
generation, transmission, distribution and sale and trading of electricity;
transmission, distribution and sale of natural gas within the State of New
Mexico and the sale and trading of electricity in the Western United States. In
addition, the Company provides energy and utility related services under its
wholly-owned subsidiary, Avistar, Inc. ("Avistar").
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Company, the Company became the parent company of PNM. Prior
to the share exchange, the Company had existed as a subsidiary of PNM. The new
holding company began trading on the New York Stock Exchange under the same PNM
symbol beginning on December 31, 2001.
Presentation
The Notes to the Consolidated Financial Statements of the Company and
PNM are presented on a combined basis. The Company as an unconsolidated holding
company ("Holding Company") had no material operations for the year ended
December 31, 2001. Except for its consolidated investment in PNM, the Holding
Company's only assets were cash of $11 million, short-term investments of $10
million and long-term investments of $106 million at December 31, 2001. In
addition, the Holding Company had no liabilities at December 31, 2001.
Accordingly, the reader of the Notes to the Consolidated Financial Statements
should assume that the information presented applies to consolidated results of
operations and financial position of both the Company and PNM, except where the
context or references clearly indicate otherwise. Discussions regarding specific
contractual obligations generally reference the company that is legally
obligated. In the case of contractual obligations of PNM, these obligations are
consolidated with the Company under Generally Accepted Accounting Principles.
Broader operational discussion references the Company.
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.
F-16
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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 Statement of
Financial Accounting Standards No. 101, Accounting for the Discontinuation of
Application of FASB Statement No. 71 ("SFAS 101"). The Company evaluates its
regulatory assets under Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of ("SFAS 121"). In 2000, the Company determined certain stranded
costs would not be recovered and recorded a charge to earnings for these amounts
recorded as stranded cost assets. The Company believes that it will recover
costs associated with its remaining stranded cost 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 or meets
the criteria of Emerging Issues Task Force 90-15, Impact of Non-Substantive
Lessors, Residual Value Guarantees and Other Provisions in Leasing Transactions.
All significant intercompany transactions and balances have been eliminated.
There were no intercompany transactions between the Company and PNM in 2001,
except the dividend described in Note 3.
Financial Statement Preparation
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.
Utility Plant
Utility plant, with the exception of Palo Verde Nuclear Generating
Station ("PVNGS") Unit 3, a portion San Juan Generating Station ("SJGS") Unit 4
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. In 1989, PVNGS Unit 3 and a portion of SJGS Unit 4 were
excluded from the jurisdictional rate base. As a result, PNM, wrote-down $17.4
million of its carrying cost related to these assets. In 1993, PNM announced
specific actions determined to be necessary in order to accelerate PNM's
preparation for the competitive electric energy market. As part of this
announcement, PNM stated its intention to attempt to sell PVNGS Unit 3. As a
result, PNM wrote-down PVNGS Unit 3 $181.3 million based on the estimated net
realizable value of the asset. Since that time, PNM has decided not to sell
PVNGS Unit 3. In connection with a rate reduction in 1994, the Company wrote
down $131.6 million of its owned interest in Units 1 and 2. Pursuant to a rate
F-17
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
stipulation dated October 1993, the Company did not capitalize amounts relating
to an allowance for funds used during construction in 2001, 2000 or 1999.
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.
Investments
The Company's investments comprise U.S., state, and municipal government
obligations and corporate securities. Investments with maturities of less than
one year are considered short-term and are carried at fair value. All
investments are held in the Company's name and custodied with major financial
institutions. The specific identification method is used to determine the cost
of securities disposed of, with realized gains and losses reflected in other
income and expense. At December 31, 2001, all of the Company's investments were
classified as available for sale. Unrealized gains and losses on these
investments are included as a separate component of shareholders' equity, net of
any related tax effect.
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 adjustments for differences in gas purchase costs
that are above or below 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 or as
services are provided. These electricity sales are recorded as operating
revenues while the electricity purchases are recorded as costs of energy sold.
These amounts are recorded on a gross basis, because the Company does not act as
an agent or broker for these energy trading contracts but takes title and has
the risks and rewards of ownership. 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,
are recorded gross in operating revenues and fuel and purchased power expense.
"Net settling" is where the unplanned netting of delivery and acceptance of
electric power for convenience of transmission and settlement occurs (referred
to as a "bookout").
The Company enters into energy trading contracts to take advantage of
market opportunities associated with the purchase and sale of electricity.
Unrealized gains and losses resulting from the impact of price movements on the
Company's trading contracts are recognized as adjustments to Generation and
Trading Operations operating revenues. The market prices used to value these
F-18
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
trading 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.
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. The costs are deferred until the period in which they are billed or
credited to customers. The Company's gas purchase costs are recoverable under a
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:
2001 2000 1999
--------- -------- --------
Electric plant ...................... 3.39% 3.42% 3.38%
Gas plant ........................... 3.19% 3.28% 3.37%
Common plant ........................ 6.92% 6.75% 7.73%
The provision for depreciation of certain equipment is 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
F-19
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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.
Financial Instruments
In December 1998, the Emerging Issues Task Force ("EITF") of the
Financial Accounting Standards Board ("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)
The Company implemented Statement of Financial Accounting Standards No.
133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"),
as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and
reporting standards requiring derivative instruments to be recorded in the
balance sheet as either an asset or liability measured at their fair value. SFAS
133, as amended, also requires that changes in the derivatives' fair value be
recognized currently in earnings unless specific hedge accounting or normal
purchase and sale 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. 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.
Stock Options
The Company accounts for stock-based compensation using the intrinsic
value method prescribed in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees". Compensation cost for stock options,
if any, is measured as the excess of the quoted market price of the Company's
stock at the date of grant over the exercise price of the granted stock option.
Restricted stock is recorded as compensation cost over the requisite vesting
periods based on the market value on the date of grant.
Statement of Financial Accounting Standards No. 123, Accounting for
Stock-Based Compensation ("SFAS 123"), established accounting and disclosure
requirements using a fair-value-based method of accounting for stock-based
employee compensation plans. The Company has elected to remain on its current
method of accounting as described above, and has adopted the disclosure
requirements of SFAS No. 123.
F-20
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Income Taxes
The Company accounts for income taxes in accordance with the provisions
of Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS No. 109"), which uses the asset and liability method for
accounting for income taxes. Under SFAS 109, deferred tax assets and liabilities
are recognized for the estimated future tax consequences attributable to
differences between the financial statement carrying value of existing assets
and liabilities and their respective tax basis. Current PRC jurisdictional rates
include the tax effects of the majority of these differences. SFAS No. 109
requires that rate-regulated enterprises record deferred income taxes for
temporary differences accorded flow-through treatment at the direction of a
regulatory commission. The resulting deferred tax assets and liabilities are
recorded at the expected cash flow to be reflected in future rates. Since the
PRC has consistently permitted the recovery of previously flowed-through tax
effects, the Company has established regulatory liabilities and assets
offsetting such deferred tax assets and liabilities. 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. 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 as currently prescribed by GAAP (see Note 4).
Change in Presentation
Certain prior year amounts have been reclassified to conform to the 2001
financial statement presentation.
(1) Segment Information
As it currently operates, the Company's principal business segments are
Utility Operations, which include Electric Services ("Electric") and Gas
Services ("Gas"), and Generation and Trading Operations ("Generation and
Trading"). Electric 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-21
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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 378,000, 369,000 and
361,000 retail electric customers were served by the Company at December 31,
2001, 2000 and 1999, respectively. The Company owns or leases 2,890 circuit
miles of transmission lines, interconnected with other utilities in New Mexico
and south and east into Texas, west into Arizona, and north into Colorado and
Utah.
Electric exclusively acquires its electricity sold to retail customers
from the Company's Generation and Trading Operations. Intersegment purchases
from 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.
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 443,000, 435,000 and 426,000 customers as of December 31, 2001,
2000 and 1999, respectively. The Company's customer base includes both
sales-service customers and transportation-service customers.
In 2000 and the first quarter of 2001, the Company's Generation and
Trading Operations procured its gas fuel supply from Gas. In the second quarter
of 2001, the Company's Generation and Trading Operations began procuring its gas
supply independent of Gas and contracting with Gas for transportation services
only.
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. In addition to generation capacity, the Company purchases
power in the open market. As of December 31, 2001, 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.
F-22
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
UNREGULATED AND OTHER
The Company's wholly-owned subsidiary, Avistar, was formed in August
1999 as a New Mexico corporation and is currently engaged in certain unregulated
and non-utility businesses. Unregulated also, includes immaterial corporate
activities and eliminations. The immaterial corporate activities were assumed by
the Company on December 31, 2001.
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, incurred previously in providing power generation to
electric service customers, the market price of electricity and natural gas
costs 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 2001, 2000 and
1999 is as follows:
Utility
------------------------------ Unregulated
Electric Gas Total Generation and Other Consolidated
-------- --- ----- ---------- ----------- ------------
(In thousands)
Twelve Months Ended:
- --------------------
2001:
Operating revenues:
External customers.......... 559,226 385,418 944,644 1,405,916 1,538 2,352,098
Intersegment revenues....... 707 - 707 341,608 (342,315) -
Depreciation and amortization.. 32,666 21,465 54,131 42,766 39 96,936
Interest income................ 1,626 935 2,561 39,302 6,157 48,020
Net interest charges........... 19,868 11,807 31,675 28,282 4,883 64,840
Income tax expense (benefit)
From continuing operations... 26,547 5,710 32,257 90,097 (41,291) 81,063
Operating income (loss)........ 61,471 20,897 82,368 154,370 (14,061) 222,677
Segment net income (loss)...... 40,507 8,917 49,424 137,485 (36,476) 150,433
Total assets................... 770,798 469,410 1,240,208 1,430,917 263,513 2,934,638
Gross property additions....... 74,316 48,978 123,294 126,605 14,994 264,893
F-23
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Summarized financial information by business segment for 2001, 2000 and
1999 is as follows:
Utility
---------------------------- Unregulated
Electric Gas Total Generation and Other 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... 31,480 19,994 51,474 41,558 27 93,059
Interest income................. 1,158 517 1,675 39,439 7,581 48,695
Net interest charges............ 17,771 11,089 28,860 36,064 518 65,442
Income tax expense (benefit)
From continuing operations.... 30,346 9,632 39,978 45,304 (10,936) 74,346
Operating income (loss)......... 60,583 22,042 82,625 81,525 (31,676) 132,474
Segment net income (loss)....... 43,466 14,327 57,793 75,261 (32,108) 100,946
Total assets.................... 689,489 521,636 1,211,125 1,424,586 254,206 2,889,917
Gross property additions........ 51,815 40,418 92,233 53,025 1,620 146,878
Utility
----------------------------- Unregulated
Electric Gas Total Generation and Other Consolidated
-------- --- ----- ---------- ----------- ------------
(In thousands)
Twelve Months Ended:
- --------------------
1999:
Operating revenues:
External customers............. 540,868 236,711 777,579 371,109 8,855 1,157,543
Intersegment revenues.......... 707 - 707 318,872 (319,579) -
Depreciation and amortization..... 30,183 19,210 49,393 41,183 2,085 92,661
Interest income................... 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...... 24,174 2,299 26,473 25,086 (9,250) 42,309
Operating income (loss)........... 58,331 16,102 74,433 57,999 (12,353) 120,079
Cumulative effect of a change in
Accounting Principle, net of tax - - - 3,541 - 3,541
Segment net income (loss)......... 38,061 2,780 40,841 56,506 (14,192) 83,155
Total assets...................... 715,620 449,790 1,165,410 1,464,423 93,435 2,723,268
Gross property additions.......... 42,253 27,150 69,403 23,899 2,334 95,636
F-24
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
(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:
2001 2000
---------- ------------
(In thousands)
Assets:
Current:
PGAC ........................................ $ 9,065 $ 46,390
Gas Take-or-Pay Costs ....................... 1,408 1,214
----------- ------------
Subtotal ................................. 10,473 47,604
----------- ------------
Deferred:
Deferred Income Taxes........................ 33,632 33,848
Loss on Reacquired Debt...................... 6,798 7,687
Gas Imputed Revenues......................... 2,310 2,117
Deferred Customer Expense on Gas Assets Sale. - 7,984
Gas Retirees' Health Care Costs.............. - 1,724
Proposed Transmission Line Costs............. 2,222 2,377
Other 1,459 1,888
----------- ------------
Subtotal.................................. 46,421 57,625
----------- ------------
Stranded and Transition Assets.................... 151,527 170,630
----------- ------------
Total Assets.............................. 208,421 275,859
----------- ------------
Liabilities:
Deferred:
Deferred Income Taxes........................ (41,915) (43,834)
Gas Regulatory Reserve....................... (565) (980)
Customer Gain on Gas Assets Sale............. - (7,226)
Line Acquisition............................. (1,954) (2,490)
Gain on Reacquired Debt...................... (1,640) (1,791)
Other........................................ (332) (568)
----------- ------------
Subtotal..................................... (46,406) (56,889)
----------- ------------
Stranded and Transition Liabilities............... (20,647) (29,359)
----------- ------------
Total Liabilities............................ (67,053) (86,248)
----------- ------------
Net Regulatory Assets ....................... $ 141,368 $ 189,611
=========== ============
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. The Company does not receive or pay a material rate
of return on these regulatory assets and regulatory liabilities.
F-25
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
The Restructuring Act, as amended, 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 or determined to be recoverable 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 $142 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 through rates is probable as
established by law, these assets continue to be classified as regulatory assets,
although the Company's Generation and Trading Operations has discontinued SFAS
71 and adopted SFAS 101.
In 2001, the Company recognized the write-off of $13.0 million of
non-recoverable coal mine decommissioning costs previously established as a
regulatory asset. As a result of the Company's evaluation of its regulatory
strategy in light of its holding company filing in May 2001, management
determined that it would not seek recovery of a portion of its previously
established stranded cost asset that was not a component of retail ratemaking.
The remaining portion of costs associated with coal mine decommissioning that
are attributed to local jurisdictional customers will be sought in future rate
cases. The amendments to the Restructuring Act provide the opportunity for
amortization of coal mine decommissioning costs currently estimated at
approximately $100 million. The Company intends to seek recovery of these costs
in its next rate case filing and believes that the costs are fully recoverable.
The Company believes that any remaining portion of the regulatory assets will be
fully recovered in future rates, including through a non-bypassable wires
charge.
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 are presently scheduled
to be recovered beginning 2007 through 2012 by means of a separate wires charge.
The Company intends to seek recovery of incurred transition costs in any future
rate proceeding held before open access begins. Transition costs include
professional fees, financing costs including underwriting fees, costs relating
to the transfer of assets, the cost of management information system changes
including billing system changes and public and customer communications costs.
F-26
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
On December 31, 2001, the Company implemented a holding company structure
without separation of supply service and energy-related service assets from
distribution and transmission service assets as permitted under the amended
Restructuring Act. The Company is unable to predict the form its further
restructuring will take under delayed implementation of customer choice.
Accordingly, it cannot estimate the total expected amount of transition costs.
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 transition costs are as
follows:
2001 2000
------------ -----------
(In thousands)
Assets:
Transition Costs................................. $ 13,208 $ 19,069
Mine Reclamation Costs........................... 100,877 113,856
Deferred Income Taxes............................ 35,775 35,726
Loss on Reacquired Debt.......................... 1,667 1,979
------------ -----------
Subtotal.................................... 151,527 170,630
------------ -----------
Liabilities:
Deferred Income Taxes............................ (14,163) (20,696)
PVNGS Prudence Audit............................. (5,058) (5,434)
Settlement Due Customers......................... (1,408) (3,205)
Gain on Reacquired Debt.......................... (18) (24)
------------ -----------
Subtotal.................................... (20,647) (29,359)
------------ -----------
Net Stranded Cost and Transition Cost....... $ 130,880 $ 141,271
============ ===========
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-27
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
(3) Capitalization
Changes in common stock, additional paid-in capital and retained earnings are as
follows:
Common Stock
-----------------------------
Additional
Number Aggregate Paid-In Retained
Of Shares Par Value Capital Earnings
-------------- ------------- ------------- -------------
(Dollars in thousands)
Balance at December 31, 1999................ 40,703,383 $203,517 $453,393 $227,829
Stock repurchases........................... (1,585,584) (7,928) (19,939) -
Tax benefit from exercise of stock options.. - - (1,232) -
Net earnings................................ - - - 100,946
Dividends:
Cumulative preferred stock............... - - - (586)
Common Stock............................. - - - (31,346)
------------- ------------- ------------- -------------
Balance at December 31, 2000................ 39,117,799 195,589 432,222 296,843
Stock repurchase............................ - - - -
Exercise of stock options................... - - (2,179) -
Net earnings................................ - - - 150,433
Dividends:
Cumulative preferred stock............... - - - (586)
Common Stock............................. - - - (31,302)
------------- ------------- ------------- -------------
Balance at December 31, 2001................ 39,117,799 $195,589 $430,043 $415,388
============= ============= ============= =============
Common Stock
The number of authorized shares of common stock of the Company is 120
million shares with no par value. The declaration of common dividends is
dependent upon a number of factors including the ability of the Company's
subsidiaries to pay dividends. Currently, PNM is the Company's primary source of
dividends. As part of the order approving the formation of the holding company,
the PRC placed certain restrictions on the ability of PNM to pay dividends to
its parent.
The PRC order imposed the following conditions regarding dividends paid
by PNM to the holding company: PNM can not pay dividends which cause its debt
rating to go below investment grade; and PNM can not pay dividends in any year,
as determined on a rolling four quarter basis, in excess of net earnings without
prior PRC approval. Additionally, PNM has various financial covenants which
limit the transfer of assets, through dividends or other means.
In addition, the ability of the Company to declare dividends is dependent
upon the extent to which cash flows will support dividends, the availability of
retained earnings, the financial circumstances and performance, the PRC's
decisions in various regulatory cases currently pending and which may be
docketed in the future, the effect of deregulating generation markets and market
F-28
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
economic conditions generally. The ability to recover stranded costs in
deregulation (as amended), conditions imposed on holding company formation,
future growth plans and the related capital requirements and standard business
considerations may also affect the Company's ability to pay dividends.
Consistent with the PRC's holding company order, PNM paid dividends of
$127.0 million to the Company on December 31, 2001. On March 4, 2002, the PNM
Board of Directors declared an additional dividend of approximately $5.5
million, which was paid March 19, 2002.
On February 19, 2002, the Company's Board of Directors approved a 10
percent increase in the common stock dividend. The increase raises the quarterly
dividend to $0.22 per share, for an indicated annual dividend of $0.88 per
share. The Company's Board of Directors approved a policy for future dividend
increases in the range of 8 to 10 percent annually, targeting a payout of
between 50 to 60 percent of regulated earnings. The Company believes that this
target is consistent with the Company's expectation of future operating cash
flows and the cash needs of its planned increase in generating capacity.
In March 1999, PNM's Board of Directors approved a plan to repurchase up
to 1,587,000 shares of its outstanding common stock with maximum purchase price
of $19.00 per share. In December 1999, PNM Board of Directors authorized PNM to
repurchase up to an additional $20.0 million of its common stock. As of December
31, 1999, PNM repurchased 1,070,700 shares of its previously outstanding common
stock at a cost of $18.8 million. From January 2000 through March 2000, PNM
repurchased an additional 963,284 shares of its outstanding common stock at a
cost of $18.8 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 made no repurchases of its stock during
the year ended December 31, 2001. In September of 2001, the Board authorized
further repurchases of stock. However, the Company has not exercised this
authority.
Cumulative Preferred Stock
No Holding Company preferred stock is outstanding. The Company's restated
articles of incorporation authorize 10 million shares of preferred stock, which
may be issued without restriction. The number of authorized shares of PNM
cumulative preferred stock is 10 million shares. PNM 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 PNM. In addition, the 1965 Series is not entitled to a sinking fund and
cannot be converted into any other class of stock of PNM.
Long-Term Debt
PNM has $268,420,000 of long-term debt that matures in August 2005. All
other long-term debt matures in 2016 or later.
On March 11, 1998, PNM modified its 1947 Indenture of Mortgage and Deed
of Trust; no future bonds can be issued under the mortgage. While first mortgage
bonds continue to serve as collateral for PCBs in the outstanding principal
amount of $111 million, the lien of the mortgage covers only PNM's ownership
interest in PVNGS. Senior unsecured notes ("SUNs"), which were issued under a
senior unsecured note indenture, serve as collateral for PCBs in the outstanding
F-29
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
principal amount of $463.3 million. With the exception of the $111 million of
PCBs secured by first mortgage bonds, the SUNs are and will be the senior debt
of PNM.
In August 1998, PNM 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 and it is expected that future long-term debt
financings will be similarly issued. In 1999, PNM 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 leaving an outstanding
principal balance of $268.4 million. In January 2000, PNM 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 leaving an outstanding
principal balance of $100.0 million. The gains recognized on these purchases
were immaterial.
On October 28, 1999, tax-exempt pollution control revenue bonds of $11.5
million with an interest rate of 6.60% were issued by PNM to provide partial
reimbursement for expenditures associated with its share of a recently completed
upgrade of the emission control system at SJGS.
Revolving Credit Facility and Other Credit Facilities
At December 31, 2001, PNM had a $150 million unsecured revolving credit
facility (the "Facility") with an expiration date of March 11, 2003. PNM must
pay commitment fees of 0.1875% per year on the total amount of the Facility. PNM
also had $20 million in local lines of credit. In addition, the Holding Company
has a $20 million reciprocal borrowing agreement with PNM and $25 million in
local lines of credit.
There were $35.0 million in outstanding borrowings under the Facility,
bearing interest at 2.3875%, under the Facility as of December 31, 2001. On
January 31, 2002, this amount was refunded at an interest rate of 2.325%.
Subsequent to December 31, 2001, an additional $40.0 million was borrowed at an
interest rate of 2.20%, which was subsequently refunded at an interest rate of
2.3875% as of March 1, 2002. PNM was in compliance with all covenants under the
Facility.
(4) Lease Commitments
PNM 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 PNM's PVNGS Units 1 and 2 lease agreements limit
PNM'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.
F-30
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
In 1998, PNM established PVNGS Capital Trust ("Capital Trust"), for the
purpose of acquiring all the debt underlying the PVNGS leases. PNM consolidates
Capital Trust in its consolidated financial statements. The purchase was funded
with the proceeds from the issuance of $435 million of SUNS (see Note 3), which
were loaned to Capital Trust. Capital Trust then acquired and holds the debt
component of the PVNGS leases. For legal and regulatory reasons, the PVNGS lease
payment continues to be recorded and paid gross with the debt component of the
payment returned to PNM via Capital Trust. As a result, the net cash outflows
for the PVNGS lease payment were $12.4 million in 2001. The summary of PNM's
future minimum operating lease payments below, reflects the net cash outflow
related to the PVNGS leases.
PNM's other significant operating lease obligations include a
transmission line with annual lease payments of $7.3 million and a power
purchase agreement for the entire output of a gas-fired generating plant in
Albuquerque, New Mexico with imputed annual lease payments of $6.0 million.
Future minimum operating lease payments (in thousands) at December 31,
2001 are:
2002........................................ $ 32,095
2003........................................ 33,049
2004........................................ 33,113
2005........................................ 34,769
2006........................................ 35,587
Later years................................. 364,341
-----------
Total minimum lease payments ............ $ 532,954
===========
Operating lease expense, inclusive of the net PVNGS lease payment, was
approximately $32.7 million in 2001, $28.5 million in 2000 and $23.7 million in
1999. Aggregate minimum payments to be received in future periods under
non-cancelable subleases are approximately $5.3 million.
(Intentionally left blank)
F-31
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
(5) Financial Instruments
The estimated fair value of the Company's financial instruments
(including current maturities) at December 31, is as follows:
2001 2000
---- ----
Carrying Fair Carrying Fair
Amount Value Amount Value
------------------------- -------------------------
(In thousands)
Short-term and long-term
investment securities..................... $ 150,781(1) $ 150,781(1) $ - $ -
Long-Term Debt .............................. $ 953,884 $ 973,975 $ 953,823 $ 930,359
Investment in PVNGS Lessors' Notes........... $ 387,347 $ 453,028 $ 405,960 $ 440,079
Decommissioning Trust........................ $ 57,284 $ 57,284 $ 54,977 $ 54,977
Fossil-Fueled Plant Decommissioning Trust.... $ - $ - $ 4,760 $ 4,760
Rabbi Trust.................................. $ 10,848 $ 10,848 $ 14,281 $ 14,281
(1) $116 million of investments are held by the Holding Company.
Fair value is based on market quotes provided by the Company's investment
bankers and trust advisors.
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 uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices, interest rates of future
debt issuances 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 Company is exposed to credit risk in the event of non-performance or
non-payment by counterparties of its financial derivative instruments. 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, 2001 and 2000 was $7.5 million and $16.7
million, respectively.
F-32
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Natural Gas Contracts
Utility Operations
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, earnings are not affected by gains or losses generated by
these instruments.
The Company purchased gas options, a type of hedge, to protect its
natural gas customers from price risk during the 2001-2002 heating season. The
Company expended $9.4 million to purchase options that limit the maximum amount
the Company would pay for gas during the winter heating season. The Company
recovered its actual hedging expenditures as a component of the PGAC during the
months of October 2001 through February 2002 in equal allotments of $1.88
million. As winter 2001-2002 gas prices were substantially lower than the
previous year, the hedges placed for this winter expired unexercised.
Generation and Trading
Commencing in 2000, the Company's Generation and Trading Operations
conducted a hedging program to reduce its exposure to fluctuations in prices for
natural gas 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 second, third and fourth quarters of 2001. The futures
contracts capped the Company's natural gas purchase prices at $5.08 to $6.40 per
MMBTU and had a notional amount of $33.6 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. The Company accounted for these transactions as cash flow
hedges; accordingly, gains and losses related to these transactions are deferred
and recorded as a component of Other Comprehensive Income. These gains and
losses were reclassified and recognized in earnings as an adjustment to the
Company's cost of fuel when the hedged transaction affected earnings. The fuel
hedge program ended in December 2001.
Electricity Trading Contracts
For the year ended December 31, 2001, the Company's wholesale electric
trading operations settled trading contracts for the sale of electricity that
generated $77.9 million of electric revenues by delivering 448,000 MWh. The
Company purchased $76.7 million or 428,000 MWh of electricity to support these
contractual sales and other open market sales opportunities. For the year ended
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 sales and
other open market sales opportunities.
F-33
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
As of December 31, 2001, the Company had open trading contract positions
to buy $66.9 million and to sell $25.7 million of electricity. At December 31,
2001, the Company had a gross mark-to-market gain (asset position) on these
trading contracts of $10.9 million and gross mark-to-market loss (liability
position) of $41.4 million, with net mark-to-market loss (liability position) of
$30.5 million. The change in mark-to-market valuation is recognized in earnings
each period.
In addition, the Company's Generation and Trading Operations enter into
forward physical contracts for the sale of the Company's electric capacity in
excess of its jurisdictional needs, including reserves, or the purchase of
jurisdictional needs, including reserves, when resource shortfalls exist. The
Company generally accounts for these derivative financial instruments as normal
sales and purchases as defined by SFAS 133, as amended. The Company from time to
time makes forward purchases to serve its jurisdictional needs when the cost of
purchased power is less than the incremental cost of its generation. At December
31, 2001, the Company had open forward positions classified as normal sales of
electricity of $48.9 million and normal purchases of electricity of $8.1
million.
The Company's Generation and Trading 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.
Forward Starting Interest Rate Swaps
PNM currently has $182.0 million of tax-exempt bonds outstanding that
are callable at a premium in December 2002 and August 2003. PNM intends to
refinance these bonds assuming the interest rate of the refinancing does not
exceed the current interest rate and has hedged the entire planned refinancing.
In order to take advantage of current low interest rates, PNM entered into two
forward starting interest rate swaps in November and December 2001 and three
additional contracts subsequent to December 31, 2001. PNM designated these swaps
as cash flow hedges. The hedged risks associated with these instruments are the
changes in cash flows related to general moves in interest rates expected for
the refinancing. The swaps effectively cap the interest on the refinancing to
4.9% plus an adjustment for PNM's and the industry's credit rating. PNM's
assessment of hedge effectiveness is based on changes in the interest rates and
PNM's credit spread. 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 transactions affects earnings. Any hedge
ineffectiveness is required to be presented in current earnings. There was no
material hedge ineffectiveness in the year ended December 31, 2001.
F-34
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
A forward starting swap does not require any upfront premium and
captures changes in the corporate credit component of an investment grade
company's interest rate as well as the underlying Treasury benchmark. The five
forward interest rate starting swaps have termination dates and notional amounts
as follows: one with a termination date of September 17, 2002 for a notional
amount of $46.0 million and four with a termination date of May 15, 2003 for a
combined notional amount of $136.0 million. There were no fees on the
transaction, as they are imbedded in the rates, and the transaction is cash
settled on the mandatory unwind date (strike date), corresponding to the
refinancing date of the underlying debt. The settlement will be capitalized as a
cost of issuance and amortized over the life of the debt as a yield adjustment.
Hedge of Trust Assets
In February 2001, PNM terminated certain financial derivatives based on
the Standard & Poor's ("S&P") 500 Index. These instruments were used to limit
potential loss on investments for nuclear decommissioning, executive retirement
and retiree medical benefits due to adverse market fluctuations. PNM recognized
a realized gain of $0.5 million (pretax) as a result. Previously, changes in
fair market value were recorded in PNM's results of operations.
(Intentionally left blank)
F-35
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
(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:
2001 2000 1999
------------- ------------- -------------
(In thousands, except per share amounts)
Basic:
Net Earnings from Continuing Operations..................... $ 150,433 $ 100,946 $ 79,614
Cumulative Effect of a Change in Accounting
Principle, net of tax.................................... - - 3,541
------------- ------------- -------------
Net Earnings................................................ 150,433 100,946 83,155
Preferred Stock Dividend Requirements....................... 586 586 586
------------- ------------- -------------
Net Earnings Applicable to Common Stock..................... $ 149,847 $ 100,360 $ 82,569
============= ============= =============
Average Number of Common Shares Outstanding................. 39,118 39,487 41,038
============= ============= =============
Net Earnings per Share of Common Stock:
Earnings from continuing operations....................... $ 3.83 $ 2.54 $ 1.93
Cumulative effect of a change in accounting principle..... - - -
------------- ------------- -------------
Net Earnings per Share of Common Stock (Basic).............. $ 3.83 $ 2.54 $ 2.01
============= ============= =============
Diluted:
Net Earnings from Continuing Operations..................... $ 150,433 $ 100,946 $ 79,614
Cumulative Effect of a Change in Accounting
Principle, net of tax.................................... - - 3,541
------------- ------------- -------------
Net Earnings................................................ 150,433 100,946 83,155
Preferred Stock Dividend Requirements....................... 586 586 586
------------- ------------- -------------
Net Earnings Applicable to Common Stock..................... $ 149,847 $ 100,360 $ 82,569
============= ============= =============
Average Number of Common Shares Outstanding................. 39,118 39,487 41,038
Diluted Effect of Common Stock Equivalents (a).............. 613 223 65
------------- ------------- -------------
Average common and common equivalent shares
Outstanding............................................... 39,731 39,710 41,103
============= ============= =============
Net Earnings per Share of Common Stock:
Earnings from continuing operations....................... $ 3.77 $ 2.53 $ 1.93
Cumulative effect of a change in accounting principle..... - - -
------------- ------------- -------------
Net Earnings per Share of Common Stock (Diluted).............. $ 3.77 $ 2.53 $ 2.01
============= ============= =============
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out of-the-money options of 105,336 and 66,143 for the years
ended 2000 and 1999, respectively. There were no anti-dilutive common
stock equivalents in 2001.
F-36
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
(7) Income Taxes
Income taxes before discontinued operations and cumulative effect of a
change in accounting principle consist of the following components:
2001 2000 1999
----------- ------------ -----------
(In thousands)
Current Federal income tax .............................. $ 97,661 $ 41,666 $ 23,511
Current state income tax ................................ 21,220 13,726 8,502
Deferred Federal income tax ............................. (28,967) 19,729 13,494
Deferred state income tax ............................... (5,712) 2,368 210
Amortization of accumulated investment tax credits ...... (3,139) (3,143) (3,409)
----------- ------------ -----------
Total income taxes ................................... $ 81,063 $ 74,346 $ 42,308
Charged to operating expenses ........................... $ 88,769 $ 53,964 $ 25,010
Charged to other income and deductions .................. (7,706) 20,382 17,298
----------- ------------ -----------
Total income taxes.................................... $ 81,063 $ 74,346 $ 42,308
=========== ============ ===========
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:
2001 2000 1999
----------- ----------- -----------
(In thousands)
Federal income tax at statutory rates ................ $ 81,024 $ 61,352 $ 42,673
Investment tax credits ............................... (3,139) (3,143) (3,409)
Depreciation of flow-through items ................... 2,249 2,250 605
Gains on the sale and leaseback of PVNGS
Units 1 and 2 ..................................... (527) (527) (527)
Equity income from passive investments................ (1,180) - (1,301)
Annual reversal of deferred income taxes accrued
at prior tax rates................................. (1,963) (2,477) (2,320)
Valuation reserve for regulatory recoverability....... (6,552) 6,552 -
State income tax ..................................... 10,706 8,343 5,541
Other ................................................ 445 1,996 1,046
----------- ----------- -----------
Total income taxes ................................ $ 81,063 $ 74,346 $ 42,308
=========== =========== ===========
Effective tax rate 35.02% 42.41% 34.70%
=========== =========== ===========
F-37
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
The components of the net accumulated deferred income tax liability were:
2001 2000
---------- ----------
(In thousands)
Deferred Tax Assets:
Nuclear decommissioning costs...................... $28,138 $23,892
Regulatory liabilities related to income taxes .... 40,594 41,695
Other ............................................. 78,973 69,469
---------- ----------
Total deferred tax assets ...................... 147,705 135,056
---------- ----------
Deferred Tax Liabilities:
Depreciation ...................................... 189,157 184,127
Investment tax credit ............................. 44,714 47,853
Fuel costs ........................................ 5,515 24,808
Regulatory assets related to income taxes.......... 68,086 67,435
Other ............................................. 19,263 45,631
---------- ----------
Total deferred tax liabilities ................. 326,735 369,854
---------- ----------
Accumulated deferred income taxes, net ............... $179,030 $234,798
========== ==========
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..................... $(55,768)
Change in tax effects of income tax related regulatory assets and liabilities... (1,752)
Tax effect of mark-to-market on investments available for sale.................. 790
Tax effect of excess pension liability.......................................... 18,912
-----------
Deferred income tax expense from continuing operations for the period........ $(37,818)
===========
The Company has no net operating loss carryforwards as of December 31,
2001.
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-38
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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 $9.0, $8.9 and $8.4 million in the years ended
December 31, 2001, 2000 and 1999, respectively.
The following sets forth the pension plan's funded status, components of
pension costs and amounts (in thousands) at the plan valuation date of September
30:
Pension Benefits
--------------------------
2001 2000
------------ ------------
Change in Benefit Obligation:
Benefit obligation at beginning of year............... $313,152 $331,061
Service cost.......................................... 5,544 6,491
Interest cost......................................... 25,758 23,572
Amendments............................................ 3,560 -
Actuarial gain (loss)................................. 44,420 (30,934)
Benefits paid......................................... (19,000) (17,038)
------------ ------------
Benefit obligation at end of period............... 373,434 313,152
------------ ------------
Change in Plan Assets:
Fair value of plan assets at beginning of year........ 389,827 361,640
Actual return on plan assets.......................... (30,989) 45,225
Benefits paid......................................... (19,000) (17,038)
------------ ------------
Fair value of plan assets at end of year.......... 339,838 389,827
------------ ------------
Funded Status......................................... (33,596) 76,675
Unamortized transition assets......................... - (1,158)
Unrecognized net actuarial gain (loss)................ 48,432 (57,445)
Unrecognized prior service cost....................... 3,571 44
------------ ------------
Prepaid pension cost.............................. $18,407 $18,116
============ ============
Weighted - Average Assumptions as of September 30,
Discount rate......................................... 7.50% 8.25%
Expected return on plan assets........................ 7.75% 9.00%
F-39
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Pension Benefits
-----------------------------------
2001 2000 1999
---------- ----------- ----------
Components of Net Periodic Benefit Cost:
Service cost.................................. $ 5,544 $ 6,491 $ 7,407
Interest cost................................. 25,758 23,572 21,777
Expected return on plan assets................ (29,488) (30,923) (27,466)
Amortization of prior service cost............ (1,971) (1,130) (1,130)
---------- ----------- ----------
Net periodic pension costs (benefit)...... $ (157) $ (1,990) $ 588
========== =========== ==========
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 the plan
valuation date of September 30:
Other Benefits
------------------------------
2001 2000
------------- ---------------
Change in Benefit Obligation:
Benefit obligation at beginning of year.............. $ 81,711 $ 73,765
Service cost......................................... 2,644 1,053
Interest cost........................................ 7,906 5,428
Actuarial loss....................................... 17,147 1,465
------------- ---------------
Benefit obligation at end of period.............. 109,408 81,711
------------- ---------------
Change in Plan Assets:
Fair value of plan assets at beginning of year....... 44,693 41,825
Actual return on plan assets.......................... (5,161) 3,661
Employer contribution................................ 6,153 1,431
Benefits paid........................................ (3,553) (2,224)
------------- ---------------
Fair value of plan assets at end of year......... 42,132 44,693
------------- ---------------
Funded Status........................................ (67,276) (37,018)
Unamortized transition assets........................ 19,988 3,181
Unrecognized prior service cost...................... 31,763 21,805
------------- ---------------
Accrued postretirement costs.................... $ (15,525) $ (12,032)
============= ===============
Weighted - Average Assumptions as of September 30,
Discount rate........................................ 7.50% 8.25%
Expected return on plan assets....................... 8.25% 9.00%
F-40
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Other Benefits
---------------------------------------
2001 2000 1999
----------- ------------ ------------
Components of Net Periodic Benefit Cost:
Service cost........................................ $ 2,644 $ 1,053 $ 1,402
Interest cost....................................... 7,906 5,428 4,782
Expected return on plan assets...................... (3,412) (3,572) (3,135)
Amortization of prior service cost.................. 2,616 1,817 1,817
----------- ------------ ------------
Net periodic post retirement benefit cost....... $ 9,754 $ 4,726 $ 4,866
=========== ============ ============
The effect of a 1% increase in the health care trend rate assumption
would increase the accumulated postretirement benefit obligation as of September
30, 2001, by approximately $18.5 million and the aggregate service and interest
cost components of net periodic postretirement benefit cost for 2001 by
approximately $2.0 million. The health care cost trend rate is expected to
decrease to 6.0% by 2010 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 and
accumulated benefit obligation for this program, as of the plan valuation date
of September 30, 2001 and 2000, was $17.7 million and $16.9 million,
respectively. As of December 31, 2001 and 2000, the Company has recognized an
additional liability of $2.8 million and $2.0 million respectively, for the
amount of unfunded accumulated benefits in excess of accrued pension costs. The
net periodic cost for 2001, 2000 and 1999 was $1.7 million, $1.9 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 the program. Marketable securities in the amount
of approximately $10.2 million (fair market value of $10.9 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") expired on December 31,
2000. The PSP was a non-qualified stock option plan, covering a group of
management employees. Options to purchase shares of the Company's common stock
were 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 between December
31, 1995 and February 2000, 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. Awards granted in December 2000 vest ratably over three years on the
anniversary of the grant date. The maximum number of options authorized was 5.0
million shares that could be granted through December 31, 2000. Although the
authority to grant options under the PSP expired on December 31, 2000, the
options that were granted continue to be effective according to their terms.
F-41
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
A new employee stock incentive plan, the Omnibus Performance Equity Plan
(the "Omnibus Plan"), became effective on the formation of the holding company
on December 31, 2001. 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 2.5 million, subject to adjustment under
certain circumstances defined in the Omnibus Plan. In addition, the grant of
restricted stock rights, performance shares and units and stock appreciation
rights is limited to 500,000 shares. Re-pricing of stock options is prohibited
unless specific shareholder approval is obtained. No grants were made in 2001.
Stock options may also be provided to non-employee directors of the
Company under the Company's Director Retainer Plan ("DRP"). Prior to December
31, 2001, non-employee directors could elect to receive payment of the 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 2001 and 2000 under
this DRP was 6,000 shares with an exercise price of $22.61 and 6,000 shares with
an exercise price of $6.19, respectively. 4,000 options were exercised under
this DRP during both 2001 and 2000. The number of options outstanding as of
December 31, 2001, was 33,000. Restricted Stock issuances were based on the fair
market value of the Company's common stock on the date of grant and vest ratably
three years on the anniversary of the grant date. As of December 31, 2001, there
were no restricted stock outstanding under the DRP plan. Amendments to the DRP
were approved by the shareholders on July 3, 2001 and the amended plan became
the DRP for the new holding company on December 31, 2001. Under the new DRP, the
maximum number of authorized shares was increased from 100,000 to 200,000
(including shares previously granted) through July 1, 2005. The annual retainer
is payable in cash and stock options. Restricted stock is no longer available
under the plan. The exercise price of stock options granted under the DRP is
determined by the fair market value of the stock on the grant date.
(Intentionally left blank)
F-42
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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.
2001 2000 1999
---------------------- ---------------------- ----------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
- ------------------------------------ ----------- --------- ----------- ---------- ----------- ----------
Outstanding at beginning of year.... 3,336,221 $19.120 1,574,418 $18.187 1,014,242 $18.819
Granted............................. 6,000 $22.610 2,078,500 $19.403 608,708 $17.397
Exercised........................... 299,951 $19.610 296,027 $16.290 - N/A
Forfeited........................... 60,969 $17.961 20,670 $17.320 48,532 $18.649
------------ ----------- ------------
Outstanding at end of year.......... 2,981,301 3,336,221 1,574,418
============ =========== ============
Options exercisable at year-end .... 981,197 916,263 766,454
============ =========== ============
ptions available for future grant .. 2,500,000 - 2,183,624
============ =========== ============
The following table summarizes information about stock options outstanding at
December 31, 2001:
Options Outstanding Options Exercisable
----------------------------------------------- ---------------------------
Weighted-
Average Weighted Weighted
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 12/31/01 Life Prices At 12/31/01 Prices
- ----------------- ---------------- -------------- ------------ ------------- -------------
$5.50 - $22.61 33,000 7.136 years $ 11.020 27,000 $ 8.444
$11.50 - $24.313 2,948,301 7.783 years $ 19.194 954,197 $ 20.435
------------ -----------
2,981,301 7.776 years $ 19.103 981,197 $ 20.105
============ ===========
F-43
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Had compensation expense for the Company's stock options been recognized
based on the fair value on the grant date under the methodology prescribed by
SFAS No. 123, 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):
2001 2000 1999
----------------------- ---------------------- -----------------------
As Reported Pro forma As Reported Pro forma As Reported Pro forma
----------- ---------- ----------- --------- ------------ ----------
Net earnings: (available for
common)....................... $149,847 $146,417 $100,360 $96,735 $82,569 $81,573
Net earnings per share
Basic....................... $3.83 $3.74 $2.54 $2.45 $2.01 $1.99
Diluted..................... $3.77 $3.69 $2.53 $2.44 $2.01 $1.98
The following table summarizes weighted-average fair value of options granted
during the year:
2001 2000 1999
---------- --------- ---------
PSP....................................... - $ 7.24 $3.89
========== ========= =========
DRP....................................... $13.94 $ 6.98 $5.85
========== ========= =========
Total fair market value of all options
granted (in thousands)................... $ 83 $15,054 $2,384
========== ========= =========
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:
2001 2000 1999
---------- ---------- ----------
Dividend yield..................... 3.10% 2.98% 4.90%
Expected volatility................ 33.99% 26.43% 30.29%
Risk-free interest rates........... 5.38% 5.11% 6.43%
Expected life...................... 10.0 10.0 10.0
(10) Construction Program and Jointly-Owned Plants
The Company's construction expenditures for 2001 were approximately
$264.9 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.
F-44
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
At December 31, 2001, 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)..... $709,699 $371,122 $ 2,180 46.3%
Palo Verde Nuclear Generating
Station (Nuclear)*................... $210,718 $ 59,932 $21,163 10.2%
Four Corners Power Plant Units 4
and 5 (Coal) ....................... $118,497 $ 81,237 $ 3,187 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, 2001, 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.
Palo Verde Nuclear Generating Station ("PVNGS")
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
PNM 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. PNM may reduce its purchases from SPS by 25 MW annually
upon three years' notice. PNM provided such notice to reduce the purchase by 25
MW in 1999 and by an additional 25 MW in 2000. PNM also is party to a master
power purchase and sale agreement with SPS, dated August 2, 1999 pursuant to
which PNM has agreed to purchase 72 MW of firm power from SPS from 2002 through
F-45
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
2005. PNM has 70 MW of contingent capacity obtained from El Paso under a
transmission capacity for generation capacity trade arrangement through
September 2004. Beginning October 2004 and continuing through June 2005, the
capacity amount is 39 MW. PNM holds a PPA with Tri-State for 50 MW through June
30, 2010. In addition, PNM is interconnected with various utilities for economy
interchanges and mutual assistance in emergencies.
In 1996, PNM entered into a long-term Power Purchase Agreement ("PPA")
for the rights to all the output of a new gas-fired generating plant for 20
years. 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-Person
Limited Partnership ("Delta") and is located on PNM '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 PNM. 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.
In July 2001, PNM entered into a long-term wholesale power contract with
Texas-New Mexico Power ("TNMP") to provide power to serve TNMP's firm retail
customers. The contract has a term of 5 1/2 years commencing July 1, 2001. PNM
will provide varying amounts of firm power on demand to complement existing TNMP
contracts. As those contracts expire, PNM will replace them and become TNMP's
sole supplier beginning January 1, 2003. In the last year of the contract, it is
estimated that TNMP will need 114 megawatts of firm power.
Coal Supply
The coal requirements for the SJGS are being supplied by San Juan Coal
Company ("SJCC"), a wholly-owned subsidiary of BHP Holdings, 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
Minerals International, Inc. has guaranteed the obligations of SJCC under the
agreement, which contemplates the delivery of approximately 103 million tons of
coal during its remaining term. That amount would supply substantially all the
requirements of the SJGS through approximately 2017.
Four Corners Power Plant ("Four Corners") is supplied with coal under a
fuel agreement between the owners and BHP Navajo Coal Company ("BNCC"), under
which BNCC agreed to supply all the coal requirements for the life of the plant.
The current fuel agreement expires December 31, 2004. Negotiations for an
extension have been initiated. BNCC 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.
F-46
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
Natural Gas Supply
The Company contracts for the purchase of gas to serve its jurisdictional
customers. These contracts are short-term in nature supplying the gas needs for
the current heating season and the following off-season months. The price of gas
is a pass-through, whereby the Company recovers 100% of its cost of gas.
The natural gas used as fuel by Generation and Trading was delivered by
Gas. In the second quarter of 2001, the Company's Generation and Trading
Operations began procuring its gas supply independent of the Company and
contracting with the Utility Operations for transportation services only.
Construction Commitment
PNM has committed to purchase five combustion turbines at a total cost of
$151.3 million. The turbines are for three planned power generation plants with
a combined capacity of 657 MWs. The plants' estimated cost of construction is
approximately $400.3 million. PNM has expended $103.4 million as of December 31,
2001. In November 2001, PNM broke ground for a new 135 MW single cycle gas
turbine plant on a site in Southern New Mexico. This facility is expected to be
operational by October 2002. Currently PNM plans to expand the facility to 225
MW by the end of 2003. In February 2002, PNM also broke ground for an 80 MW,
natural gas fired generating plant in southwestern New Mexico. This facility is
expected to be operational by July 2002. The planned plants are part of PNM's
ongoing competitive strategy of increasing generation capacity over time. The
costs of the plants are not anticipated to be added to the rate base.
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 $88.1 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.
Aspects of the Federal law referred to above (the "Price-Anderson Act"),
which provides for payment of public liability claims in case of a catastrophic
accident involving a nuclear power plant are up for renewal in August 2002.
While existing nuclear power plant would continue to be covered in any event,
the renewal would extend coverage to future nuclear power plants and could
contain amendments that would affect existing plants. A renewal bill was passed
F-47
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
by the House with unanimous consent on November 27, 2001. The House proposed a
change in the annual retrospective premium limit from $10 million to $15 million
per reactor per incident. Additionally, the House proposed to amend the maximum
potential assessment from $88.1 million to $98.7 million per reactor per
incident, taking into account effects of inflation. On March 7, 2002 the Senate
approved a Price-Anderson Act amendment as a part of the overall energy bill.
The Senate version is substantially the same as the Price-Anderson Act in its
current form. In the event the energy bill does not pass, it is possible that
the Price-Anderson amendment would be passed as a stand-alone bill. In a report
issued in 1998, the NRC had made a number of recommendations regarding the
Price-Anderson Act, including a recommendation that Congress investigate whether
the $200 million now available from the private insurance market for liability
claims per reactor could be increased to keep pace with inflation. The Company
cannot predict whether or not Congress will renew the Price-Anderson Act or act
on the NRC's recommendation. However, if adopted, certain changes in the law
could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases,
absent waiver by the lessors. Such an occurrence could require the Company to,
among other things, (i) pay the lessor and the equity investor, in return for
the investor's interest in PVNGS, cash in the amount as provided in the lease
and (ii) assume debt obligations relating to the PVNGS lease (see Note 4).
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, 2002, 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 $4.8 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
$181 million (in 1998 dollars).
The Company funded an additional $6.1 million, $3.9 million and $3.1
million in 2001, 2000 and 1999, respectively, into the qualified and
non-qualified trust funds. The estimated market value of the trusts at the end
of 2001 was approximately $57.3 million.
F-48
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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 2001 and 2000, the Company expensed approximately $1.0
million for on-site interim nuclear fuel storage costs related to nuclear fuel
burned during 2001 and 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.
Natural Gas Explosion
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New
Mexico. The apparent cause of the explosion was a leak from a Company line near
the location. The explosion destroyed a small building and injured two persons
who were working in the building. The Company's investigation indicates that the
leak was an isolated incident likely caused by a combination of corrosion and
increased pressure. The Company also is cooperating with an investigation of the
incident by the PRC's Pipeline Safety Bureau which issued its report on March
18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the
New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the
Company by the injured persons along with several claims for property and
business interruption damages have been resolved by the Company. At this time,
the Company is unable to estimate the potential liability, if any, that the
Company may incur as a result of the Pipeline Safety Bureau's investigation.
There can be no assurance that the outcome of this matter will not have a
material adverse impact on the results of operations and financial position of
the Company.
Western Resources Transaction
On November 9, 2000, the Company and 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 agreement required that Western
Resources split-off its non-utility businesses to its shareholders prior to
closing.
F-49
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
In July, 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for $151 million increase. After rehearing the KCC established the rate
decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001, in New York state court
seeking declarations that the transaction could not be accomplished as designed
due to the KCC's determination that the split-off condition of the transaction
is unlawful; that the Company is not obligated to pursue approvals of the
transaction as designed; that the transaction is terminated effective December
31, 2001, without an automatic extension; and that the KCC rate case order
constitutes a material adverse effect under the agreement. The Company also
seeks monetary damages for breach of contract because Western Resources
represented and warranted that the split-off did not require approval of the
KCC.
On November 19, 2001, Western Resources filed a complaint against the
Company in New York state court alleging breach of contract and breach of
implied covenant of good faith and fair dealing. Western Resources alleged that
the Company brought about the KCC orders, failed to assist in efforts to reverse
the KCC orders, refused to renegotiate within the terms of the agreement,
interfered with Western Resources' efforts to satisfy the terms of the
agreement, and effected an unauthorized de facto termination of the agreement by
filing its complaint. Western Resources alleges damages in excess of $650
million. The Company believes that the complaint filed by Western Resources is
without merit and intends to vigorously defend itself against the complaint. The
Company also intends to vigorously pursue its own complaint.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect.
On February 5, 2002, the District Court for Shawnee County, Kansas,
dismissed without prejudice Western Resources' petition for judicial review of
the KCC's split-off orders. The Court ruled that, by filing a new financial plan
in compliance with the orders, Western Resources had acquiesced in certain
portions of the orders thereby creating a situation where further administrative
action became necessary. As a result, the Court concluded that the matter was
not ripe for judicial review and remanded the case to the KCC.
F-50
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate
order.
The Company is currently unable to predict the outcome of its litigation
with Western Resources.
Other
There are various claims and lawsuits pending against the Company and
certain of its subsidiaries, in addition to the matters discussed above. 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
F-51
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2001, 2000 and 1999
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.
For the year ended December 31, 2001, 2000 and 1999, the Company spent
$1.7 million, $1.6 million and $4.4 million, respectively, for remediation. The
majority of the December 31, 2001, 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) New and Proposed Accounting Standards
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" ("SFAS 143"). In June 2001, the FASB issued SFAS
143. The statement requires the recognition of a liability for legal obligations
associated with the retirement of a tangible long-lived asset that result from
the acquisition, construction or development and/or the normal operation of a
long-lived asset. The asset retirement obligation is required to be recognized
at its fair value when incurred. The cost of the asset retirement obligation is
required to be capitalized by increasing the carrying amount of the related
long-lived asset by the same amount as the liability. This cost must be expensed
using a systematic and rational method over the related asset's useful life.
SFAS 143 is effective for the Company beginning January 1, 2003. The Company is
currently assessing the impact of SFAS 143 and is unable to predict its impact
on the Company's operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the
FASB issued SFAS 144. The statement amends certain requirements of the
previously issued pronouncement on asset impairment, SFAS 121. SFAS 144 removes
goodwill from the scope of SFAS 121, provides for a probability-weighted cash
flow estimation approach for estimating possible future cash flows, and
establishes a "primary asset" approach for a group of assets and liabilities
that represents the unit of accounting to be evaluated for impairment. In
addition, SFAS 144 changes the measurement of long-lived assets to be disposed
of by sale, as accounted for by Accounting Principles Board Opinion No. 30.
Under SFAS 144, discontinued operations are no longer measured on a net
realizable value basis, and their future operating losses are no longer
recognized before they occur. The Company does not believe SFAS 144 will have a
material effect on its future operating results or financial position.
F-52
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
QUARTERLY OPERATING RESULTS
The unaudited operating results by quarters for 2001 and 2000 are as
follows:
Quarter Ended
----------------------------------------------------
March 31 June 30 September 30 December 31
----------- ----------- -------------- ------------
(In thousands, except per share amounts)
2001:
Operating Revenues......................... $ 736,530 $ 666,091 $ 621,895 $ 327,581
Operating Income........................... 77,300 80,547 47,422 17,407
Earnings from Continuing Operations........ 63,552 49,597 32,775 4,509
Net Earnings............................... 63,552 49,597 32,775 4,509
Net Earnings per share from Continuing
Operations.............................. 1.62 1.26 0.83 0.11
Net Earnings per Share (Basic)............. 1.62 1.26 0.83 0.11
Net Earnings per Share (Diluted)........... 1.60 1.24 0.82 0.11
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 .............................. 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
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.
- -------------------
F-53
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
COMPARATIVE OPERATING STATISTICS
(Unaudited)
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Utility Operations Sales:
Energy Sales--KWh (in thousands):
Residential.............................. 2,197,889 2,171,945 2,027,589 2,022,598 1,951,219
Commercial............................... 3,213,208 3,133,996 2,981,656 2,909,752 2,805,576
Industrial............................... 1,603,266 1,544,367 1,559,155 1,571,824 1,556,264
Other ultimate customers................. 240,934 238,635 235,183 235,700 221,840
----------- ----------- ----------- ----------- -----------
Total KWh sales........................ 7,255,297 7,088,943 6,803,583 6,739,874 6,534,899
=========== =========== =========== =========== ===========
Gas Throughput--Decatherms (in thousands):
Residential.............................. 27,848 28,810 32,121 29,258 30,605
Commercial............................... 10,421 9,859 11,106 10,044 10,592
Industrial............................... 3,920 5,038 2,338 1,553 1,280
Other.................................... 4,355 6,426 6,538 8,390 8,158
----------- ----------- ----------- ----------- -----------
Total gas sales........................ 46,544 50,133 52,103 49,245 50,635
Transportation throughput................ 51,395 44,871 40,161 36,413 33,975
----------- ----------- ----------- ----------- -----------
Total gas throughput................... 97,939 95,004 92,264 85,658 84,610
=========== =========== =========== =========== ===========
Revenues (in thousands):
Electric Revenues:
Residential.............................. $ 187,600 $ 186,133 $ 184,088 $ 187,681 $ 184,813
Commercial............................... 242,372 238,243 238,830 241,968 237,629
Industrial............................... 82,752 79,671 85,828 88,644 86,927
Other ultimate customers................. 14,795 14,618 13,777 18,124 10,135
----------- ----------- ----------- ----------- -----------
Total revenues to ultimate customers... 527,519 518,665 522,523 536,417 519,504
Intersegment revenues.................... 707 707 707 707 -
Miscellaneous electric revenues.......... 31,707 20,093 18,345 19,151 3,331
----------- ----------- ----------- ----------- -----------
Total electric revenues................ $ 559,933 $ 539,465 $ 541,575 $ 556,275 $ 522,835
----------- ----------- ----------- ----------- -----------
Gas Revenues:
Residential.............................. $ 232,321 $ 191,231 $ 152,266 $ 160,398 $ 185,851
Commercial............................... 68,895 52,964 37,337 42,480 50,042
Industrial............................... 27,519 24,206 8,550 4,887 4,533
Other.................................... 28,896 29,203 20,080 27,218 30,285
----------- ----------- ----------- ----------- -----------
Revenues from gas sales.................. 357,631 297,604 218,233 234,983 270,711
Transportation........................... 20,188 14,163 12,390 13,464 14,172
Other.................................... 7,599 8,157 6,088 7,528 9,886
----------- ----------- ----------- ----------- -----------
Total gas revenues..................... $ 385,418 $ 319,924 $ 236,711 $ 255,975 $ 294,769
----------- ----------- ----------- ----------- -----------
Total Utility Revenues............ $ 945,351 $ 859,389 $ 778,286 $ 812,250 $ 817,604
=========== =========== =========== =========== ===========
F-54
PNM RESOURCES, INC. AND SUBSIDIARIES AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
COMPARATIVE OPERATING STATISTICS
(Unaudited)
2001 2000 1999 1998 1997
------------ ------------ ------------ ----------- -----------
Utility Customers at Year End:
Electric:
Residential............................. 336,614 328,519 321,949 319,415 311,314
Commercial.............................. 39,674 38,991 38,435 37,652 36,942
Industrial.............................. 377 371 375 363 363
Other ultimate customers................ 924 625 625 665 637
------------ ------------ ------------ ----------- -----------
Total ultimate customers.............. 377,589 368,506 361,384 358,095 349,256
Sales for Resale........................ 79 81 83 83 66
------------ ------------ ------------ ----------- -----------
Total customers....................... 377,668 368,587 361,467 358,178 349,322
============ ============ ============ =========== ===========
Gas:
Residential............................. 404,753 398,623 390,428 383,292 375,032
Commercial.............................. 32,894 32,626 32,116 32,004 31,560
Industrial.............................. 50 50 51 55 50
Other................................... 3,528 3,612 3,688 3,622 3,765
Transportation.......................... 34 32 32 29 31
------------ ------------ ------------ ----------- -----------
Total customers....................... 441,259 434,943 426,315 419,002 410,438
============ ============ ============ =========== ===========
Generation and Trading Operations Sales:
Energy Sales--KWh (in thousands):
Firm-requirements wholesale............. 616,703 330,003 179,249 278,615 278,727
Other contracted off-system............. 6,900,589 7,315,679 6,196,499 4,033,931 3,790,081
Economy energy sales.................... 5,059,808 4,706,446 4,795,873 4,469,769 2,716,835
------------ ------------ ------------ ----------- -----------
Total sales to ultimate customers..... 12,577,100 12,352,128 11,171,621 8,782,315 6,785,643
Intersegment sales...................... 7,255,297 7,088,943 6,803,583 6,739,874 6,534,899
------------ ------------ ------------ ----------- -----------
Total energy sales.................... 19,832,397 19,441,071 17,975,204 15,522,189 13,320,542
============ ============ ============ =========== ===========
Revenues (in thousands):
Firm-requirements wholesale............. $ 24,754 $ 15,540 $ 7,046 $ 10,708 $ 10,690
Other contracted off-system............. 892,105 364,278 226,773 142,115 118,876
Economy energy sales.................... 512,209 368,374 131,549 122,156 55,768
------------ ------------ ------------ ----------- -----------
Total revenues to ultimate customers.. 1,429,068 748,192 365,368 274,979 185,334
Intersegment revenues................... 341,608 324,744 318,872 362,722 370,019
Miscellaneous electric revenues......... (23,152) 2,242 5,741 4,657 14,269
------------ ------------ ------------ ----------- -----------
Total generation revenues............. $1,747,524 $1,075,178 $ 689,981 $ 642,358 $ 569,622
============ ============ ============ =========== ===========
Customers at Year End:
Generation 79 81 83 83 66
============ ============ ============ =========== ===========
Reliable Net Capability--KW............... 1,521,000 1,521,000 1,521,000 1,506,000 1,506,000
Coincidental Peak Demand--KW.............. 1,397,000 1,368,000 1,291,000 1,313,000 1,209,000
Average Fuel Cost per Million BTU......... $ 1.6007 $ 1.3827 $ 1.3169 $ 1.2433 $ 1.2319
BTU per KWh of Net Generation............. 10,549 10,547 10,490 10,784 10,927
F-55
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
PNM Resources, Inc. and Public Service Company of
New Mexico:
We have audited, in accordance with auditing standards generally accepted
in the United States, the consolidated financial statements included in
this annual report on Form 10-K, and have issued our report thereon dated
February 1, 2002. Our audit was made for the purpose of forming an
opinion on those statements taken as a whole. The schedules listed in the
index are the responsibility of the Company's management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic consolidated financial
statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic consolidated financial
statements and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the basic
consolidated financial statements taken as a whole.
Albuquerque, New Mexico
February 1, 2002
F-56
SCHEDULE I
The PNM Resources, Inc. holding company structure was effected through a
one-for-one share exchange between the shareholders of Public Service Company of
New Mexico ("PNM") and PNM Resources, Inc. on December 31, 2001, whereby the
shareholders of PNM became shareholders of PNM Resources, Inc. and PNM
Resources, Inc. acquired all of PNM's common stock. There were no material
operations in 2001; therefore a statement of earnings is not presented.
PNM RESOURCES, INC.
CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
BALANCE SHEET
As of December 31,
------------------
2001
---------------
(In thousands)
Assets
Cash and cash equivalents................................ $ 11,380
Other current assets..................................... 9,951
---------------
Total current assets.................................. 21,331
---------------
Investment in subsidiaries............................... 885,328
Other investments........................................ 105,669
---------------
Total Assets........................................... $ 1,012,328
===============
Liabilities and Shareholder's Equity
Common stock, 39,118 shares, issued and authorized....... $ 195,589
Additional paid in capital............................... 816,739
Retained earnings........................................ -
---------------
Total Liabilities and Shareholder's Equity............ $ 1,012,328
===============
F-57
SCHEDULE I
PNM RESOURCES, INC.
CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
STATEMENT OF CASH FLOWS
As of December 31,
------------------
2001
---------------
(In thousands)
Net cash provided by investing activities:
Cash dividends received from subsidiaries................... $ 127,000
Short-term and long-term investments........................ (115,620)
---------------
Net increase in cash and cash equivalents..................... 11,380
Cash and cash equivalents at beginning of period.............. -
---------------
Cash and cash equivalents at end of period.................... $ 11,380
===============
F-58
SCHEDULE II
PNM RESOURCES, INC.
PUBLIC SERVICE COMPANY OF NEW MEXICO
VALUATION AND QUALIFYING ACCOUNTS
Additions Deductions
-------------------------------- -----------
Balance at Charged to Charged to
beginning of costs and other Write off Balance at
Description year expenses accounts adjustments end of year
- ----------------------------------- ------------- --------------- -------------- ----------- -----------
(In thousands)
Allowance for doubtful accounts,
year ended December 31:
1999 $ 836 $11,496 $ - $ (172) $ 12,504
2000 $12,504 $14,296 $ - $13,521 $ 13,279
2001 $13,279 $10,312 $ - $ 5,566 $ 18,025
Allowance for market and credit
volatility year ended December 31:
1999 $ - $ - $ - $ - $ -
2000 $ - $ 4,139 $ - $ - $ 4,139
2001 $ 4,139 $(1,090) (a) $ - $ - $ 3,049
(a) Represents a change in assessed market and credit volatility risk by
the Company (see Management's Discussion and Analysis of Results of
Operations and Financial Condition - Critical Accounting Policies).
F-59
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 May
14, 2002 (the "2002 Proxy Statement"), to PART I, SUPPLEMENTAL ITEM - "EXECUTIVE
OFFICERS OF THE COMPANY" and "Other Matters" - "Section 16(a) Beneficial
Ownership Reporting Compliance" in the 2002 Proxy Statement.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to "Executive Compensation" in the 2002 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 2002 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to the 2002 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 2001, 2000, and
1999 are omitted for the reason that they are not required
or the information is otherwise supplied.
(a) - 3-A. Exhibits Filed:
E-1
Exhibit Description
- ------- -----------
No.
- ---
3.1 Restated Articles of Incorporation of PNM Resources dated
February 22, 2002
10.52** PNM Resources' Executive Spending Account procedures effective
January 1, 2002
10.75** First Amended and Restated Public Service Company of New Mexico
Executive Savings Plan dated November 16, 2001
21 Certain subsidiaries of PNM Resources
23.1 Consent of Arthur Andersen LLP
99.23 Confirmation of Arthur Andersen LLP's representation of audit
quality control
(a) - 3-B. Exhibits Incorporated By Reference:
In addition to those Exhibits shown above, PNM and PNM Resources hereby
incorporate 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
3.1.1 Restated Articles of Incorporation of PNM, as 4-(b) to PNM's Registration 2-99990
amended through May 10, 1985 Statement
3.2 Bylaws of PNM Resources, Inc. with all 4.2 of Post-Effective Amendment 333-10993
Amendments to and including April 17, 2001 No. 1 to PNM Resources Form S-3
Registration Statement filed
October 4, 2001
E-2
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
Instruments Defining the Rights of Security Holders, Including Indentures
3.2.1 By-laws of PNM with All Amendments to and 3.2 to PNM's Annual Report on 1-6986
including February 8, 2000 Form 10-K for the fiscal year
ended December 31, 2000
4.1 Indenture of Mortgage and Deed of Trust dated as 4-(d) to PNM's Registration 2-99990
of June 1, 1947, between PNM and The Bank of New Statement No. 2-99990
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 PNM
4.3 Fifty-third Supplemental Indenture, dated as of 4.3 to PNM's Quarterly Report 1-6986
March 11, 1998, supplemental to Indenture of on Form 10-Q for the quarter
Mortgage and Deed of Trust, dated as of June 1, ended March 31, 1998.
1947, between PNM and The Bank of New
York(formerly Irving Trust Company), as trustee.
4.4 Indenture (for Senior Notes), dated as of March 4.4 to PNM's Quarterly Report 1-6986
11, 1998, between PNM and The Chase Manhattan on Form 10-Q for the quarter
Bank, as Trustee. ended March 31, 1998.
4.5 First Supplemental Indenture, dated as of March 4.5 to PNM's Quarterly Report 1-6986
11, 1998, supplemental to Indenture, dated as of on Form 10-Q for the quarter
March 11, 1998, Between PNM and The Chase ended March 31, 1998.
Manhattan Bank, as Trustee.
4.6 Second Supplemental Indenture, dated as of March 4.6 to PNM's Quarterly Report 1-6986
11, 1998, supplemental to Indenture, dated as of on Form 10-Q for the quarter
March 11, 1998, Between PNM and The Chase ended March 31, 1998.
Manhattan Bank, as Trustee.
E-3
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
4.6.1 Third Supplemental Indenture, dated as of 4.6.1 to PNM's Annual Report on 1-6986
October 1, 1999 to Indenture dated as of March Form 10-K for the fiscal year
11, 1998, between PNM and The Chase Manhattan ended December 31, 1999.
Bank, as Trustee
4.7 Indenture (for Senior Notes), dated as of August 4.1 to PNM's Registration 33-53367
1, 1998, between PNM and The Chase Manhattan Statement No. 33-53367
Bank, as Trustee.
4.8 First Supplemental Indenture, dated August 1, 4.3 to PNM's Current Report on 1-6986
1998, supplemental to Indenture, dated as of Form 8-K dated August 7, 1998.
August 1, 1998, between PNM and the Chase
Manhattan Bank, as Trustee.
Material Contracts
10.1 Supplemental Indenture of Lease dated as of July 4-D to PNM's Registration 2-26116
19, 1966 between PNM and other participants in Statement No. 2-26116
the Four Corners Project and the Navajo Indian
Tribal Council.
10.1.1 Amendment and Supplement No. 1 to Supplemental 10.1.1 to PNM's Annual Report 1-6986
and Additional Indenture of Lease dated April on Form 10-K for fiscal year
25, 1985 between the Navajo Tribe of Indians and ended December 31, 1995.
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 as of 4-H to PNM's Registration 2-35042
September 1, 1966 between Utah Construction & Statement No. 2-35042
Mining Co. and the participants in the Four
Corners Project including PNM.
10.3 Fourth Supplement to Four Corners Fuel Agreement 10.3 to PNM's Annual Report on 1-6986
No. 2 effective as of January 1, 1981, between Form 10-K for fiscal year ended
Utah International Inc. and the participants in December 31, 1991.
the Four Corners Project, including PNM.
10.4 Contract between the United States and PNM dated 5-L to PNM's Registration 2-41010
April 11, 1968, for furnishing water. Statement No. 2-41010
E-4
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.4.1 Amendatory Contract between the United States 5-R to PNM's Registration 2-60021
and PNM dated September 29, 1977, for furnishing Statement No. 2-60021
water.
10.5 Water Supply Agreement between the Jicarilla 10.5 to PNM's Quarterly Report 1-6986
Apache Tribe and Public Service Company of New of Form 10-Q for the quarter
Mexico, dated July 20, 2000 ended September 30, 2001
10.8 Arizona Nuclear Power Project Participation 5-T to PNM's Registration 2-50338
Agreement among PNM and Arizona Public Service Statement No. 2-50338
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 Arizona 10.8.1 to PNM's Annual Report 1-6986
Nuclear Power Project Participation Agreement. on Form 10-K for fiscal year
ended December 31, 1991.
10.8.2 Amendment No. 7 effective April 1, 1982, to the 10.8.2 to PNM's Annual Report 1-6986
Arizona Nuclear Power Project Participation on Form 10-K for fiscal year
Agreement (refiled). ended December 31, 1991.
10.8.3 Amendment No. 8 effective September 12, 1983, to 10.58 to PNM's Annual Report on 1-6986
the Arizona Nuclear Power Project Participation Form 10-K for fiscal year ended
Agreement (refiled). December 31, 1993.
10.8.4 Amendment No. 9 to Arizona Nuclear Power Project 10.8.4 to PNM's Annual Report 1-6986
Participation Agreement dated as of June 12, of the Registrant on Form 10-K
1984 (refiled). for fiscal year ended December
31, 1994.
10.8.5 Amendment No. 10 dated as of November 21, 1985 10.8.5 to PNM's Annual Report 1-6986
and Amendment No. 11 dated as of June 13, 1986 of the Registrant on Form 10-K
and effective January 10, 1987 to Arizona for fiscal year ended December
Nuclear Power Project Participation Agreement 31, 1994.
(refiled).
E-5
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.8.7 Amendment No. 12 to Arizona Nuclear Power 19.1 to PNM's Quarterly Report 1-6986
Project Participation Agreement dated June 14, on Form 10-Q for the quarter
1988, and effective August 5, 1988. ended September 30, 1990.
10.8.8 Amendment No. 13 to the Arizona Nuclear Power 10.8.10 to PNM's Annual Report 1-6986
Project Participation Agreement dated April 4, on Form 10-K for the fiscal
1990, and effective June 15, 1991. year ended December 31, 1990.
10.8.9 Amendment No. 14 to the Arizona Nuclear Power 10.8.9 to PNM's Annual Report
Project Participation Agreement effective June on Form 10-K for the fiscal
20, 2000. year ended December 31, 2000.
10.9 Coal Sales Agreement executed August 18, 1980 10.9 to PNM's Annual Report for 1-6986
among San Juan Coal Company, PNM and Tucson fiscal year ended December 31,
Electric Power Company, together with Amendments 1991.
No. One, Two, Four, and Six thereto.
10.9.1 Amendment No. Three to Coal Sales Agreement 10.9.1 to PNM's Annual Report 1-6986
dated April 30, 1984 among San Juan Coal on Form 10-K for fiscal year
Company, PNM and Tucson Electric Power Company. ended December 31, 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 Agreement dated 10.9.2 to PNM's Annual Report 1-6986
May 29, 1990 among San Juan Coal Company, PNM on Form 10-K for fiscal year
and Tucson Electric Power Company. ended December 31, 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).
E-6
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.9.3 Amendment No. Seven to Coal Sales Agreement, 19.3 to PNM's Quarterly Report 1-6986
dated as of July 27, 1992 among San Juan Coal on Form 10-Q for the quarter
Company, PNM and Tucson Electric Power Company. ended September 30, 1992
(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).
10.9.4 First Supplement to Coal Sales Agreement, dated 19.4 to PNM's Quarterly Report 1-6986
July 27, 1992 among San Juan Coal Company, PNM on Form 10-Q for the quarter
and Tucson Electric Power Company. ended September 30, 1992
(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).
10.9.5 Amendment No. Eight to Coal Sales Agreement, 10.9.5 to PNM's Annual Report 1-6986
dated as of September 1, 1995, among San Juan on Form 10-K for fiscal year
Coal Company, PNM and Tucson Electric Power ended December 31, 1995.
Company.
10.9.6 Amendment No. Nine to Coal Sales Agreement, 10.9.6 to PNM's Annual Report 1-6986
dated as of December 31, 1995, among San Juan of the Registrant on Form 10-K
Coal Company, PNM and Tucson Electric Power for fiscal year ended December
Company. 31, 1996.
E-7
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.9.8 Amendment No. 11 to Coal Sales Agreement, dated 10.9.8 to PNM's Quarterly
August 31, 2001 among San Juan Coal Company, PNM Report on Form 10-Q for the
and Tucson Electric Power Company quarter ended September 30,
2001.(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).
10.11 San Juan Unit 4 Early Purchase and Participation 10.11 to PNM's Quarterly Report 1-6986
Agreement dated as of September 26, 1983 between on Form 10-Q for the quarter
PNM and M-S-R Public Power Agency, and ended March 31, 1994.
Modification No. 2 to the San Juan Project
Agreements dated December 31, 1983 (refiled).
10.11.1 Amendment No. 1 to the Early Purchase and 10.11.1 to PNM's Annual Report 1-6986
Participation Agreement between Public Service on Form 10-K for fiscal year
Company of New Mexico and M-S-R Public Power ended December 31, 1997.
Agency, executed as of December 16, 1987, for
San Juan Unit 4 (refiled).
10.11.3 Amendment No. 3 to the San Juan Unit 4 Early 10.11.3 to PNM's Annual Report 1-6986
Purchase and Participation Agreement between on Form 10-K for fiscal year
Public Service Company of New Mexico and M-S-R ended December 31, 1999.
Public Power Agency, dated as of October 27,
1999.
10.12 Amended and Restated San Juan Unit 4 Purchase 10.12 to PNM's Annual Report on 1-6986
and Participation Agreement dated as of December Form 10-K for fiscal year ended
28, 1984 between PNM and the Incorporated December 31, 1994.
County of Los Alamos (refiled).
10.12.1 Amendment No. 1 to the Amended and Restated San 10.12.1 to PNM's Annual Report 1-6986
Juan Unit 4 Purchase and Participation Agreement Form 10-K for fiscal year ended
between Public Service Company of New Mexico and December 31, 1999.
M-S-R Public Power Agency, dated as of October
27, 1999.
E-8
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.13 Amendment No. 2 to the San Juan Unit 4 Purchase 10.13 to PNM's Annual Report on 1-6986
Agreement and Participation Agreement between Form 10-K for fiscal year ended
Public Service Company of New Mexico and The December 31, 1999.
Incorporated County of Los Alamos, New Mexico,
dated October 27, 1999.
10.14 Participation Agreement among PNM, Tucson 10.14 to PNM's Annual Report on 1-6986
Electric Power Company and certain financial Form 10-K for fiscal year ended
institutions relating to the San Juan Coal Trust December 31, 1992.
dated as of December 31, 1981 (refiled).
10.16 Interconnection Agreement dated November 23, 10.16 to PNM's Annual Report on 1-6986
1982, between PNM and Southwestern Public Form 10-K for fiscal year ended
Service Company (refiled). December 31, 1992.
10.18* Facility Lease dated as of December 16, 1985 10.18 to PNM's Annual Report on 1-6986
between The First National Bank of Boston, as Form 10-K for fiscal year ended
Owner Trustee, and Public Service Company of New December 31, 1995.
Mexico together with Amendments No. 1, 2 and 3
thereto (refiled).
10.18.4* Amendment No. 4 dated as of March 8, 1995, to 10.18.4 to the PNM's Quarter 1-6986
Facility Lease between Public Service Company of Report on Form
New Mexico and the First National Bank of 10-Q for the quarter ended
Boston, dated as of December 16, 1985. March 31, 1995.
10.19 Facility Lease dated as of July 31, 1986, 10.19 to PNM's Annual Report on 1-6986
between the First National Bank of Boston, as Form 10-K for fiscal year ended
Owner Trustee, and Public Service Company of New December 31, 1996.
Mexico together with Amendments No. 1, 2 and 3
thereto (refiled).
10.20* Facility Lease dated as of August 12, 1986, 10.20 to PNM's Annual Report on 1-6986
between The First National Bank of Boston, as Form 10-K for fiscal year ended
Owner Trustee, and Public Service Company of New December 31, 1996.
Mexico together with Amendments No. 1 and 2
thereto (refiled).
E-9
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.20.2 Amendment No. 2 dated as of April 10, 1987 to 10.20.2 to PNM's Annual 1-6986
Facility Lease dated as of August 12, 1986, as Report on Form 10-K for
amended, between The First National Bank of Boston, fiscal year ended December
not in its individual capacity, but solely as Owner 31, 1998.
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, 1995, to 10.20.3 to PNM's Quarterly 1-6986
Facility Lease between Public Service Company of New Report on Form
Mexico and the First National Bank of Boston, dated 10-Q for the quarter ended
as of August 12, 1986. March 31, 1995.
10.21 Facility Lease dated as of December 15, 1986, 10.21 to PNM's Annual Report 1-6986
between The First National Bank of Boston, as Owner on Form 10-K for fiscal year
Trustee, and Public Service Company of New Mexico ended December 31, 1996.
(Unit 1 Transaction) together with Amendment No. 1
thereto (refiled).
10.22 Facility Lease dated as of December 15, 1986, 10.22 to PNM's Annual Report 1-6986
between The First National Bank of Boston, as Owner of the Registrant on Form
Trustee, and Public Service Company of New Mexico 10-K for fiscal year ended
Unit 2 Transaction) together with Amendment No. 1 December 31, 1996.
thereto (refiled).
10.23** Restated and Amended Public Service Company of New 10.23 to PNM's Annual Report 1-6986
Mexico Accelerated Management Performance Plan on Form 10-K for fiscal year
(1988) (August 16, 1988) (refiled). ended December 31, 1998.
10.23.1** First Amendment to Restated and Amended Public 10.23.1 to PNM's Annual 1-6986
Service Company of New Mexico Accelerated Management Report on Form 10-K for
Performance Plan (1988) (August 30, 1988) (refiled). fiscal year ended December
31, 1998.
10.23.2** Second Amendment to Restated and Amended Public 10.23.2 to PNM's Annual 1-6986
Service Company of New Mexico Accelerated Management Report on Form 10-K for
Performance Plan (1988) (December 29, 1989) fiscal year ended December
(refiled). 31, 1998.
E-10
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.23.4** Fourth Amendment to the Restated and Amended Public 10.23.4 to PNM's Quarterly 1-6986
Service Company of New Mexico Accelerated on Form 10-Q for the
Management Report Performance Plan, as quarter ended March 31, 1999.
amended effective December 7, 1998.
10.24** Management Life Insurance Plan (July 1985) of the 10.24 to PNM's Annual Report 1-6986
Company (refiled). on Form 10-K for fiscal year
ended December 31, 1995.
10.25.1** Second Restated and Amended Public Service Company 10.25.1 to PNM's Annual 1-6986
of New Mexico Executive Medical Plan as amended on Report on Form 10-K for
December 28, 1995. fiscal year ended December
31, 1997.
10.27 Amendment No. 2 dated as of April 10, 1987, to the 10.53 to PNM's Annual Report 1-6986
Facility Lease dated as of August 12, 1986, between on Form 10-K for fiscal year
The First National Bank of Boston, as Owner Trustee, ended December 31, 1987.
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 Agreements dated 10.32 to PNM's Annual Report 1-6986
August 4, 1989, Between Public Service Company of on Form 10-K for fiscal year
New Mexico and John R. Ackerman and Max Maerki ended December 31, 1999.
(refilled).
10.32.1** First Amendment to the Supplemental Employee 10.32.1 to PNM's Quarterly 1-6986
Retirement Agreement for Max H. Maerki, as amended Report on Form 10-Q for the
effective August 10, 1998. quarter ended September 30,
1998.
10.32.2** Second Amendment to the Supplemental Employee 10.32.2 to PNM's Quarterly 1-6986
Retirement Agreement for Max H. Maerki, as Report on Form 10-Q for the
amended effective December 7, 1998 quarter ended March 31, 1999.
E-11
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.32.3** First Amendment to the Supplemental Employee 10.32.3 to PNM's Quarterly 1-6986
Retirement Agreement for John T. Ackerman, as Report on Form 10-Q for the
amended effective December 7, 1998 quarter ended March 31, 1999.
10.34 Settlement Agreement between Public Service Company 10.34 to PNM's Quarterly 1-6986
of New Mexico and Creditors of Meadows Resources, Report on Form 10-Q for
Inc. dated November 2, 1989 (refiled). quarter ended June 30, 2000.
10.34.1 First amendment dated April 24, 1992 to the 10.34.1 to PNM's Quarterly 1-6986
Settlement Agreement dated November 2, 1989 Report on Form 10-Q
among Public Service Company of New quarter ended June 30, 2000.
Mexico, the lender parties thereto
and collateral agent (refiled).
10.35 Amendment dated April 11, 1991 among Public Service 19.1 to PNM's Quarterly 1-6986
Company of New Mexico, certain banks and Chemical Report on Form 10-Q for the
Bank and Citibank, N.A., as agents for the banks. quarter ended September 30,
1991.
10.36 San Juan Unit 4 Purchase and Participation Agreement 19.2 to PNM's Quarterly 1-6986
Public Service Company of New Mexico and the City of Report on Form 10-Q for the
Anaheim, California dated April 26, 1991. quarter ended March 31, 1991.
10.36.1 Amendment No. 1 to the San Juan Unit 4 Purchase and 10.36.1 to Annual Report 1-6986
Participation Agreement between Public Service PNM's on Form 10-K for fiscal
Company of New Mexico and The City of Anaheim, year ended
California, dated October 27, 1999 December 31, 1999.
10.38 Restated and Amended San Juan Unit 4 Purchase and 10.2.1 to PNM's Quarterly 1-6986
Participation Agreement between Public Service Report on Form 10-Q for the
Company of New Mexico and Utah Associated Municipal quarter ended September 30,
Power Systems. 1993.
10.38.1 Amendment No. 1 to the Restated and Amended San Juan 10.38.1 to PNM's Annual 1-6986
Unit 4 Purchase And Participation Agreement between Report on Form 10-K for
Public Service Company of New Mexico And Utah fiscal year ended December
Associated Municipal Power Systems, dated October 31, 1999.
27, 1999.
E-12
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.40** PNM Resources, Inc. Director Retainer Plan, dated 4.3 to PNM Resources, Inc. 333-03289
December 31, 2001 Post-Effective Amendment No.
1 to Form 8 Registration
Statement filed December 31,
2001
10.41 Waste Disposal Agreement, dated as of July 27, 1992 19.5 to PNM's Quarterly 1-6986
among San Juan Coal Company, PNM and Tucson Electric Report on Form 10-Q for the
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 filed and were filed
separately with the Securities
and Exchange Commission).
10.42 Stipulation in the matter of the application of Gas 10.42 to PNM's Annual Report 1-6986
Company of New Mexico for an order authorizing on Form 10-K for fiscal year
recovery of MDL costs through Rate Rider Number 8. ended December 31, 1992.
10.43 2001 Officer Incentive Plan effective January 1, 2001 10.43 to PNM's Annual Report
on Form 10-K for the fiscal
year ended December 31, 2000
10.44.2** Second Restated and Amended Non-Union Severance 10.44.2 to PNM's Quarterly 1-6986
Pay Plan of Public Service Company of New Report on Form 10-Q for
Mexico dated the August 1, 1999 quarter ended September 30,
1999.
10.45** Second Amendment to the Public Service Company 10.45 to PNM's Quarterly 1-6986
of New Mexico Service Bonus Plan, as amended Report on Form 10-Q
effective December 7, 1998. for the quarter
ended March 31, 1999.
10.47** Compensation Arrangement with Chief Executive 10.3 to PNM's Quarterly 1-6986
Officer, Benjamin F. Montoya effective June 23, 1993. Report on Form 10-Q for the
quarter ended June 30, 1993.
E-13
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.47.1** Pension Service Adjustment Agreement for Benjamin F. 10.3.1 to PNM's Quarterly 1-6986
Montoya. Report on Form 10-Q for the
quarter ended September 30,
1993.
10.47.2** Severance Agreement for Benjamin F. Montoya. 10.3.2 to PNM's Quarterly 1-6986
Report on Form 10-Q
for the quarter ended
September 30, 1993.
10.47.4** First Amendment to the Pension Service Adjustment 10.47.4 to PNM's Quarterly 1-6986
Agreement for Benjamin F. Montoya. Report on Form 10-Q for the
quarter ended June 30, 1998.
10.47.6** Second Amendment to the Pension Service Adjustment 10.47.6 to PNM's Quarterly 1-6986
Agreement for Benjamin F. Montoya, as amended Report on Form 10-Q for the
effective December 7, 1998 quarter ended March 31, 1999.
10.48** Public Service Company of New Mexico OBRA `93 10.4 to PNM's Quarterly 1-6986
Retirement Plan. Report on Form 10-Q for the
quarter ended September 30,
1993.
10.48.1** First Amendment to the Public Service Company 10.48.1 to PNM's Quarterly 1-6986
of New Mexico OBRA '93 Retirement Plan, as Report on Form 10-Q for the
amended effective December 7, 1998 quarter ended March 31, 1999.
10.49** Employment Contract By and Between Public Service 10.49 to PNM's Annual Report 1-6986
Company of New Mexico and Roger J. Flynn. on Form 10-K for fiscal year
ended December 31, 1994.
10.50** Public Service Company of New Mexico Section 415 Plan 10.50 to PNM's Annual Report 1-6986
dated January 1, 1994. on Form 10-K for fiscal year
ended December 31, 1993.
E-14
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.51.2** First Restated and Amended Executive Retention Plan, 10.51.2 to PNM's Quarterly 1-6986
as amended effective December 7, 1998 Report on Form 10-Q for the
quarter ended March 31, 1999.
10.53 January 12, 1994 Stipulation. 10.53 to PNM's Annual Report 1-6986
on Form 10-K for fiscal year
ended December 31, 1993.
10.54.1** Health Care and Retirement Benefit Agreement By and 10.54.1 to PNM's Quarterly 1-6986
Between the Public Service Company of New Mexico and Report on Form 10-Q for the
John T. Ackerman dated February 1, 1994. quarter ended March 31, 1994.
10.56.1 Amended and Restated Receivables Purchase Agreement 10.56.1 to PNM's Quarterly 1-6986
dated May 20, 1996, between Public Service Company of Report on Form 10-Q for the
New Mexico, Citibank and Citicorp North America, Inc. quarter ended June 30, 1996.
and Amended Restated Collection Agent Agreement dated
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 September 1, 10.59 to PNM's Annual 1-6986
1993, between The First National Bank of Boston, Report on Form 10-K for
Lessor, and PNM, Lessee (EIP Lease). fiscal year ended December
31, 1993.
10.61 Participation Agreement dated as of June 30, 1983 10.61 to PNM's Annual 1-6986
among Security Trust Company, as Trustee, Report on Form 10-K for
PNM, Tucson Electric Power Company and certain fiscal year ended December
financial institutions relating to the 31, 1993.
San Juan Coal Trust (refiled).
10.62 Agreement of PNM pursuant to Item 601(b)(4)(iii) of 10.62 to PNM's Annual 1-6986
Regulation S-K (refiled). Report on Form 10-K for
fiscal year ended December
31, 1993.
10.64** Results Pay 10.64 to PNM's Quarterly 1-6986
Report on Form 10-Q
for the quarter ended
March 31, 1995.
E-15
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.65 Agreement for Contract Operation and Maintenance of the 10.64 to PNM's Quarterly 1-6986
City of Santa Fe Water Supply Utility System, dated Report on Form 10-Q for the
July 3, 1995. quarter ended June 30, 1995.
10.67 New Mexico Public Service Commission Order dated July 10.67 to PNM's Annual 1-6986
30, 1987, and Exhibit I thereto, in NMPUC Case No. Report on Form 10-K for
2004, regarding the PVNGS decommissioning trust fund fiscal year ended December
(refiled). 31, 1997.
10.68 Master Decommissioning Trust Agreement for Palo Verde 10.68 to PNM's Quarterly 1-6986
Nuclear Generating Station dated March 15, 1996, Report on Form 10-Q for the
between Public Service Company of New Mexico and quarter ended March 31, 1996.
Mellon Bank, N.A.
10.68.1 Amendment Number One to the Master Decommissioning 10.68.1 to PNM's Annual 1-6986
Trust Agreement for Palo Verde Nuclear Generating Report of the Registrant on
Station dated January 27, 1997, between Public Service Form 10-K for fiscal year
Company of New Mexico and Mellon Bank, N.A. ended December 31, 1997.
10.69* Refunding Agreement No. 3 dated as of September 27, 10.69 to PNM's Quarterly 1-6986
1996 between Public Service Company of New Mexico, Report on Form10-Q for the
The Owner Participant named therein, quarter ended September 30,
State Street Bank and Trust Company, as 1996.
Owner Trustee, The Chase Manhattan, Bank, as
Indenture Trustee, and First PV Funding
Corporation.
10.72 Revolving Credit Agreement dated as of March 11, 10.72 to PNM's Quarterly 1-6986
1998, among PNM, the Chase Manhattan Bank, Report on Form 10-Q for the
Citibank, N.A., Morgan Guaranty quarter ended March 31,
Trust Company of New York, and Chase 1998.
Securities, Inc., and the Initial
Lenders Named Therein.
10.73 Refunding Agreement No. 8A, dated as 10.73 to PNM's Quarterly 1-6986
of December 23, 1997, among PNM, the Owner Report on Form 10-Q for the
Participant Named Therein, State Street quarter ended March 31,
Bank and Trust Company, as Owner 1998.
Trustee, The Chase Manhattan Bank,
as Indenture Trustee, nd First PV
a Funding Corporation.
E-16
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.74** Third Restated and Amended Public 10.74 to PNM's Quarterly 1-6986
Service Company of New Mexico Report on Form 10-Q for the
Performance Stock Plan effective March 10, 1998. quarter ended March 31,
1998.
10.74.1** First Amendment to the Third Restated 10.74.1 to PNM's Quarterly 1-6986
and Amended Public Service Company Report on Form 10-Q for the
of New Mexico Performance Stock Plan quarter ended March 31, 2000.
Dated February 7, 2000
10.74.2** Second Amendment to the Third Restated and Amended 10.74.2 to PNM's Annual
Public Service Company of New Mexico Performance Report on Form 10-K for the
Stock Plan, effective December 7, 1998 fiscal year ended December
31, 2000
10.74.3** Third Amendment to the Third Restated and Amended 10.74.3 to PNM's Annual
Public Service Company of New Mexico Performance Report on Form 10-K for the
Stock Plan, effective December 10, 2000 fiscal year ended December
31, 2000
10.74.4** Fourth Amendment to Third Restated and Amended Public 4.3.5 to PNM Resources' 333-03303
Service Company of New Mexico Performance Stock Plan Post-Effective Amendment
dated December 31, 2001 No. 1 to Form 8
Registration Statement
filed December 31, 2001
10.75** First Amended and Restated Public Service Company of 10.75 to PNM Resources and 1-6986
New Mexico Executive Savings Plan dated November 16, PNM's Annual Report on Form
2001. 10-K for the fiscal year
ended December 31, 2001
10.75.1** First Amendment to the First Amended and Restated 4.6 to PNM Resources' Form 333-76316
Public Service Company of New Mexico Executive 8 Registration Statement
Savings Plan effective January 1, 2002 filed January 4, 2002
E-17
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.76 PVNGS Capital Trust--Variable Rate 10.76 to PNM'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 as of 10.77 to PNM's Quarterly 1-6986
October 27, 1999, among Public Service Company of New Report on Form 10-Q for the
Mexico, Tucson Electric Power Company, The City of quarter ended September 30,
Farmington, New Mexico, M-S-R Public Power Agency, 1999.
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.
10.78 Stipulation in the matter of the Commission's 10.78 to PNM's Quarterly 1-6986
investigation of the rates for electric service of Report on Form 10-Q for the
Public Service Company of New Mexico, Rate Case No. quarter ended September 30,
2761, dated May 21, 1999 1999.
10.78.1 Stipulation in the matter of the Commission's 10.78.1 to PNM's Quarterly 1-6986
investigation of the rates for electric service of Report on Form 10-Q for the
Public Service Company of New Mexico, Rate Case No. quarter ended September 30,
2761, dated May 27, 1999 1999.
10.79 Asset Sale Agreement between Tri-State Generation and 10.79 to PNM's Quarterly 1-6986
Transmission Association, Inc., a Colorado Report on Form 10-Q for the
Cooperative Association and Public Service Company of quarter ended September 30,
New Mexico, a New Mexico Corporation, dated September 1999.
9, 1999
10.80** Supplemental Employee Retirement 10.80 to PNM's Quarterly 1-6986
Agreement, dated March 14, 2000 for Report on Form 10-Q for the
Patrick T. Ortiz quarter ended March 31,
2000.
E-18
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.81** Supplemental Employee Retirement 10.81 to PNM's Quarterly 1-6986
Agreement, dated March 22, 2000 for Report on Form 10-Q for the
Jeffry E. Sterba quarter ended March 31,
2000.
10.82 PNM Resources, Inc. Omnibus Performance Equity 4.3 to PNM Resources' Form 333-76288
Plan dated December 31, 2001 8 Registration Statement
filed January 4, 2001
10.83 Transportation Agreement Buy Out Agreement, dated 10.83 to PNM's Quarterly
August 31, 2001 among San Juan Transportation Report on Form 10-Q for the
Company, PNM and Tucson Electric Power Company. quarter ending September
31, 2001 (Confidential
treatment was requested to
portions of this exhibit,
and such portions were
omitted from this exhibits
filed and were filed
separately with the
Securities and Exchange
Commission.)
10.84 Coal Sales Agreement Buy Out Agreement, dated August 10.8 4 to PNM's Quarterly
31, 2001 among San Juan Coal Company, PNM and Tucson Report on Form 10-Q for the
Electric Power Company. quarter ending September
31, 2001 (Confidential
treatment was requested to
portions of this exhibit,
and such portions were
omitted from this exhibits
filed and were filed
separately with the
Securities and Exchange
Commission.)
E-19
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
10.85 Underground Coal Sales Agreement, dated August 31, 10.85 to PNM's Quarterly
2001 among San Juan Coal Company, PNM and Tucson Report on Form 10-Q for the
Electric Power Company. quarter ending September
31, 2001 (Confidential
treatment was requested to
portions of this exhibit,
and such portions were
omitted from this exhibits
filed and were filed
separately with the
Securities and Exchange
Commission.)
Additional Exhibits
99.2* Participation Agreement dated as of 99.2 to PNM's Annual Report 1-6986
December 16, 1985, among the Owner on Form 10-K for fiscal
Participant named therein, First PV 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 PNM'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,
the First National Bank of Boston, as 1996.
Owner Trustee, and Chemical Bank, as
Indenture Trustee together with
Supplemental Indentures Nos. 1 and 2
(refiled).
E-20
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.3.3 Supplemental Indenture No. 3 dated as 99.3.3 to PNM's Quarterly 1-6986
of March 8, 1995, to Trust Indenture Report on Form 10-Q for the
Mortgage, Security Agreement and 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 PNM's Annual Report 1-6986
Agreement dated as of December 16, 1985, on Form 10-K for fiscal
between Public Service Company of New year ended December 31, 1995.
Mexico and The First National Bank
of Boston, as Owner Trustee (refiled).
99.5 Participation Agreement dated as of July 99.5 to PNM's Annual Report 1-6986
31, 1986, among the Owner Participant on Form 10-K for fiscal
named herein, First PV Funding year ended December 31,
Corporation, The First National Bank of 1996.
Boston, in its 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 PNM's Annual Report 1-6986
Agreement and Assignment of Rents on Form 10-K for fiscal
dated as of July 31, 1986, between ended December 31, 1996.
The First National Bank of Boston,
as Owner Trustee, and Chemical
Bank, as Indenture Trustee together
with Supplemental Indenture
No. 1 thereto (refiled).
99.7 Assignment, Assumption, and Further 99.7 to PNM's Annual Report 1-6986
Agreement dated as of July 31, 1986, on Form 10-K for fiscal
between Public Service Company of year ended December 31,
New Mexico and The First National Bank 1996.
of Boston, as Owner Trustee (refiled).
E-21
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.8 Participation Agreement dated as of 99.8 to PNM'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,
Funding Corporation. The First National 1997.
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).
99.8.1* Amendment No. 1 dated as of November 99.8.1 to PNM's Quarterly 1-6986
18, 1986, to Participation Agreement Report on Form 10-Q for the
dated as of August 12, 1986 (refiled). quarter ended March 31,
1997.
99.9* Trust Indenture, Mortgage, Security 99.9 to PNM's Annual Report 1-6986
Agreement and Assignment of Rents of the Registrant on Form
dated as of August 12, 1986, between the 10-K for fiscal year ended
First National Bank of Boston, as Owner December 31, 1996.
Trustee, 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 PNM's Quarterly 1-6986
of March 8, 1995, to Trust Indenture, Report on Form 10-Q for the
Mortgage, Security Agreement and 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 PNM'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).
E-22
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.11* Participation Agreement dated as of December 99.1 to PNM's Quarterly 1-6986
15, 1986, among the Owner Participant named Report on Form 10-Q for the
therein, First PV Funding Corporation, The First quarter ended March 31, 1997.
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 PNM'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,
The First National Bank of Boston, as 1997.
Owner Trustee, and Chemical Bank, as
Indenture Trustee (Unit 1 Transaction)
(refiled).
99.13 Assignment, Assumption and Further 99.13 to PNM'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 December 99.14 to PNM's 1-6986
15, 1986, among the Owner Participant named Quarterly Report on Form
therein, First PV Funding Corporation, The First 10-Q for the quarter ended
National Bank of Boston, in its individual March 31, 1997.
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).
E-23
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.15 Trust Indenture, Mortgage, Security 99.15 to PNM's Annual 1-6986
Agreement and Assignment of Rents dated Report on Form 10-K for
as of December 31, 1986, between the fiscal year ended December
First National Bank of Boston, as Owner 31, 1996.
Trustee, and Chemical Bank, as Indenture
Trustee (Unit 2 Transaction) (refiled).
99.16 Assignment, Assumption, and Further 99.16 to PNM's Quarterly 1-6986
Agreement dated as of December 15, Report on Form 10-Q for the
1986, between Public Service Company of quarter ended March 31, 1997.
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 PNM's Annual 1-6986
Loss Event" dated as of August 18, 1986, Report on Form 10-K for
between the Owner Participant named 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 PNM's Annual 1-6986
Loss Event" dated as of August 18, 1986, Report on Form 10-K for
between the Owner Participant named fiscal year ended December
therein, and Public Service Company of 31, 1996.
New Mexico (refiled).
99.19 Agreement No. 13904 (Option and Purchase of Effluent), 99.19 to PNM's Annual 1-6986
dated April 23, 1973, among Arizona Public Service Report on Form 10-K for
Company, Salt River Project Agricultural Improvement fiscal year ended December
and Power District, the Cities of Phoenix, Glendale, 31, 1996.
Mesa, Scottsdale, and Tempe, and the Town of Youngtown
(refiled).
99.20 Agreement for the Sale and Purchase of 99.20 to PNM's Annual 1-6986
Wastewater Effluent, dated June 12, 1981, Report on Form 10-K for
Among Arizona Public Service Company, fiscal year ended December
Salt River Project Agricultural 31, 1996.
Improvement and Power District and the
City of Tolleson, as amended (refiled).
99.21* 1996 Supplemental Indenture dated as of 99.21 to PNM'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,
Assignment of Rents dated as of December 1996.
16, 1985 between State Street Bank and
Trust Company, as Owner Trustee, and
The Chase Manhattan Bank, as Indenture
Trustee.
E-24
Exhibit No. Description of Exhibit Filed as Exhibit: File No:
- ----------- ---------------------- ----------------- --------
99.22 1997 Supplemental Indenture, dated as of 99.22 to PNM'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,
Assignment of Rents, dated as of August 1998.
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-25
(b) Reports on Form 8-K:
During the quarter ended December 31, 2001 and during the period
beginning January 1, 2002 and ending March 22, 2002, the Company filed, on the
date indicated, the following reports on Form 8-K.
Dated: Filed: Relating to:
------ ------ ------------
September 30, 2001 October 11, 2001 The Company Reports Comparative
Operating Statistics for September 2000 and 2001
October 12, 2001 October 16, 2001 The Company Reports Court to Rule on Western
Resources Agreement
October 23, 2001 October 23, 2001 The Company Reports Third Quarter 2001
Earnings Conference Call
October 24, 2001 October 25, 2001 The Company Reports Quarter and Nine
Months Ended September 30, 2001 Earnings
Announcement and Consolidated Statement
of Earnings
October 30, 2001 November 2, 2001 The Company Reports Merchant Utility Model Combines
Growth with Stability,
CEO Tells Analysts
October 31, 2001 November 15, 2001 The Company Reports Comparative
Operating Statistics for October 2000 and 2001
November 15, 2001 November 16, 2001 The Company Reports Breaking Ground on
New Generating Plant in Southern NM
November 19, 2001 November 30, 2001 The Company Reports Certain Pending Litigation
Brought by the Company in New
York State Court Against Western Resources
November 30, 2001 December 12, 2001 The Company Reports Comparative
Operating Statistics for November 2000
and 2001
December 11, 2001 December 14, 2001 The Company Reports University President
is Named to the Company's Board of
Directors
December 11, 2001 December 14, 2001 The Company Declares Common and
Preferred Stock Dividend
December 19, 2001 December 20, 2001 The Company Reports an Approved
Settlement between the Company and Other
Parties to Allow Activation of a New Holding
Company
E-26
Dated: Filed: Relating to:
------ ------ ------------
December 20, 2001 December 27, 2001 The Company Reports Asking a New York
Court to Dismiss a Lawsuit Filed Against the
Company by Western Resources
December 31, 2001 December 31, 2001 The Company Reports Shareholders of the
Company Approved Management's Plan to
Create a New Holding Company
January 8, 2002 January 9, 2002 The Company Reports Terminating the
Western Resources Agreement
January 9, 2002 January 10, 2002 The Company Announces New Power
Plant in Southern New Mexico
December 31, 2001 January 15, 2002 The Company Reports Comparative
Operating Statistics for December 2001 and
2000
January 22, 2002 January 23, 2002 The Company Reports Plans to Retire
Transmission Line Debt
January 23, 2002 January 24, 2002 The Company Reports Quarter and Nine
Months Ended December 31, 2001 Earnings
Announcement and Consolidated Statement
of Earnings
February 19, 2002 February 21, 2002 The Company Reports an Increase in
Common Stock Dividend
January 31, 2002 February 27, 2002 The Company Reports Comparative
Operating Statistics for January 2002 and
2001
February 28, 2002 March 14, 2002 The Company Reports Comparative
Operating Statistics for February 2002 and
2001
March 19, 2002 March 19, 2002 The Company Reports 2002 Annual Meeting
of Shareholders on May 14, 2002
E-27
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.
PNM RESOURCES, INC.
(Registrant)
Date: March 26, 2002 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 March 26, 2002
- --------------------------------- Officer and Chairman
J. E. Sterba of the Board
Chairman, President and
Chief Executive Officer
/s/ M. H. MAERKI Principal Financial March 26, 2002
- --------------------------------- Officer
M. H. Maerki
Senior Vice President and
Chief Financial Officer
/s/ J. R. LOYACK Principal Accounting March 26, 2002
- --------------------------------- Officer
J. R. Loyack
Vice President, Corporate Controller
and Chief Accounting Officer
/s/ R. G. ARMSTRONG Director March 26, 2002
- ---------------------------------
R. G. Armstrong
/s/ R. M. CHAVEZ Director March 26, 2002
- ---------------------------------
R. M. Chavez
/s/ J. A. GODWIN Director March 26, 2002
- ---------------------------------
J. A. Godwin
/s/ B. F. MONTOYA Director March 26, 2002
- ---------------------------------
B. F. Montoya
/s/ M. T. PACHECO Director March 26, 2002
- ---------------------------------
M. T. Pacheco
/s/ T. F. PATLOVICH Director March 26, 2002
- ---------------------------------
T. F. Patlovich
/s/ R. M. PRICE Director March 26, 2002
- ---------------------------------
R. M. Price
/s/ P. F. ROTH Director March 26, 2002
- ---------------------------------
P. F. Roth
E-28