UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20012002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to _________.
Commission Registrant; State of Incorporation; IRS Employer
File Number Address; and Telephone Number Identification Number
----------- ---------------------------------- ---------------------
1-13739 UNISOURCE ENERGY CORPORATION 86-0786732
(An Arizona Corporation)
One South Church Avenue, Suite 100
Tucson, AZ 85701
(520) 571-4000
1-5924 TUCSON ELECTRIC POWER COMPANY 86-0062700
(An Arizona Corporation)
One South Church Avenue, Suite 100
Tucson, AZ 85701
(520) 571-4000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
---------- ------------------- --------------------------------------------
UniSource Energy Common Stock, no par New York Stock Exchange
Corporation value and Preferred Pacific Exchange
Share Purchase Rights Pacific Stock
Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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 each registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes X No
----- -----
The aggregate market value of UniSource Energy Corporation voting Common
Stock held by non-affiliates of the registrant was $578,856,011$622,739,272 based on
the last reported sale price thereof on the consolidated tape on February 25,June 28, 2002.
At February 25, 2002, 33,539,487March 4, 2003, 33,583,182 shares of UniSource Energy Corporation
Common Stock, no par value (the only class of Common Stock), were outstanding.
At February 25, 2002,March 4, 2003, UniSource Energy Corporation is the holder of
32,139,434 shares of the outstanding Common Stockcommon stock of Tucson Electric Power
Company.
Documents incorporated by reference: Specified portions of UniSource
Energy Corporation's Proxy Statement relating to the 20022003 Annual Meeting of
Shareholders are incorporated by reference into PART III.
- --------------------------------------------------------------------------------
This combined Form 10-K is separately filed by UniSource Energy Corporation and
Tucson Electric Power Company. Information contained in this document relating
to Tucson Electric Power Company is filed by UniSource Energy Corporation and
separately by Tucson Electric Power Company on its own behalf. Tucson Electric
Power Company makes no representation as to information relating to UniSource
Energy Corporation or its subsidiaries, except as it may relate to Tucson
Electric Power Company.
TABLE OF CONTENTS
Page
----
Definitions................................................................ v
- PART I -
Item 1. - Business
Overview of Consolidated Business.........................................1
Outlook and Strategy......................................................1
TEP Electric Utility Operations
Overview of Electric Utility............................................2
Peak Demand.............................................................3
Retail Customers........................................................3
Wholesale Business......................................................4Service Area and Customers..............................................2
Generating and Other Resources..........................................6Resources..........................................5
Fuel Supply.............................................................7
Water Supply............................................................9
Transmission Access.....................................................9
Rates and Regulation....................................................8
Fuel Supply............................................................13
Water Supply...........................................................14Regulation...................................................10
TEP's Utility Operating Statistics.....................................15Statistics.....................................12
Environmental Matters....................................................16Matters..................................................13
Millennium Energy Businesses.............................................17Businesses.............................................14
UniSource Energy Development Company.....................................18
Employees................................................................19Company.....................................15
Employees................................................................16
SEC Reports available on UniSource Energy's Website......................16
Item 2. - Properties.......................................................19Properties.......................................................18
Item 3. - Legal Proceedings................................................21Proceedings................................................19
Item 4. - Submission of Matters to a Vote of Security Holders..............21Holders..............19
- PART II -
Item 5. - Market for Registrant's Common Equity and Related
Stockholder Matters..............................................22Matters..............................................20
Item 6. - Selected Consolidated Financial Data
UniSource Energy.........................................................23
TEP......................................................................24Energy.........................................................21
TEP......................................................................22
Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview.................................................................25Operations....................................................23
UniSource Energy Consolidated..........................................23
Contribution by Business Segment.......................................24
Results of TEP.........................................................24
Results of Millennium Energy Businesses................................28
Results of UED.........................................................29
Income Tax Position......................................................29
Asset Purchase Agreements................................................29
Factors Affecting Results of Operations
Competition............................................................26Competition............................................................30
Industry Restructuring.................................................27Restructuring.................................................31
Market Risks...........................................................30Risks...........................................................34
Outlook and Strategies.................................................37
Critical Accounting Policies.............................................33
Results of Operations....................................................35
Contribution by Business Segment.......................................36
Utility Sales and Revenues.............................................36
Operating Expenses.....................................................38
Interest Income........................................................40Policies...........................................37
TABLE OF CONTENTS
(continued)
Page
- -----------------------------------------------------------------------------
Interest Expense.......................................................40
Income Taxes...........................................................40
Extraordinary Income - Net of Tax......................................40
Results of Millennium Energy Businesses..................................41
Results of UED...........................................................42
Dividends on Common Stock................................................42
Income Tax Position......................................................43
Liquidity and Capital Resources
Overall Liquidity......................................................43UniSource Energy - Consolidated Cash Flows.............................................................45
Investing and Financing ActivitiesFlows.............................42
UniSource Energy - Parent Company....................................46Company......................................43
TEP - Electric Utility...............................................46Utility.................................................43
Operating Activities.................................................43
Investing Activities.................................................44
Financing Actitities.................................................45
Millennium - Unregulated Energy Businesses...........................50Businesses.............................47
UED - Unregulated Energy Business....................................51Business......................................49
Financing Risks........................................................49
Contractual Obligations................................................50
Guarantees and Indemnities.............................................51
Dividends on Common Stock..............................................52
New Accounting Pronouncements............................................52
Safe Harbor for Forward-Looking Statements...............................51Statements...............................53
Item 7A. -7A.- Quantitative and Qualitative Disclosures about Market Risk......52Risk.......54
Item 8. - Consolidated Financial Statements and Supplementary Data.........52Data.........54
Report of Independent Accountants........................................53Accountants........................................55
UniSource Energy Corporation
Consolidated Statements of Income......................................54Income......................................56
Consolidated Statements of Cash Flows..................................55Flows..................................57
Consolidated Balance Sheets............................................56Sheets............................................58
Consolidated Statements of Capitalization..............................57Capitalization..............................59
Consolidated Statements of Changes in Stockholders' Equity.............58Equity.............60
Tucson Electric Power Company
Consolidated Statements of Income......................................59Income......................................61
Consolidated Statements of Cash Flows..................................60Flows..................................62
Consolidated Balance Sheets............................................61Sheets............................................63
Consolidated Statements of Capitalization..............................62Capitalization..............................64
Consolidated Statements of Changes in Stockholders' Equity.............63Equity.............65
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting
Policies......................................................64Policies......................................................66
Note 2. Regulatory Matters..............................................68Matters..............................................72
Note 3. Accounting for Derivative Instruments, Trading Activities
and Hedging Activities....73Activities........................................75
Note 4. Millennium Energy Businesses....................................75Businesses....................................77
Note 5. Segment and Related Information.................................77Business Segments...............................................80
Note 6. TEP's Utility Plant and Jointly-Owned Facilities................79Facilities................82
Note 7. Long-Term Debt and Capital Lease Obligations....................79Obligations..............................83
Note 8. Fair Value of UniSource EnergyTEP's Financial Instruments............82Instruments.......................85
Note 9. Dividend Limitations............................................82Stockholders' Equity............................................86
Note 10. Commitments and Contingencies...................................83Contingencies...................................87
Note 11. Wholesale Accounts Receivable and Allowances....................86Allowances....................91
Note 12. Income Taxes....................................................88Taxes....................................................92
Note 13. Employee Benefits Plans.........................................90Plans.........................................94
Note 14. UniSource Energy Earnings Per Share (EPS).......................94.......................98
Note 15. Warrants........................................................95Asset Purchase Agreements.......................................99
Note 16. UniSource Energy Shareholder Rights Plan........................95
Note 17. Supplemental Cash Flow Information..............................96Information.............................100
Note 18.17. Quarterly Financial Data (Unaudited)............................98...........................103
TABLE OF CONTENTS
(concluded)
Page
- -----------------------------------------------------------------------------
Schedule II - Valuation and Qualifying Accounts........................ 101Accounts.........................106
- PART III -
Item 9. - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................................102Disclosure.......................................107
Item 10. - Directors and Executive Officers of the Registrants
Directors...............................................................102
Executive Officers......................................................102Registrants............107
Item 11. - Executive Compensation.........................................104Compensation.........................................109
Item 12. - Security Ownership of Certain Beneficial Owners and
Management
General.................................................................104
Security Ownership of Certain Beneficial Owners.........................105
Security Ownership of Management........................................105Management.....................................................109
Item 13. - Certain Relationships and Related Transactions.................105Transactions.................110
- PART IV -
Item 14. - Controls and Procedures........................................111
Item 15. - Exhibits, Financial Statement Schedules, and Reports
on Form 8-K...........................................................106
Signatures..............................................................1078-K...........................................................111
Signatures..............................................................113
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act.........117
Exhibit Index...........................................................111Index...........................................................121
DEFINITIONS
The abbreviations and acronyms used in the 20012002 Form 10-K are defined below:
- ------------------------------------------------------------------------------
ACC.......................... Arizona Corporation Commission.
ACC Holding Company Order.... The order approved by the ACC in November 1997
allowing TEP to form a holding company.
AISA......................... Arizona Independent Scheduling Administrator,
a temporary organization required by the ACC
Retail Electric Competition Rules.AHMSA........................ Altos Hornos de Mexico, S.A. de C.V. AHMSA owns
50% of Sabinas.
ALJ.......................... FERC Administrative Law Judge.
APS.......................... Arizona Public Service Company.
BTU..........................Btu.......................... British Thermal Unit(s)thermal unit(s).
CAAA......................... Federal Clean Air Act Amendments.
Capacity..................... The ability to produce power; the most power
a unit can produce or the maximum that can
be taken under a contract; measured in MWs.
CDWR......................... California Department of Water Resources.
CISO......................... California Independent System Operator.
Citizens..................... Citizens Communications Company.
Common Stock................. UniSource Energy's common stock, without par
value.
Company or UniSource Energy.. UniSource Energy Corporation.
Cooling Degree Days.......... CalculatedAn index used to measure the impact of weather
on energy usage calculated by subtracting 75
from the average of the high and low daily
temperatures.
CPX.......................... California Power Exchange.
Credit Agreement............. Credit Agreement between TEP and a syndicate
of banks, dated as of December 30, 1997.
Desert STAR.................. The ISO formed in the southwestern U.S., in
which TEP is a participant.November 14, 2002.
Emission Allowance(s)........ An EPA-issued allowance which permits
emission of one ton of sulfur dioxide.
These allowances can be bought orand sold.
Energy....................... The amount of power produced over a given
period of time; measured in MWh.
EPA.......................... The Environmental Protection Agency.
ESP.......................... Energy Service Provider.
Express Line................. 345-kV circuit connecting Springerville
Unit 2 to the Tucson 138 kV system.
FAS 71....................... Statement of Financial Accounting Standards
No. 71: Accounting for the Effects of
Certain Types of Regulation.
FAS 133...................... Statement of Financial Accounting Standards
No. 133: Accounting for Derivative
Instruments and Hedging Activities.
FAS 143...................... Statement of Financial Accounting Standards
No. 143: Accounting for Asset Retirement
Obligations.
FERC......................... Federal Energy Regulatory Commission.
First Collateral Trust
Bonds...................... Bonds issued under the Indenture of Trust,
dated as of August 1, 1998, of TEP to the
Bank of New York, successor trustee.
First Mortgage Bonds......... First mortgage bonds issued under the Indenture,
dated as of April 1, 1941, of TEP to JPMorgan
Chase Bank, successor trustee, as supplemented
and amended.
Four Corners................. Four Corners Generating Station.
GAAP......................... Generally Accepted Accounting Principles.
GES.......................... Global Energy Solutions, Inc., a majority-owned
subsidiary of Millennium, which owns 100% of
Global Solar and Infinite Power Solutions.
Global Solar................. Global Solar Energy, Inc., a wholly-owned
subsidiary of GES, whichcompany that
develops and manufactures thin-film
photovoltaic cells. Millennium owns 87% of
Global Solar.
Heating Degree Days.......... CalculatedAn index used to measure the impact of weather
on energy usage calculated by subtracting the
average of the high and low daily temperatures
from 65.
IDBs......................... Industrial development revenue or pollution
control revenue bonds.
Infinite Power Solutions.....IPS.......................... Infinite Power Solutions, Inc., a wholly-owned
subsidiary of GES, whichcompany that
develops thin-film batteries. Millennium owns
77.5% of IPS.
IRS.......................... Internal Revenue Service.
DEFINITIONS
(continued)
- ------------------------------------------------------------------------------
Irvington.................... Irvington Generating Station.
Irvington Lease.............. The leveraged lease arrangement relating to
Irvington Unit 4.
ISO.......................... Independent System Operator.
ITN.......................... ITN Energy Systems, Inc. was formed to provide
research, development, and other services.
Millenium currently owns 49% but has agreed
to reduce its ownership to 9%.
ITC.......................... Investment tax credit.
kW........................... Kilowatt(s).
kWh.......................... Kilowatt-hour(s).
kV........................... Kilovolt(s).
LOC.......................... Letter of Credit.
MEG.......................... Millennium Environmental Group, Inc., a wholly-
owned subsidiary of Millennium, which manages
and trades emission allowances, coal, and
related financial instruments.
MEH.......................... MEH Corporation, a wholly-owned subsidiary
of Millennium, which formerly held a 50%
interest in NewEnergy.
MicroSat..................... MicroSat Systems, Inc., is a company owned 49% by
Millennium, which was formed to
develop and commercialize small-scale
satellites. Millennium currently owns 49%
but has agreed to reduce its ownership to 35%.
Millennium................... Millennium Energy Holdings, Inc., a wholly-owned
subsidiary of UniSource Energy.
Mimosa....................... Minerales de Monclova, S.A. de C.V., an owner of
coal and associated gas reserves and a supplier
of metallurgical coal to the steel industry
and thermal coal to the Mexican electricity
commission. Sabinas owns 19.5% of Mimosa.
MMBtus....................... Million British Thermal Units.
MSR.......................... Modesto, Santa Clara and Redding Public Power
Agency.
MW........................... Megawatt(s).
MWh.......................... Megawatt-hour(s).
Nations Energy............... Nations Energy Corporation, a wholly-owned
subsidiary of Millennium, and holder of a
minority interest in an independent power
project in Panama.
Navajo....................... Navajo Generating Station.
NewEnergy.................... NewEnergy, Inc., formerly New Energy Ventures,
Inc., a company in which a 50% interest was
owned by MEH.
NOL.......................... Net Operating Loss carryback or carryforward for
income tax purposes.
NTUA......................... Navajo Tribal Utility Authority.
PDES......................... Phelps Dodge Energy Services.
PG&E......................... Pacific Gas and Electric Company.
PNM.......................... Public Service Company of New Mexico.
Rate Settlement.............. TEP's Rate Settlement agreement approvedPowertrusion................. POWERTRUSION, International, Inc., a company
owned 50.5% by the
ACC in August 1998,Millennium, which provided retail base
price decreases over a two-year period.manufactures
lightweight utility poles.
Revolving Credit.Facility.... $100Credit Facility.... $60 million revolving credit facility entered
into under the Credit Agreement between a
syndicate of banks and TEP.
RTO.......................... Regional Transmission Organization.
Rules........................ Retail Electric Competition Rules.
Sabinas...................... Carboelectrica Sabinas, S. de R.L. de C.V., a
Mexican limited liability company. Millennium
owns 50% of Sabinas.
San Carlos................... San Carlos Resources Inc., a wholly-owned
subsidiary of TEP.
San Juan..................... San Juan Generating Station.
Second Mortgage Bonds........ TEP's second mortgage bonds issued under the
Indenture of Mortgage and Deed of Trust, dated
as of December 1, 1992, of TEP to the Bank of
New York, successor trustee, as supplemented.
SCE.......................... Southern California Edison Company.
SES.......................... Southwest Energy Solutions, Inc., a wholly-owned
subsidiary of Millennium.
Settlement Agreement......... TEP's Settlement Agreement approved by the ACC
in November 1999 that provided for electric
retail competition and transition recovery
asset
recovery.
Springerville................ Springerville Generating Station.
DEFINITIONS
(concluded)
- ------------------------------------------------------------------------------
Springerville Coal Handling
Facilities Leases............ Leveraged lease arrangements relating to the
coal handling facilities serving
Springerville.
Springerville Common
Facilities................. Facilities at Springerville used in common
with Springerville Unit 1 and Springerville
Unit 2.
Springerville Common
Facilities Leases.......... Leveraged lease arrangements relating to an
undivided one-half interest in certain
Springerville Common Facilities.
Springerville Unit 1......... Unit 1 of the Springerville Generating Station.
Springerville Unit 1 Lease... Leveraged lease arrangement relating to
Springerville Unit 1 and an undivided
one-half interest in certain Springerville
Common Facilities.
Springerville Unit 2......... Unit 2 of the Springerville Generating Station.
SRP.......................... Salt River Project Agricultural Improvement
and Power District.
TEP.......................... Tucson Electric Power Company, the principal
subsidiary of UniSource Energy.
TEP Warrants................. Warrants for the purchase of TEP common stock
which were issued in 1992.
TOUA......................... The Tohono O'odham Utility Authority.Tri-State.................... Tri-State Generation and Transmission
Association.
TruePricing.................. TruePricing, Inc., a start-up company
established to market energy related
products.
UED.......................... UniSource Energy Development Company, a wholly-
owned subsidiary of UniSource Energy, which
owns a 20 MW gas turbine under lease to TEP
and
engages in developing generation resources
and other project development services and
related activities.
UniSource Energy............. UniSource Energy Corporation.
UniSource Energy Warrants.... Warrants for the purchase of UniSource Energy
Common Stock that were issued in exchange for
TEP Warrants, pursuant to an exchange offer
which expired October 23, 1998.Warrants.
WestConnect.................. The proposed for-profit RTO formed by the
reorganization of Desert STAR, in which TEP is a
participant.
WSCC......................... Western Systems Coordinating Council.
PART I
This Annual Report on Form 10-K contains forward-looking statements as
defined by the Private Securities Litigation Reform Act of 1995. You should
read forward-looking statements together with the cautionary statements and
important factors included in this Form 10-K. (See Item 7. - Management's
Discussion and Analysis of Financial Condition and Results of Operations,
Safe Harbor for Forward-Looking Statements.) Forward-looking statements
include statements concerning plans, objectives, goals, strategies, future
events or performance and underlying assumptions. Forward-looking statements
are not statements of historical facts. Forward-looking statements may be
identified by the use of words such as "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," "projects," and similar expressions. We
express our expectations, beliefs and projections in good faith and believe
them to have a reasonable basis. However, we make no assurances that
management's expectations, beliefs or projections will be achieved or
accomplished.
ITEM 1. - BUSINESS
- --------------------------------------------------------------------------------
OVERVIEW OF CONSOLIDATED BUSINESS
- ---------------------------------
UniSource Energy Corporation (UniSource Energy) is a holding company
that owns the outstanding common stock of Tucson Electric Power Company
(TEP), Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy
Development Company (UED). TEP, is an electric utility, that has provided electric
service to the community of Tucson, Arizona, for over 100 years. TEP is UniSource Energy's
principal subsidiary and represents most of UniSource Energy's
assets. Millennium
invests in unregulated ventures, related
primarily to the energy business, including a developer of thin-film
batteries, a developer of small-scale commercial satellites, and a developer
and manufacturer of thin-film photovoltaic cells. UED engages in developing
generating resources and other project development activities, including
facilitating the expansion of the Springerville Generating Station through construction of
Springerville Units 3 and 4.Station. We
conduct our business in these three primary business segments--TEP'ssegments-TEP's Electric
Utility Segment, the Millennium Energy Businesses Segment, and the UniSource
Energy Development Segment. See Notes 4 and 5 of Notes to Consolidated
Financial Statements,Statements. See Millennium Energy Businesses and UniSource Energy
Development Company below.
References in this report to "we" and "our" are toIn October 2002, UniSource Energy entered into two Asset Purchase
Agreements with Citizens Communications Company (Citizens) for the purchase
by UniSource Energy of Citizens' Arizona electric utility and its subsidiaries, collectively. Referencesgas utility
businesses for a total of $230 million. The purchase price of each is
subject to adjustment based on the date on which the transaction is closed
and, in this
reporteach case, on the amount of certain assets and liabilities of the
purchased business at the time of closing. The closing of these transactions
is subject to approval by the "utility business" areArizona Corporation Commission (ACC), the
Federal Energy Regulatory Commission (FERC) and the SEC. If completed, these
transactions would add to TEP.our customer base approximately 77,500 retail
electric customers in Arizona, and approximately 122,000 retail gas customers
in Arizona. See Item 7.-Management's Discussion and Analysis of Financial
Condition and Results of Operations, Asset Purchase Agreements, for more
information regarding these transactions.
TEP was incorporated in the State of Arizona on December 16, 1963. TEP
is the successor by merger as of February 20, 1964, to a Colorado corporation
that was incorporated on January 25, 1902. UniSource Energy was incorporated
in the State of Arizona on March 8, 1995 and obtained regulatory approval to
form a holding company in November 1997. On January 1, 1998, TEP and
UniSource Energy exchanged shares of stock resulting in TEP becoming a
subsidiary of UniSource Energy. Following the share exchange, TEP
transferred the stock of its subsidiary Millennium to UniSource Energy. See
Note 1 of Notes to Consolidated Financial Statements - NatureStatements-Nature of Operations and
Summary of Significant Accounting Policies.
OUTLOOK AND STRATEGYThe table below shows the contributions to our consolidated after-tax
earnings by our three business segments, as well as parent company expenses.
2002 2001 2000
--------------------------------------------------------------------
- --------------------
In recent years,Millions of Dollars -
Business Segment
TEP $ 53.7 $ 75.3 $ 51.2
Millennium (15.5) (9.2) (4.1)
UED 0.8 0.8 -
UniSource Energy Standalone (1) (5.8) (5.6) (5.2)
--------------------------------------------------------------------
Consolidated Net Income $ 33.2 $ 61.3 $ 41.9
====================================================================
(1) Represents interest expense (net of tax) on the note payable
from UniSource Energy to TEP.
The electric utility industry has undergone significant regulatory
change designed to encourage competition in the salerecent years. See Item 7. - Management's Discussion and Analysis
of electric generation services. Recent actions by the
Arizona Corporation Commission (ACC), however, have added
uncertainty regarding the ongoing implementationFinancial Condition and Results of competition
rules in Arizona. Additionally, FERC issued various orders in
response to the California energy crisis which have impactedOperations, Factors Affecting Results
of Operations, Outlook and Strategies, for a discussion of our businesses. We continually evaluate our position to developplans and
strategies to remain competitive and flexible in this changing environment. Our plansenvironment
and strategies includeRates and Regulation, below, for the following:
- Enhancestatus of competition in Arizona.
References in this report to "we" and "our" are to UniSource Energy and
its subsidiaries, collectively. References in this report to the value of our transmission system while continuing"utility
business" are to provide reliable access to generation for our retail
customers and market access for all generating assets. This
will include focusing on completing a transmission line to an
electric distribution company in Nogales, Arizona. This line
could eventually be connected to Mexico's utility system.
- Facilitate the construction of Springerville Units 3 and 4,
which will allow us to spread the fixed costs of TEP's
Springerville Units 1 and 2 over four units. This includes
obtaining construction financing in 2002.
- Reduce TEP's debt as appropriate, using some of our excess
cash flows.
- Proactively maintain our transmission and distribution system
to ensure reliable service to our retail customers.
- Efficiently manage our generating resources and look for ways to
reduce or control operating costs in order to improve profitability.
- Actively participate in the formulation of regulatory policies
and actions, including reconsideration of the current requirement
to transfer TEP's generation assets to a wholly-owned subsidiary
by December 31, 2002.
- Focus the efforts of Millennium's technology entities to begin
larger scale production of Global Solar Energy's thin-film
photovoltaic cells and develop thin-film battery technology. Seek
strategic partners and investors to achieve commercial operation of
these businesses.
To accomplish our goals, we estimate that during 2002, TEP will
spend $124 million on capital expenditures, Millennium will provide
at least $14 million of funding to its technology investments, and
we will provide between $30 million and $100 million to UED. Our
funding of UED will depend upon the timing of financial close of the
Springerville Unit 3 and 4 project and UED's ultimate ownership
percentage.TEP.
TEP ELECTRIC UTILITY OPERATIONS
- -------------------------------
OVERVIEW OF ELECTRIC UTILITYTEP is the principal operating subsidiary of UniSource Energy. In 2002,
TEP's electric utility operations contributed 99% of UniSource Energy's
operating revenues and comprised 94% of its assets.
SERVICE AREA AND CUSTOMERS
TEP is a vertically integrated utility that provides regulated electric
service to over 350,000355,000 retail customers in its retail service territory. This
service territory consists of a 1,155 square mile area of Southeastern
Arizona with a population of approximately 871,000891,000 in the greater Tucson
metropolitan area in Pima County, as well as parts of Cochise County. TEP
holds a franchise to provide electric distribution service to customers in
the CityCities of Tucson and South Tucson. This franchise expiresThese franchises expire in 2026.2026 and
2017, respectively. TEP also sells electricity to other utilities and power
marketing entities in the western U.S.
In 1999, the ACC approved the Retail Electric Competition Rules
(Rules) that required TEP to unbundle itsRETAIL CUSTOMERS
TEP's retail electric services
into separate generation, transmission and distribution services
with open retail competition for generation services. In November
1999, the ACC approved TEP's Settlement Agreement with certain
customer groups relating to the implementation of retail
competition. This Settlement Agreement provided the framework for
transition to a fullysales are influenced by several factors, including seasonal
weather patterns, competitive generation market, including a
requirement to transfer TEP's generating assets to a separate
subsidiary by December 31, 2002. Recent events such as California's
experience with retail electric competition and legislative and
regulatory actions in other Western states have caused the ACC to
begin to reexamine the implementation of the Rulesconditions and the impact
thereon, if any, on the Settlement Agreement.
PEAK DEMAND
Peak Demand 2001 2000 1999 1998 1997
-------------------------------------
- MW -
Retail Customers-Net One Hour 1,840 1,862 1,754 1,786 1,659
Firm Sales to Other Utilities 151 143 178 179 177
- --------------------------------------------------------------------------------
Non-Coincident Peak Demand (A) 1,991 2,005 1,932 1,965 1,836
Total Generating Resources 1,999 1,904 1,904 1,896 1,992
Other Resources 217 248 235 235 235
- --------------------------------------------------------------------------------
Total TEP Resources (B) 2,216 2,152 2,139 2,131 2,227
Total Reserves (B) - (A) 225 147 207 166 391
Reserve Margin (% of Non-
Coincident Peak Demand) 11% 7% 11% 8% 21%
- --------------------------------------------------------------------------------
The weather causes seasonal fluctuations in TEP's sales.overall economic climate.
The peak demand for TEP's retail service area occurs during the summer months
due to the cooling requirements of ourTEP's retail customers. TEP's retail peak
demand has grown at an average annual rate of approximately 3.0%2.7% during the
past five years.
The chart above shows the relationship over a five-year period
betweenIn 2002, TEP's peak demand and its energy resources. In addition to
TEP's generating resources, total resources include firm capacity
purchases and interruptible retail load. TEP's reserves are the
difference between energy resources and peak demand, and the reserve
margin is the ratio of reserves to peak demand. For planning
purposes, TEP calculates its reserve margin in accordance with
guidelines set by the Western Systems Coordinating Council (WSCC)
and strives to maintain the minimum reserve margin indicated by
those guidelines equal to its largest single hazard plus 5% of its
non-coincident peak demand. For 2001, these guidelines suggested a
reserve margin of 330 MW or 17% of non-coincident peak demand.
TEP's actual reserve margin in 2001 was 11%. TEP purchased
additional firm energy in the forward energy markets for its third
quarter peak period in 2001 to ensure it had adequate operating
reserve margins.
TEP's forecasted retail peak demand for 2002 is approximately
1,800 MW. This is lower than actual peak demand in 2000 and 2001
due to load reductions by TEP's mining customers. Although TEP
believes it has sufficient resources to meet this expected demand in
2002 with its existing resources, it plans to make forward
purchases of approximately 50 MW to ensure adequate supply during
its summer peak period. See Future Generating Resources and Power
Exchange Agreement, below.
RETAIL CUSTOMERS
The average number of TEP's retail customers increased by 2.5%
in 2001 to 347,099. TEP expects that the number of retail
distribution customers, as well as the total amount of energy
consumed by this customer group, will grow at an average annual rate
of approximately 1.6% through 2006. Retail peak demand in TEP's
service territory is expected to grow at an average annual rate of
1.8% over the same period. TEP expects energy consumed by its
residential, commercial, non-mining industrial, mining and public
authority customers to comprise approximately 38%, 20%, 27%, 12% and
3%, respectively, of2.4% while total
retail energy consumption during that
period.decreased by approximately 3%. This decrease in
kWh energy sales was primarily attributable to reduced sales to copper mining
customers. See Sales to Large Industrial Customers, below. The table below
shows the trend in the percentage distribution of energy sales by major
customer class over the last three years.
2002 2001 2000
---- ---- ----
Residential 40% 38% 37%
Commercial 20% 19% 18%
Non-mining Industrial 28% 27% 28%
Mining 9% 13% 14%
Public Authority 3% 3% 3%
TEP uses population and demographic studies prepared by unrelated third
parties to forecast the growth in the number of customers, peak demand and
retail sales. TEP also makes assumptions about the weather, the economy and
competitive conditions. Based on these factors, TEP expects that its peak
demand, its number of retail customers and their energy consumption will
increase at 2 - 3% annually through 2006.
During that period, TEP expects total retail energy consumption by customer
class will be distributed similarly to the 2002 distribution.
Beginning January 1, 2001, all of TEP's retail customers were eligible
to choose alternative energy providers. Even though some of TEP's retail
customers may choose other energy suppliers,providers, the forecasted growth rates in
the number of customers referred to above would continue to apply to TEP's
distribution business. As of February 25, 2002March 4, 2003, no TEP retail customers are
currently served by alternate energy suppliers.providers. See TEP's Settlement AgreementRates and Retail Electric Competition Rules,Regulation,
State, below.
Sales to Large Industrial Customers
-----------------------------------
TEP provides electric utility service to a diversified group of
commercial, industrial, and public sector customers. Major industries served
include copper mining, cement manufacturing, defense, health care, education,
military bases and other governmental entities. Local, regional, and
national economic factors can impact the financial condition and operations
of TEP's large industrial customers. Such economic conditions may directly
impact energy consumption by large industrial customers, and may indirectly
impact residential and small commercial sales and revenues if employment
levels and consumer spending is affected.
Two of TEP's largest retail customers are in the copper mining industry.
In 2001, sales to
these customers totaled about 13% of TEP's total retail energy
sales, and their actual demand totaled approximately 8% of the 2001
retail peak demand. Revenues from sales to mining customers
decreased by $6 million in 2001 and accounted for 6% of TEP's retail
revenues.
TEP has contracts with its two principal mining customers to provide them electric power at
specified non-tariffednegotiated rates. These contracts expire between 2003in 2006 and 2006. However, under certain
conditions and with advance notice to TEP, the mines can cancel all
or part of their contracts. To date, TEP has not received any
termination notices.2008. Whether these
contracts are extended or terminated will depend, in part, on market
conditions and available alternatives. SalesTEP's sales to mining customers
depend on a variety of factors including changes in supply and demand in the
world copper market and the economics of self-generation. During 2001, marketU.S. copper prices
for copper were consistent with year 2000 prices, which were
slightly higher thanapproximately 77 cents per pound in February 2003, and have ranged
between 63 cents and 91 cents per pound during the low prices experienced during 1998 and
1999. However, these prices still remain low relative to historical
prices.last five years. As athe
result of these low copper prices, TEP's mining customers have reduced operation levelsoperations
in recent years, and have correspondingly reduced energy consumption. See
Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations, Results of TEP, Utility Sales and Revenues.
Energy sales to lower
their electricity costs. Theseand revenues from TEP's mining customers recently announced
additional reductionsmay continue to
decline in the future. One of TEP's mining customers substantially curtailed
mining operations at one of its mines in December of 2002. This reduction in
operations will further decrease sales. TEP's revenue from this customer was
approximately $11 million in 2002. Any reduction of this retail revenue
would be mitigated, however, by an opportunity for TEP to sell this
generation capacity in the wholesale market or to reduce generation with
resulting fuel costs reductions. Depending on wholesale market price
assumptions, TEP's pre-tax net income in 2003 could be reduced by $1 million
to $3 million from the 2002 which we anticipate will result in a
40 MW load reduction to system retail peak demand.level if this customer ceases mining operations
at this location.
WHOLESALE BUSINESS
TEP's electric utility operations include the wholesale marketing of
electricity to other utilities and power marketers. These wholesale sales
transactions are made on both a firm basis and an interruptible basis. A
firm basis means that contractually, TEP must supply the power (except under
limited emergency circumstances), while an interruptible basis means that TEP
may stop supplying power under various circumstances. See Other Purchases
and Interconnections, below.
TEP typically uses its own generation to serve the requirements of its
retail and long-term wholesale customers. Generally, TEP commits to future
sales based on expected excess generating capability, forward prices and
generation costs, using a diversified portfolio approach to provide a balance
between long-term, mid-term and spot energy sales. When TEP expects to have
excess generating capacity (usually in the first, second and fourth calendar
quarters), TEP may enter into forward contracts to sell a portion of this
forecasted excess generating capacity. Then, during the course of each
month, TEP will analyze any remaining excess short-term generating capacity
and make energy sales in the daily and hourly markets. TEP also enters into
limited forward sales and purchases to take advantage of favorable market
opportunities.
TEP's wholesale sales consist primarily of four types of sales:
(1) Sales under long-term contracts for periods of more than
one year. TEP has long-term contracts with three entities
to sell firm capacity and energy:
- Salt River Project (SRP), expiring May 31, 2011, with a
contract demand of 100 MW;
- Navajo Tribal Utility Authority (NTUA), expiring December
31, 2009, a full requirements contract with a typical
high demand of approximately 50 MW in the summer and
90 MW in the winter; and
- Tohono O'odham Utility Authority (TOUA), expiring August
31, 2004, a full requirements contract with a typical
high demand of less than 5 MW.
TEP also has a long-term interruptible contract with Phelps
Dodge Energy Services (PDES). This contract expires March 1,
2006 and requires a fixed contract demand of 60 MW at all
times except during TEP's peak customer energy demand period,
from July through September of each year. Under the
contract, TEP can interrupt delivery of power if the utility
experiences significant loss of any generating resources.
(2) Forward contracts to sell energy for periods through the end
of the next calendar year. Under forward contracts, TEP
commits to sell a specified amount of capacity or energy at
a specified price over a given period of time, typically for
one-month, three-month or one-year periods.
(3) Short-term economy energy sales in the daily or hourly markets
at fluctuating spot market prices and other non-firm energy
sales.
(4) Sales of transmission service.
TEP also purchases power in the wholesale markets under certain
situations. It may enter into forward contracts: (a) to purchase energy
under long-term strips of energycontracts to serve retail load and long-term wholesale
contracts, (b) to purchase capacity or energy during periods of planned
outages or for peak summer load conditions, (c)
to purchase energy for trading purposes within TEP's established
limits to take advantage of favorable market conditions, and (d)(c) to purchase energy to
resell to certain wholesale customers under load and resource management
agreements. Finally, TEP may purchase energy in the daily and hourly markets
to meet higher than anticipated demands, or to cover unplanned generation
outages.
The table below shows the percentage contribution to total
wholesale revenues from each category of wholesale salesoutages, or when it is more economical than generating.
As a participant in the last
three years:
2001 2000 1999
-------------------------------------------------------------
Long-term Contracts 10% 14% 26%
Forward Contracts 63% 36% 42%
Short-term Saleswestern U.S. wholesale power markets, TEP is
directly and Other 26% 48% 29%
Transmission 1% 2% 3%
-------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------
TEP's kWh wholesale sales increasedindirectly affected by 15% in 2001 while
revenues fromchanges affecting these sales grew by 111%. This increase in sales and
revenues was mainly the result of sales of available generating
capacity, particularly in the second quarter, increased trading
activity in the forward and short-term markets and
significantly
higher market participants. In 2000 and 2001, a significant portion of TEP's
revenues and earnings resulted from its wholesale marketing activities, which
benefited from strong demand and high wholesale prices in the western U.S.
wholesale energy markets
duringThese market conditions were the first two quartersresult of 2001. These higher market prices
in the first half of 2001 made it profitable for TEP to run its gas-
fired generating units to sell into the wholesale markets.
The average market price for around-the-clock energy based on
the Dow Jones Palo Verde Index fluctuated widely in 2001. It varied
from an average of $156 per MWh in the first half of 2001 to an
average of $23 per MWh in the fourth quarter of 2001. This
reduction was due to a number of factors, including
more generation
onlinepower supply shortages, high natural gas prices, transmission, and
environmental constraints. During this period, these markets experienced
unprecedented price volatility, as well as payment defaults and bankruptcies
by several of its largest participants. Regulatory agencies became concerned
with the outcomes of deregulation of the electric power industry and
intervened in the operation of these markets by, among other things, imposing
price caps and initiating investigations into potential market manipulation.
Since mid-2001, conditions in the western U.S., lowerenergy markets have changed
significantly as a result of various regulatory actions, moderate weather, a
decrease in natural gas prices, increased
hydro supplythe addition of new generation in the region,
the slowdown of the regional economy, and weaker demand. Asthe energy crisis in California.
In addition, the presence of Februaryfewer creditworthy counterparties, as well as
legal, political and regulatory uncertainties have reduced market liquidity
and trading volume. Several companies that were large market participants
have either curtailed their activities or exited the business completely.
These factors placed downward pressure on wholesale electricity prices, and
resulted in significantly lower wholesale electricity sales and revenues at
TEP in 2002.
In the first quarter of 2003, both the natural gas and western U.S.
wholesale electricity markets have experienced some price spikes and
volatility due to severe winter weather in certain regions, as well as high
gas storage withdrawals due to lagging production. TEP cannot predict,
however, whether average wholesale electricity prices will remain higher than
in 2002 and what the average
forward around-the-clock market price for the balance of 2002 was
approximately $27 per MWh, basedimpact will be on the Dow Jones Palo Verde Index.
As a result, we expect our wholesaleTEP's sales and revenues in 2003.
TEP expects to continue to be significantly
lower in 2002 than in 2001. A large portion of our revenues in 2001
was from sales contracted at higher pricesa participant in the first half of the
year that settledwholesale energy
markets, primarily by making sales and purchases in the second half of the year. Therefore, we
continued to benefit from the higher prices in the second half of the
year even though market prices had declined. We cannot predict
whether these lower prices will continue, or whether changes in
various factors that influence demandshort-term and
capacity will cause prices
to rise again during the remainder of 2002.
We expectforward markets. TEP expects the market price and demand for capacity and
energy to continue to be influenced by the following factors, among others,
during the next few years:
- continued population growth and economic conditions in the western U.S.;
- availability of capacity throughout the western U.S.;
- the extent of electric utility industry restructuring in Arizona,
California and other western states;
- the effect of FERC regulation of wholesale energy markets;
- the availability and price of natural gas;
- precipitation, which affects hydropower availability;
- transmission constraints; and
- environmental restrictions and the cost of compliance.
Under the conditions outlined above, we expect to continue to
be an active participant in the wholesale energy markets, primarily
by making sales and purchases in the short-term and forward markets.
See Item 7. --- Management's Discussion and Analysis of Financial
Condition and Results of Operations, Factors Affecting Results of Operations,
Competition, Western Energy Markets and Market Risks, for additional
discussion of TEP's wholesale marketing activities.
GENERATING AND OTHER RESOURCES
TEP GENERATING RESOURCES
At December 31, 2001,2002, TEP owned or leased 1,9992,002 MW of net generating
capability as set forth in the following table:
Net TEP's Share
Unit Fuel Owned/ Capability Operating -----------
Generating Source No. Location Type Leased MW Agent % MW
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Springerville Station 1 Springerville, AZ Coal Leased 380 TEP 100.0 380
Springerville Station 2 Springerville, AZ Coal Owned 380 TEP 100.0 380
San Juan Station 1 Farmington, NM Coal Owned 327 PNM 50.0 164
San Juan Station 2 Farmington, NM Coal Owned 316 PNM 50.0 158
Navajo Station 1 Page, AZ Coal Owned 750 SRP 7.5 56
Navajo Station 2 Page, AZ Coal Owned 750 SRP 7.5 56
Navajo Station 3 Page, AZ Coal Owned 750 SRP 7.5 56
Four Corners Station 4 Farmington, NM Coal Owned 784 APS 7.0 55
Four Corners Station 5 Farmington, NM Coal Owned 784 APS 7.0 55
Irvington Station 1 Tucson, AZ Gas/Oil Owned 81 TEP 100.0 81
Irvington Station 2 Tucson, AZ Gas/Oil Owned 81 TEP 100.0 81
Irvington Station 3 Tucson, AZ Gas/Oil Owned 104 TEP 100.0 104
Irvington Station 4 Tucson, AZ Coal/Gas Leased 156 TEP 100.0 156
Internal Combustion
Turbines Tucson, AZ Gas/Oil Owned 122 TEP 100.0 122
Internal Combustion
TurbineTurbines Tucson, AZ Gas Owned 7595 TEP 100.0 75
Internal Combustion
Turbine95
Solar Electric Generation Springerville/
Tucson, AZ Gas Leased 20Solar Owned 3 TEP 100.0 203
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total TEP Capacity (1) 1,999
- -----------------------------------------------------------------------------------------------------2,002
====================================================================================================
(1) Excludes 217380 MW of additional resources, which consist of certain capacity purchases
and interruptible retail load. At December 31, 2001,2002, total owned capacity was 1,4431,466 MW
and leased capacity was 556536 MW.
TEP added 95 MW of new peaking resources in 2001 to improve
local system reliability in Tucson. TEP purchased a 75 MW gas
turbine and leased, from UED, the 20 MW gas turbine that UED
obtained in 2001. The generators came online in June to meet summer
peaking needs.
Springerville Station
---------------------
The Springerville Generating Station, located in northeast Arizona,
consists of two coal-fired units. Springerville Unit 1 began commercial
operation in 1985 and is leased and operated by TEP. Springerville Unit 2
started commercial operation in June 1990 and is owned by TEP's wholly-owned
subsidiary, San Carlos Resources Inc. (San Carlos), and operated by TEP.
These units are rated at 380 MW for continuous operation, but may be operated
for up to eight hours at a time at a net capacity of 400 MW each. The
Springerville Station was originally designed for four generating units. UED
is currently facilitatingevaluating opportunities to expand the construction ofSpringerville Station by
assigning the rights to construct Springerville Units 3 and 4.4 to unrelated
third parties. TEP will be the operator of the new units. See UniSource
Energy Development Company, below.
The initial terms ofSpringerville Station also includes the Springerville Unit 1 Leases, which
include a 50% interest inCoal Handling
Facilities and the Springerville Common Facilities,
expire on January 1, 2015, but have optional fair market value
renewalFacilities. In 1984, TEP sold and
purchase provisions. The annual cash cost of lease
payments forleased back the Springerville Unit 1 Leases will range from $33
million to $176 million, averaging approximately $83 million. In
2001, TEP made lease payments of $53 million.Coal Handling Facilities. In 1985, TEP sold
and leased back a 50% interest in the Springerville Common Facilities. The
initial lease term forother 50% interest is included in the Springerville Common Facilities Leases expiresUnit 1 leases.
TEP obtains approximately 600 MW, or 30%, of its generating capacity
from jointly-owned facilities at the San Juan, Four Corners, and Navajo
Generating Stations in 2017 for one owner
participantNew Mexico and in 2020 for the other two owner participants,
subject to fixed purchase price options. Annual lease payments
under these leases vary with changes in the interest rate on the
underlying debt. The average interest rate in 2001 was 8.6%. Based
on an assumed interest rate of 8.5%, annual lease payments will
range from $7 million to $20 million and average approximately $12
million. In 2001, TEP made lease payments of $18 million.
See Fuel Supply, Springerville Coal Handling Facilities, below,
for information regarding the Springerville Coal Handling Facilities
Leases.
Irvington Station
-----------------northern Arizona.
Irvington is a four-unit generating station located in Tucson, Arizona.
Units 1, 2, and 3 are gas or oil burning units. Irvington Unit 4 operates
primarily on coal in combination with natural gas or landfill gas, but it is
also able to operate solely on natural gas. In
1988,Units 1, 2, and 3 are wholly-
owned by TEP, and Unit 4 was sold and then leased back in 1988 under the Irvington
Lease. Annual lease payments range from approximately $11 million
to $14 million and average about $13 million. In 2001, TEP made
payments of $14 million. The initial lease term expires in 2011,
but the lease has optional fair market value renewal and purchase
provisions.4 lease. The Irvington Station, along with the internal combustion turbines
located in Tucson, are designated as "must-run generation" facilities. Must-runMust-
run generating units are those which are required to run in certain
circumstances in order to maintain distribution system reliability and meet local load
requirements.
To improve local system reliability in Tucson and to serve increasing
load requirements, TEP added 95 MW of new peaking resources in June 2001,
consisting of a 75 MW gas turbine it purchased and a 20 MW gas turbine leased
from UED. In September 2002, TEP purchased the 20 MW gas turbine from UED.
See Note 7 of Notes to Consolidated Financial Statements, and Item 7. -
Management's Discussion and Analysis of Financial Condition and Results of
Operations, Liquidity and Capital Resources, Contractual Obligations, for
more information regarding the Springerville and Irvington leases.
POWER EXCHANGE AGREEMENT
As part of a 1992 litigation settlement,
TEP and Southern California Edison Company (SCE) agreed tohave a ten-year power
exchange agreement. Since the agreement began in 1995, TEP has relied upon
thewhich requires SCE to provide firm system capacity of 110
MW provided under this agreement as a firm source of energy
to supply its retail loadTEP during the peak summer months. TEP is then obligated to return to SCE
in the winter months the same amount of energy that itTEP received during the
preceding summer. For example, in the summer of 2000,2002, TEP received
approximately 140,000133,000 MWh from SCE and returned the same amount during the
winter months from November 20002002 to February 2001. Except for a few occasions2003. This agreement expires in
2000
and 2001, SCE provided TEP with requested energy under the power
exchange agreement. In 2001, TEP received approximately 125,000 MWh
from SCE.
As TEP entered the summer peaking season of 2001, there was
considerable uncertainty as to the ongoing availability of the 110
MW resource because of the energy crisis in California and the
deteriorating financial condition of SCE. To mitigate the risk of
loss of this resource, TEP relied upon its two new peaking resources
that went in-service in June 2001, as well as interruptible
contracts, load shifting by large mining customers, and reserve
sharing with other utilities. Also, to ensure service reliability,
TEP purchased power under forward contracts at the beginning of
summer at prices in excess of the cost of the SCE power exchange
agreement.
Since June 2001, western power markets have stabilized and
SCE's financial condition appears to be improving. As such, we
believe that there is more certainty of the availability of this
resource for TEP in the summer of 2002. Nevertheless, TEP plans to
make forward purchases of approximately 50 MW for the summer peaking
season to mitigate the risk of loss of this or other resources.February 2005.
OTHER PURCHASES AND INTERCONNECTIONS
TEP participates in a number of interchange agreements by which
it can purchasepurchases additional electric energy from other utilities.utilities and power
marketers. The amount of energy purchased from other utilities and power
marketers varies substantially from time to
time depending on the demand for energy, the cost of purchased energy
compared with TEP's cost of generation, and the availability of such energy.
TEP may also sell electric energy at wholesale through these agreements.wholesale. See also Wholesale Business,
above and Item 7. - Management's Discussion and Analysis of Financial
Condition and Results of Operations, Factors Affecting Results of Operations,
Market Risks.
TEP has transmission access and power transaction arrangements
with over 120 electric systems or suppliers.
TEP is also a member of various regional reserve sharing, reliability
and power poolingsharing organizations. These relationships allow TEP to call upon
other utilities during emergencies such as plant outages and system
disturbances, and also reduce the amount of reserves TEP is required to
carry.
PEAK DEMAND AND RESOURCES
Peak Demand 2002 2001 2000 1999 1998
-------------------------------------
- MW -
Retail Customers-Net One Hour 1,899 1,840 1,862 1,754 1,786
Firm Sales to Other Utilities 228 151 143 178 179
---------------------------------------------------------------------------
Coincident Peak Demand (A) 2,127 1,991 2,005 1,932 1,965
Total Generating Resources 2,002 1,999 1,904 1,904 1,896
Other Resources (1) 308 217 248 235 235
---------------------------------------------------------------------------
Total TEP Resources (B) 2,310 2,216 2,152 2,139 2,131
Total Margin (B) - (A) 183 225 147 207 166
Reserve Margin (% of Coincident
Peak Demand) 9% 11% 7% 11% 8%
(1) Other Resources includes firm power purchases and interruptible retail
and wholesale loads.
---------------------------------------------------------------------------
TEP's retail sales are influenced by several factors, including seasonal
weather patterns, competitive conditions and the overall economic climate.
The peak demand for TEP's retail service area occurs during the summer months
due to the cooling requirements of its retail customers. TEP's retail peak
demand has grown at an average annual rate of approximately 2.7% during the
past five years.
The chart above shows the relationship over a five-year period between
TEP's peak demand and its energy resources. TEP's margin is the difference
between total energy resources and coincident peak demand, and the reserve
margin is the ratio of margin to coincident peak demand. TEP maintains a
minimum reserve margin in excess of 7% to comply with reliability criteria
set forth by the Western Electricity Coordinating Council (WECC), (formerly
the Western Systems Coordinating Council). TEP's actual reserve margin in
2002 was 9%. In January 2001,2002, TEP purchased 50 MW of firm capacity and Citizens Communications Company
(Citizens) entered into a project development agreementenergy in the
forward energy markets during the summer peak period to ensure an adequate
reserve margin.
TEP's forecasted retail peak demand for 2003 is approximately 1,950 MW,
compared with actual peak demand of 1,899 MW in 2002. Except for certain
peak hours during the construction of a transmission line from Tucsonsummer peak period, TEP believes it has sufficient
resources to Nogales, Arizona.
In January 2002, the ACC approved construction of the line.
Applications for Department of Energy permits to cross national
forest service land are pending.meet this expected demand in 2003 with its existing resources.
TEP plans to begin constructionmake forward purchases to ensure adequate supply during its
summer peak period. Beginning in early 2003, any future resource needs are
expected to be procured through a competitive bidding process being
established by the first quarterACC.
See Future Generating Resources--TEP, and Item 7. - Management's
Discussion and Analysis of 2003. This project, when completed, will meet
oneFinancial Condition and Results of Citizen's service reliability requirements mandated by the
ACC following repeated outages in their system. TEP has also
applied for a Presidential Permit to interconnect with Mexico, which
could improve TEP's system reliability and provide increased
transmission revenues for TEP.
See Rates and Regulation, Transmission Access, below, for a
discussionOperations,
Factors Affecting Results of possible changesOperations, Recent Developments in the operation and oversight of
TEP's transmission facilities.Arizona
Regulatory Environment, below.
FUTURE GENERATING RESOURCES -- TEP
In the past, TEP assessed its need for future generating resources based
on the premise of a continued regulatory requirement to serve customers in
TEP's retail service area. However, the ACC's electric competition rules, as
currently in effect, modified the obligation to provide generation services
to all customers. These rules and TEP's ability to retain and attract
customers will affect the need for future resources. For those customers who
do not choose other energy providers, TEP remains obligated to supply energy.
However, TEP is not obligated to supply this energy from TEP-owned generating
assets. The energy may be acquired by purchasing in the wholesale markets.
See Rates and Regulation, TEP's Settlement Agreement and Retail Electric Competition Rules,
below and Item 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations, Factors Affecting
Results of Operations, Competition.
TEP will continue to add peaking resources in the Tucson area as needed
based upon our forecasts of retail and firm wholesale load. Forload, as well as the
longer term,statewide transmission infrastructure. TEP currently forecasts that new
peaking resources of 75 MW may be needed in both 2008 and 2010. To
facilitate the proposed expansion of the Springerville Generating Station,
TEP is also considering enteringplanning to enter into a power purchase contract for up to 100 MW
of the generationcapacity from the proposed addition of UnitsUnit 3 and 4 at Springerville under
development by UED. This contract would be for up to five years, beginning
with commercial operation of Unit 3, expected in 2006. TEP anticipates that
any power purchased by it under such a contract will be sold in the wholesale
markets. TEP could not use Springerville Unit 3 power to serve its retail
load without complying with the competitive bidding procedures being
established by the ACC. See UniSource Energy Development Company, below.below and
Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations, Factors Affecting Results of Operations, Industry
Restructuring.
FUEL SUPPLY
TEP's principal fuel for electric generation is low-sulfur coal. Fuel
information is provided below:
Average Cost Per MMBTU Consumed Percentage of Total BTU Consumed
2002 2001 2000 2002 2001 2000
- ---------------------------------------------------------------------------------
Coal (A) $1.59 $1.63 $1.61 94% 90% 91%
Gas 4.28 5.99 5.70 6 10 9
- ---------------------------------------------------------------------------------
All Fuels $1.76 $2.08 $1.95 100% 100% 100%
(A) The average cost per ton of coal for 2002, 2001, and 2000 was $30.86
$30.96, and $30.69, respectively.
TEP'S COAL SUPPLY
Year Average
Contract Sulfur
Station Coal Supplier Terminates Content Coal Obtained From (A)
------- ------------- ---------- ------- ------------------------------
Springerville Peabody Coalsales Company 2010 0.9% Lee Ranch Coal Company
Four Corners BHP Billiton 2004 (B) 0.8% Navajo Indian Tribe
San Juan San Juan Coal Company 2017 0.8% Federal and State Agencies
Navajo Peabody Coalsales Company 2011 0.6% Navajo and Hopi Indian Tribes
Irvington Various approved suppliers - - Various locations
(A) Substantially all of the suppliers' mining leases extend at least as long as coal
is being mined in economic quantities.
(B) Contract is under negotiation to be extended through 2016.
TEP Operated Generating Facilities
----------------------------------
TEP is the sole owner (or lessee) and operator of the Springerville and
Irvington Generating Stations. The coal supplies for these plants are
transported from northwestern New Mexico and Colorado by railroad.
The coal supply contract for the Springerville Generating Station ends
in June 2010, with an option to extend the term for another ten years. The
Springerville contract has an adjustment clause that will affect the future
cost of coal delivered. We expect coal reserves to be sufficient to supply
the estimated requirements of Springerville for its presently estimated
remaining life. The Springerville coal contract requires TEP to take 1.9
million tons of coal per year through June 2010 at an estimated annual cost
of $45 million for the next five years and requires TEP to pay a take-or-pay
charge if minimum quantities of coal are not purchased. TEP's present fuel
requirements are in excess of the take-or-pay minimums. The Springerville
rail contract expires in 2009. This contract requires TEP to transport 1.9
million tons of coal per year through 2009 at an estimated annual cost of $13
million for the next five years.
In July 2002, TEP terminated the long-term coal supply contract for the
Irvington station. TEP incurred a pre-tax charge of $11.3 million related to
the cost of terminating this contract. The termination fee relieves TEP of
up to $3.5 million in annual pre-tax take-or-pay payments. TEP is currently
purchasing coal for Irvington under short-term contracts to take advantage of
favorable price opportunities. At this time, there is no concern for future
coal availability for the life of this station. While the Irvington coal
supply contract was terminated, the rail contract for the Irvington station
is in effect until the earlier of 2015 or the remaining life of Unit 4. The
rail contract requires TEP to transport at least 75,000 tons of coal per year
through 2015 at an estimated annual cost of $1.5 million or to make a minimum
payment of $0.5 million for the next five years if coal deliveries are not
chosen. See Note 10 of Notes to Consolidated Financial Statements -
Commitments and Contingencies, TEP Commitments, Fuel Purchase and
Transportation Commitments.
Generating Facilities Operated by Others
----------------------------------------
TEP also participates in jointly-owned generating facilities at Four
Corners, Navajo and San Juan, where coal supplies are under long-term
contracts administered by the operating agents. The coal contract for Four
Corners terminates in 2004 unless extended pursuant to its terms. The Four
Corners contract is under negotiation and is expected to be extended through
July 1, 2016. The coal quantities under contract for the Navajo and San Juan
mine-mouth coal-fired generating stations are expected to be sufficient for
the remaining lives of the stations.
The contracts to purchase coal for use at the jointly-owned facilities
require TEP to purchase minimum amounts of coal at an estimated average
annual cost of $16 million for the next five years.
NATURAL GAS
TEP purchases natural gas from Southwest Gas Corporation (SWG) for its
natural gas-fired facilities. TEP is a retail customer of SWG under a
special procurement agreement. In 2001, TEP entered into a new five-year
agreement that provides for all of TEP's natural gas commodity and
transportation needs for use in power generation. SWG purchases gas at TEP's
direction at spot or forward market prices. The first two and one-half years
of the contract, through October 31, 2003, as extended, require that TEP take
a minimum of 10 million MMBtus annually at transportation rates established
in the contract. Minimum gas transportation costs for 2003 are expected to
be $6 million. SWG is affected by recent FERC actions relating to its gas
allocations from the Permian and San Juan basins. A FERC order on this issue
is expected in the summer of 2003. At that time, TEP and SWG will
renegotiate the terms of the special procurement agreement. TEP does not
anticipate any material difference in operational or economic terms in the
new agreement, which is estimated to begin November 1, 2003. Actual gas
commodity costs will depend on the volumes purchased and the market prices.
During 2002, TEP received natural gas sufficient to meet all of its needs.
During 2002, natural gas supplied approximately 6% of TEP's generation.
TEP's gas usage was significantly higher in 2000 and 2001 because of: (1)
higher wholesale energy prices in the western U.S. in the second half of 2000
and the first half of 2001, which made it profitable for TEP to sell gas-
generated energy into the wholesale markets, and (2) the addition of the two
new gas turbines in 2001, providing 95 MW in new generating capacity. TEP
also burns small amounts of landfill gas at Irvington Unit 4.
WATER SUPPLY
TEP believes there will be sufficient water to supply the requirements
of TEP's existing and planned electric generating stations in Arizona.
However, drought conditions in the Four Corners region, combined with water
usage in upper New Mexico, have resulted in decreasing water levels in the
lake that indirectly supplies water to the San Juan and Four Corners
generating stations located in New Mexico. The U.S. Bureau of Reclamation
projects that, based on historical factors and seasonal usage, there should
be adequate capacity in the lake for all water users. The projected water
levels are not expected to affect the operations of the generating stations
in 2003.
TRANSMISSION ACCESS
TEP has transmission access and power transaction arrangements with over
120 electric systems or suppliers. In January 2001, TEP and Citizens entered
into a project development agreement for the joint construction of a 62-mile
transmission line from Tucson to Nogales, Arizona. In January 2002, the ACC
approved the location and construction of the proposed 345 kV line, almost
half of which runs through a national forest. A drought-caused closure of
the forest in June 2002 has delayed the progress on the environmental impact
study required for Federal project approval. A U.S. Department of Energy
(DOE) and Forest Service decision is expected to occur by the end of 2003.
Construction could begin as early as mid-2004 with an expected in-service
date eight months after the start of construction. Construction costs are
expected to be approximately $75 million. In 2000, TEP applied to the DOE
for a Presidential Permit to allow extension of the line across the
international border with Mexico to connect with Mexico's utility system,
providing further reliability and market opportunities in the region.
In 1997, TEP and other transmission owners and users located in the
southwestern U.S. began to investigate the feasibility of forming an
Independent System Operator (ISO) for the region. In December 1999, the FERC
issued FERC Order 2000, which established timelines for all transmission
owning entities to join a Regional Transmission Organization (RTO) and
defined the minimum characteristics and functions of an RTO. TEP and three
other southwestern utilities filed agreements and operating protocols with
the FERC in October 2001 to form a new, for-profit RTO to be known as
WestConnect RTO, LLC (WestConnect).
WestConnect will be responsible for security, reservations, scheduling,
transmission expansion and planning, and congestion management for the
regional transmission system. It will also focus on ensuring reliability,
nondiscriminatory open-access, and independent governance. Regional
transmission owners would have the option, but not be required, to transfer
ownership of transmission assets to the RTO. At present, TEP intends to turn
over only operating control of its transmission assets to the RTO.
Additionally, the RTO may build new transmission lines in the region, which
would be owned by the RTO.
In October, 2002, the FERC issued a provisional order approving, in
part, the WestConnect RTO proposal. The FERC also required WestConnect,
along with the other two RTOs in the western region (the California
Independent System Operator (CISO) and RTO West), to participate in a
steering group to encourage the development of a seamless wholesale electric
energy market. WestConnect's operation is dependent on the resolution of
these issues and is also subject to approval by state regulatory agencies in
the region. WestConnect is not expected to become operational prior to 2005.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR)
proposing standard market design rules that would significantly alter the
markets for wholesale electricity and transmission and ancillary services in
the U.S. The new rules would establish a generation adequacy requirement for
"load-serving entities" and a standard platform for the sale of electricity
and transmission services. Under the new rules, Independent Transmission
Providers would administer spot markets for wholesale power, ancillary
services and transmission congestion rights, and electric utilities,
including TEP, would be required to transfer control over transmission
facilities to the applicable Independent Transmission Provider. The FERC
expects to release for comments a white paper on the standard market design
in April 2003, followed in July 2003 by final rules. Once the final rules
are issued, a phased compliance schedule will begin. TEP is currently in the
process of determining the impact the proposed rules would have on its
operations.
RATES AND REGULATION
GENERAL
The FERC and the ACC regulate portions of TEP's utility accounting
practices and electricity rates. The FERC regulates the terms and prices of
TEP's sales to other utilities and resellers. In 1997, TEP was granted a
FERC tariff to sell power at market based rates. The ACC has authority over certain
rates charged to retail customers, the issuance of securities, and
transactions with affiliated parties.
The ACC currently consists of three commissioners; however, in
the November 2000 general election, the voters of Arizona approved
an amendment to the Arizona Constitution, expanding the membership
to five members. In addition, the amendment expanded the term of
office from a single six-year term to up to two terms of four years.
The election for the two new members will take place in 2002 and
their first term will be a two-year term beginning in January 2003.
Thereafter, they will serve four-year terms. The present
commissioners are:
- William A. Mundell (Republican), who started his term in 1999
and was elected Chairman in 2001. His term expires in 2004.
- Jim Irvin (Republican), who started his term in 1997. His term
expires in 2002.
- Marc Spitzer (Republican), who started his term in 2001. His
term expires in 2006.STATE
Historically, the ACC determined TEP's rates for retail sales of
electric energy on a "cost of service" basis, which was designed to provide,
after recovery of allowable operating expenses, an opportunity to earn a
reasonable rate of return on "fair value rate base." Fair value rate base
was generally determined by reference to the original cost and the
reproductionreconstruction cost (net of depreciation) of utility plant in service to the
extent deemed used and useful, and to various adjustments for deferred taxes
and other items, plus a working capital component. Over time, rate base was
increased by additions to utility plant in service and reduced by
depreciation and retirements of utility plant.
WithIn September 1999, the ACC approved the Retail Electric Competition
Rules (Rules) that provided a framework for the introduction of retail
electric competition in TEP's
service territoryArizona. In November 1999, the ACC approved the
Settlement Agreement between TEP and certain customer groups related to the
implementation of retail electric competition in 2000, theArizona.
The Rules and TEP's Settlement Agreement required the unbundling of
electric services, with separate rates or prices for generation,
transmission, distribution, metering, meter reading, billing and collection,
and ancillary services. Generation services at market prices may be provided
by Energy Service Providers (ESPs) licensed by the ACC. Transmission and
distribution services and must-run generation facilities will remain subject
to regulation on a cost of service basis. TEP has met all conditions
required by the ACC to facilitate electric retail competition, including ACC
approval of TEP's direct access tariffs. However, ESPs and their related
service providers must meet certain conditions before they can competitively
sell electricity in TEP's service territory. Examples of these conditions
include ACC certification of ESPs and completion of direct access service
agreements with TEP.
In general, rates for wholesale power sales and transmission
services may not exceed rates determined on a cost of service basis.
In the fall of 1997, TEP was granted a tariff to sell at market
based rates. The FERC has historically set rates in formal rate
application proceedings. With respect to wholesale power sold
during 1998 and 1999, TEP's wholesale rates were generally
substantially below rates determined on a fully allocated cost of
service basis, but, in all instances, rates exceeded the level
necessary to recover fuel and other variable costs. During 2000 and
2001, rates earned on wholesale sales in the short-term market,
including forward sales, sometimes equaled or exceeded rates
determined on a fully allocated cost of service basis. Wholesale
sales on long-term contracts entered into prior to 1998 continued to
be at rates below fully allocated costs, but recovered the cost of
fuel and other variable costs.
TEP'S SETTLEMENT AGREEMENT AND RETAIL ELECTRIC COMPETITION RULES
In December 1996, the ACC adopted the Retail Electric
Competition Rules (Rules) that provided a framework for the
introduction of retail electric competition in Arizona. These
Rules, as amended and modified, were approved by the ACC in
September 1999.
In November 1999, the ACC approved the Settlement Agreement
between TEP and certain customer groups relating to the
implementation of retail electric competition, including TEP's
recovery of its transition recovery assets and the unbundling of
tariffs. The major provisions of the Settlement Agreement, as
approved, were:
- Consumer choice for energy supply began in 2000, and by January
1, 2001 consumer choice was available to all retail customers.
- In accordance with the Rate Settlement approved by the ACC in
1998, TEP decreased rates to retail customers by 1.1% on July 1,
1998, 1% on July 1, 1999, and 1% on July 1, 2000. These reductions
applied to all retail customers except for certain customers that
have negotiated non-standard rates. The Settlement Agreement provides that,also provided for certain retail rate
reductions from 1998 through 2000, after these reductions,which TEP's retail rates are frozen
until December 31, 2008, except under certain circumstances. These
include the impact of (a) termination of the Fixed Competitive
Transition Charge component of retail rates as a result of the early
collection of $450 million of transition recovery assets; and (b)
changes in transmission charges dueTEP is required
to regional transmission
organizations or emergencies. The costs of transmission and
distribution would be recovered under regulated unbundled rates both
during and after the rate freeze.
- TEP's frozen rates include two Competition Transition Charge
(CTC) components designated for the recovery of its transition
recovery assets.
- A Fixed CTC component that equals a fixed charge per
kilowatt-hour sold. It ends when $450 million has been
recovered, or on December 31, 2008, whichever occurs first.
When the Fixed CTC terminates, TEP's retail rates will
decreasefile by the Fixed CTC amount.
- A Floating CTC component that equals the amount of the
frozen retail rate less the price of retail electric
service. The price of retail electric service includes
TEP's transmission and distribution charge and a market
energy component based on a market index for electric
energy. Because TEP's total retail rate will be frozen, the
Floating CTC is expected to allow TEP to recoup the balance
of transition recovery assets not otherwise recovered
through the Fixed CTC. The Floating CTC will end no later
than December 31, 2008.
- By June 1, 2004 TEP will be required to file a general rate case, for its transmission and distribution business, including an updated cost-of-servicecost of
service study. Any rate change resulting from this rate case would be
effective no sooner than June 1, 2005, and would not result in a net rate
increase.
- The Settlement Agreement currently requires TEP to transfer its
generation and other competitive assets to a wholly-owned subsidiary
by December 31, 2002. TEP's generation subsidiary will sell energy
into the wholesale market. TEP, as a utility distribution company
(UDC), would acquire energy in the wholesale market for its retail
customer energy requirements. The Settlement Agreement also
requires that by December 31, 2002, the UDC must acquire at least
50% of its requirements through a competitive bidding process, while
the remainder may be purchased under contracts with TEP's generation
subsidiary or another supplier. The amounts the UDC acquires
through competitive bids may be purchased under bilateral contracts
or spot market purchases with third parties, or potentially with
TEP's generation subsidiary. With frozen rates through 2008, TEP as
the UDC will bear the risk of any increases in energy costs.
However, TEP believes that any such cost increases will generally be
offset by sales of energy by its generation subsidiary.
Approval of the Settlement Agreement caused TEP to discontinue
regulatory accounting for its generation operations using FAS 71 in
November 1999. See Note 2 of Notes to Consolidated Financial Statements--Regulatory Matters.
RECENT DEVELOPMENTS IN THE ARIZONA REGULATORY ENVIRONMENTStatements - Regulatory
Matters, for more information on TEP's Settlement Agreement.
In JanuaryOctober 2002, UniSource Energy entered into two Asset Purchase
Agreements with Citizens for the ACC beganpurchase by UniSource Energy of Citizens'
Arizona electric utility and gas utility businesses for a total of $230
million. The purchase price of each is subject to formally reexamine
circumstances that have changed sinceadjustment based on the
Rules were adopteddate on which the transaction is closed and, in 1996each case, on the amount of
certain assets and to revisit the path to deregulationliabilities of the retail electric
market.purchased business at the time of
closing. The ACC sent questions related to retail competition to
stakeholders, requesting comments by February 25, 2002. At the
current time, the outcomeclosing of this proceedingthese transactions is uncertain.
On January 28, 2002, TEP filed a request with the ACC for an
extension of the generation assets transfer requirement and the 50%
competitive bid requirement of its Settlement Agreement until the
latter of December 31, 2003 or six months after the ACC has issued a
final order in the current docket pertaining to electric
restructuring issues. TEP's filing was consolidated with the
generic docket and a procedural conference began on March 4, 2002.
STATE AND FEDERAL LEGISLATION
In 2001, federal and state legislative interest focused on the
California energy crisis. Federal legislators introduced several
pieces of legislation, but by year-end all momentum had been
refocused on national security issues. In 2002, Congress will
likely focus on administrative controls and oversight of the energy
industry as a result of the Enron Corp. (Enron) bankruptcy filing in
December 2001.
The Arizona State legislature was also concerned with the
State's preparedness to meet growing electric demand. The siting
and construction of new generation and transmission facilities is
ongoing and closely monitored by the legislature. The 2002
legislature is expected to review legislation to modify the
valuation of power plants for property tax purposes.
TRANSMISSION ACCESS
In 1997, TEP and other transmission owners and users located in
the southwestern U.S. began to investigate the feasibility of
forming an Independent System Operator (ISO) for the region. As a
result, they formed a non-profit corporation named Desert STAR in
September 1999. In December 1999, the FERC issued FERC Order 2000,
which established timelines for all transmission owning entities to
join a Regional Transmission Organization (RTO) and defined the
minimum characteristics and functions of an RTO.
TEP and three other southwestern utilities filed agreements and
operating protocols with the FERC in October 2001 to form a new, for-
profit RTO to be known as WestConnect RTO, LLC (WestConnect) to
replace Desert STAR, which was still under development and had not
commenced operations. WestConnect is based primarily on policies
and procedures developed for Desert STAR. It will be responsible
for security, reservations, scheduling, transmission expansion and
planning, and congestion management for the regional transmission
system. It will also focus on ensuring reliability, nondiscriminatory
open-access, and independent governance. Regional transmission
owners would have the option, but not be required, to transfer
ownership of transmission assets to the RTO. At present, TEP
intends to turn over only operating control of its transmission
assets to the RTO. Additionally, the RTO may build new transmission
lines in the region, which would be owned by the RTO. Assuming the
required regulatory approvals are obtained in a timely fashion,
WestConnect is projected to begin operation in early 2004. The
reorganization of Desert STAR into WestConnect will be subject to approval by the
ACC, the FERC and certain state regulatory authoritiesthe SEC. Citizens had two cases pending before the ACC
requesting rate relief for both the Arizona electric and Arizona gas assets
prior to entering into the Asset Purchase Agreements with UniSource Energy.
The requested electric rate increase is to recover purchased power costs
and the gas rate increase is a base rate increase. In December 2002,
UniSource Energy and Citizens filed a Joint Application with the ACC
requesting smaller increases in both pending cases. Under the region.
The ACC Retail Electric Competition Rules also requiredproposal,
UniSource Energy asked that the formation45% electric increase requested by
Citizens be reduced to 22%, and implementation of an Arizona Independent Scheduling
Administrator (AISA)that the 29% increase in gas rates be reduced
to 23%. The purposeUniSource Energy believes that the smaller proposed rate increases
are sufficient in light of the AISA, a not-for-profit
entity, is to oversee the application of operating protocols to
ensure statewide consistency for transmission access. The AISA is
anticipated to be a temporary organization until the formation of an
ISO or RTO. TEP participatednegotiated purchase price. We are currently
in the creation of the AISA and the
compliance filing at the FERC for approval of its rates and procedures
for operation. TEP continues to participatesettlement discussions with the other affected
utilities in developing the AISA's structureACC Staff and protocols in response
to retail competition.
In July 2001, the ACC Commissioners provided stakeholders the
opportunity to comment on a list of issues related to the AISA.
Among the issues discussed was a proposal by one of the Commissioners
to end the obligation of Arizona utilities to fund and participate
in the AISA, claiming the AISA had fulfilled its obligation to develop
transmission operating protocols. The AISA docket is one of those
that was consolidated with the generic docket related to retail
electric competition issues. See Recent Developments in the Arizona
Regulatory Environment, above.intervenors regarding this
Joint Application. See Item 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations, Tax Exempt Local Furnishing
Bonds for a discussion ofAsset Purchase Agreements.
FEDERAL
During 2000 and 2001, the possible effect of the establishment
of an RTO, ISO and/or an AISA on TEP's capital structureFERC ordered hearings and refinancing
requirements.
WESTERN ENERGY MARKETS
As a participantissued several
orders to mitigate volatile energy prices in the western U.S. wholesale power markets,
TEP is directly and indirectly affected by changes to these markets
and market participants. During 2000 and 2001, these markets
experienced unprecedented price volatility, bankruptcies and payment
defaults by several of its largest participants, and increased
attention and intervention by regulatory agencies concerned withaddress
the outcomes of deregulation of the electric power industry.
In early 2001, California's two largest utilities, SCE and
Pacific Gas and Electric Company (PG&E), defaulted on payment
obligations owed to various energy sellers, including the California
Power Exchange (CPX) and the California Independent System Operator
(CISO). The CPX and CISO defaulted on their payment obligations to
market participants including TEP. PG&E and CPX filed for
protection under Chapter 11 of the U.S. Bankruptcy Code. SCE has
remained out of bankruptcy butemergency in a weakened financial condition.
SCE has publicly disclosed that on March 1, 2002, SCE obtained financing
and made payments so that they have no material undisputed obligations
that are past due or in default. These payments included a payment to
the CPX. However, TEP did not correspondingly receive a payment from
the CPX. PG&E has filed a plan of reorganization which provides for
payment of its creditors on or around January 1, 2003. The plan requires
various approvals and numerous parties have expressed opposition to
the plan.
On December 2, 2001, Enron and certain of its affiliates filed
for protection under Chapter 11 of the U.S. Bankruptcy Code. At the
time of the bankruptcy filing, TEP had an outstanding receivable
of $0.8 million from Enron for power delivered in November 2001, as
well as certain forward contracts for the delivery of power through
June 2002. The bankruptcy filing constituted an event of default
under TEP's contracts with Enron. Therefore, TEP suspended all trading
activities and terminated all contracts with Enron. See Note 11 of
Notes to Consolidated Financial Statements - Wholesale Accounts
Receivable and Allowances.
See also Item 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations, Competition and
Western Energy Markets for additional discussion of the effect of
the California energy crisis on TEP's operations.
FERC MATTERSCalifornia. During 2000, the FERC established
certain soft caps on prices for power sold to the CISO. Also in December 2000, the Secretary of
Energy issued an order designed to address the electric emergency in
California. The order required that entities, including TEP, "sell
electricity to the California ISO that is available in excess of
electricity needed by each entity to render service to its firm
customers." This order was allowed to expire on February 7, 2001.
OnIn June 19, 2001, the
FERC issued an order adoptingadopted a price mitigation plan applicable to certain wholesale power
sales in California and throughout the western U.S. during the period June
20, 2001 through September 30,This plan, which had a price cap of $91.87 per
MWh, was in effect until October 31, 2002. This order applies to spot
market (day-ahead and hour-ahead) transactions in the western U.S.
when operating reserves fall below 7.5% in California and the CISO
callsThe FERC adopted a Stage 1 alert. The market price is then capped at the
operating cost of the highest cost unit in operation during the
Stage 1 alert. The price during non-Stage 1 alert periods is based
on 85% of the price established during the most recent Stage 1
alert. Sellers that do not wish to establish rates on the basis of
this price mitigation plan may propose cost-of-service rates
covering all of their generating units in the WSCC for the duration
of the mitigation plan.
On June 25, 2001, a FERC administrative law judge (ALJ)
convened a conference to negotiate a voluntary settlement between
California and numerous power generators, including TEP. California
claims that it was overcharged up to $9 billion for wholesale power
purchases since May 2000, and is seeking refunds. Representatives
from over 100 parties and participants in the western power market,
including the state of California and power generators, negotiated
for two weeks but failed to reach an agreement. On July 25, 2001,
the FERC ordered hearings to determine refunds/offsets applicable to
wholesale sales into the CISO's spot marketscap for
the period from
October 2, 2000 to June 20, 2001. The order established the
methodology that will be used to calculate the amountthereafter of refunds.
The FERC methodology specified that the price-mitigation formula
contained in its June 19, 2001 order be applied to the period from
October 2, 2000 to June 20, 2001. This methodology will likely
result in refunds substantially lower than the $9 billion claimed by
California.
On December 19, 2001, the FERC issued an order that modified
certain limited aspects of the FERC's prior rulings regarding
refunds/offsets applicable to wholesale sales into the CISO's spot
markets for the period October 2, 2000 to June 20, 2001. In
particular, the FERC ruled that load-serving entities (as well as
generators and hydroelectric units) selling in the CISO and CPX spot
markets may submit evidence that the refund methodology results in a
total revenue shortfall for their transactions. The FERC stated
that this finding applies during the refund period, and shall be
addressed after the refund hearing before the ALJ is concluded.
In a separate order issued on December 19, 2001, the FERC
altered the price mitigation methodology applicable to certain
wholesale power sales in California and throughout the western U.S.
during the upcoming winter season. The change, which extends from
the date of this order through April 30, 2002, is triggered when the
average of three gas indices increases 10 percent from the level
last used to calculate the mitigated price.
We are not able to predict the length and outcome of the FERC
hearings and the outcome of any subsequent lawsuits and appeals that
might be filed. As a participant in the June 2001 refund
proceedings, TEP will be subject to any final refund orders. TEP
does not expect its refund liability, if any, to have a significant
impact on the financial statements.$250 per MWh.
See Item 77. - Management's Discussion and Analysis of Financial
Condition and Results of Operation, Critical Accounting Policies - Payment Defaults and
AllowancesOperations, Factors Affecting Results of
Operations, Western Energy Markets, for Doubtful Accounts.
There are several other outstanding legal issues, complaints,
and lawsuits concerning thea discussion of various FERC
proceedings, including refund hearings on power sold to California energy crisis related to the
FERC, wholesale power suppliers, SCE, PG&E, the CPX and CISO, and to
Enron. We cannot predict the outcome of these issues or lawsuits.
We believe, however, that we are adequately reserved for our
transactions with the CPX, CISO and Enron. See Note 11 of Notes to
Consolidated Financial Statements - Wholesale Accounts Receivable
and Allowances.
FUEL SUPPLY
TEP's principal fuel for electric generation is low-sulfur
coal. Fuel cost information is provided below:
Cost Per Million BTU Consumed Percentage of Total BTU Consumed
2001 2000 1999 2001 2000 1999
- --------------------------------------------------------------------------------
Coal (A) $1.63 $1.61 $1.64 90% 91% 95%
Gas 5.99 5.70 2.94 10 9 5
- --------------------------------------------------------------------------------
All Fuels $2.08 $1.95 $1.71 100% 100% 100%
- --------------------------------------------------------------------------------
(A) The average cost per ton of coal for each of the last three years
(2001, 2000, and 1999) was $30.96, $30.69, $31.23, respectively.
TEP'S COAL CONTRACTS
Year Average
Contract Sulfur
Station Coal Supplier Terminates Content Coal Obtained From (A)
------- ------------- ---------- ------- -------------------------------
Four Corners BHP Billiton 2004 0.8% Navajo Indian Tribe
San Juan San Juan Coal Company 2017 0.8% Federal and State Agencies
Navajo Peabody Coalsales Company 2011 0.6% Navajo and Hopi Indian Tribes
Springerville Peabody Coalsales Company 2010 0.8% Lee Ranch Coal Company
Irvington The Pittsburg & Midway Coal 2015 0.5% Navajo Indian Tribe and Federal
Mining Company and State Agencies
- --------------------------------------------------------------
(A) Substantially all of the suppliers' leases extend at least as long as coal
is being mined in economic quantities.
TEP Operated Generating Facilities
----------------------------------
TEP is the sole owner (or lessee) and operator of the
Springerville and Irvington Generating Stations. The coal supplies
for these plants are transported from northwestern New Mexico and
Colorado by railroad.
The coal supply contract for the Springerville Generating
Station ends in 2010, with an option to extend the term for another
ten years. The Springerville rail contract expires in 2009. The
coal supply and rail contracts termination date for the Irvington
station is the earlier of 2015 or the remaining life of Unit 4.
The Springerville and Irvington contracts have various
adjustment clauses that will affect the future cost of coal
delivered. We expect coal reserves to be sufficient to supply the
estimated requirements of Springerville and Irvington for their
presently estimated remaining lives.
The Springerville and Irvington coal contracts combined require
TEP to take 2.1 million tons of coal per year through 2009 at an
estimated annual cost of $50 million for the next five years. The
Springerville and Irvington rail contracts combined require TEP to
transport 1.9 million tons of coal per year through 2015 at an
estimated cost of $13 million for the next five years. The coal
supply contracts require TEP to pay a take-or-pay charge if minimum
quantities of coal are not purchased. TEP's present fuel
requirements are in excess of the take-or-pay minimums. However,
TEP has purchased coal and natural gas in the spot market, and
switches fuel burn from one generating station to another in order
to reduce overall fuel costs, despite incurring take-or-pay minimum
charges. TEP incurred take-or-pay charges of $3 million in 2001 and
$4 million in 2000 and 1999. See Note 10 of Notes to Consolidated
Financial Statements - Commitments and Contingencies and TEP
Commitments - Fuel Purchase and Transportation Commitments.
Generating Facilities Operated by Others
----------------------------------------
TEP also participates in jointly-owned generating facilities at
Four Corners, Navajo and San Juan, where coal supplies are under
long-term contracts entered into by the operating agents. The coal
contract for Four Corners terminates in 2004. The coal quantities
under contract for the Navajo mine-mouth coal-fired generating
station are expected to be sufficient for the remaining life of the
station.
The mine supplying coal to San Juan will phase out the current
surface mining operation and replace it with an underground mining
operation to be in full production by November 2002. The
underground mine will provide higher quality coal to San Juan and
reduce production costs.
The contracts to purchase coal, including rail transportation,
for use at the jointly-owned facilities require TEP to purchase coal
at an estimated average annual cost of $18 million for the next five
years.
SPRINGERVILLE COAL HANDLING FACILITIES
TEP is the lessee of the coal-handling facilities at
Springerville under a capital lease. The Springerville Coal
Handling Facilities Leases have a remaining initial lease term
through 2015 with fixed price purchase options. Annual rental
payments range from approximately $10 million to $28 million but
average $19 million. In 2001, TEP made rental payments of $19
million. In December 2001, TEP purchased a 13% ownership interest
in the Springerville Coal Handling Facilities Leases for $13
million. In a related transaction, in January 2002, TEP purchased
all $96 million of the capital lease debt related to the Coal
Handling Facilities Leases. In the first quarter of 2002, TEP
intends to cancel that portion of the leases related to its
ownership interest, as it now holds both the ownership interest and
the debt.
NATURAL GAS
TEP purchases natural gas to power generation from Southwest
Gas Corporation (SWG). TEP is a retail customer of SWG under a
special procurement agreement. In 2001, TEP entered into a new five-
year agreement that provides for all of TEP's natural gas commodity
and transportation needs for use in power generation. SWG purchases
gas at TEP's direction at spot or forward market prices. The first
two years of the contract, through June 1, 2003, require that TEP
take a minimum of 10 million MMBtus annually at transportation rates
established in the contract. Minimum gas transportation costs for
2002 and 2003 (through June 1) are expected to be $6 million and $2
million, respectively. Actual gas commodity costs will depend on
the volumes purchased and the market prices. During 2001, TEP
received natural gas sufficient to meet all of its needs. TEP's gas
usage was significantly higher in
2000 and 2001, than in previous
years because of: (1) higher wholesale energy prices in the western
U.S. in the second half of 2000 and the first half of 2001, which made it profitable for TEP to sell gas-generated energy into the
wholesale markets, and (2) the addition of the two new gas turbines
in 2001, providing 95 MW in new generating capacity. TEP also burns
small amounts of landfill gas at Irvington Unit 4.
WATER SUPPLY
TEP believes there will be sufficient water to supply the
requirements of existing and planned electric generating stations in
which TEP has an interest for their estimated lives except for San
Juan. A federal contract for water at San Juan expires in 2005.
Public Service Company of New Mexico (PNM), as operating agent of
San Juan, has entered into a contract which would begin at the
conclusion of the current federal contract and terminates December
31, 2027. The contract is subject to various federal and
environmental approvals that are pending.may impact TEP's results.
TEP's UTILITY OPERATING STATISTICS
For Years Ended December 31,
2002 2001 2000 1999 1998 1997
- -------------------------------------------------------------------------------------------------------
Generation and Purchased Power-kWh (000)
Remote Generation (Coal) 10,067,069 10,362,211 10,278,393 10,000,401 10,002,250
9,694,152
Local Tucson Generation (Oil, Gas & Coal) 1,402,504 1,820,783 1,667,308 1,115,277 720,515
806,819
Purchased Power 4,052,6741,842,739 3,656,978 3,174,244 2,712,570 2,227,773 1,222,970
- -------------------------------------------------------------------------------------------------------
Total Generation and Purchased Power 16,235,66813,312,312 15,839,972 15,119,945 13,828,248 12,950,538 11,723,941
Less Losses and Company Use 769,101 846,287 724,677 814,945 810,117 824,072
- -------------------------------------------------------------------------------------------------------
Total Energy Sold 15,389,38112,543,211 14,993,685 14,395,268 13,013,303 12,140,421 10,899,869
=======================================================================================================
Sales-kWh (000)
Residential 3,188,726 3,122,332 3,027,963 2,736,837 2,662,598
2,608,515
Commercial 1,609,367 1,573,213 1,496,558 1,383,756 1,355,319
1,316,360
Industrial 2,261,463 2,270,446 2,262,212 2,220,900 2,139,464
2,115,332
Mining 695,221 1,040,762 1,140,811 1,200,214 1,230,259
1,193,094
Public Authorities 257,641 254,130 258,470 247,361 242,845 237,113
- -------------------------------------------------------------------------------------------------------
Total - Electric Retail Sales 8,012,418 8,260,883 8,186,014 7,789,068 7,630,485
7,470,414
Electric Wholesale Sales 7,128,4984,530,793 6,732,802 6,209,254 5,224,235 4,509,936 3,429,455
- -------------------------------------------------------------------------------------------------------
Total Electric Sales 15,389,38112,543,211 14,993,685 14,395,268 13,013,303 12,140,421 10,899,869
=======================================================================================================
Operating Revenues (000)
Residential $290,091 $283,673 $276,720 $253,352 $248,821
$246,251
Commercial 168,159 164,345 157,744 148,039 146,269
146,377
Industrial 160,862 161,584 162,790 160,963 157,735
158,266
Mining 28,168 41,994 48,484 49,399 51,965
53,231
Public Authorities 18,769 18,521 18,908 18,147 17,950 17,531
- -------------------------------------------------------------------------------------------------------
Total - Electric Retail Sales 666,049 670,117 664,646 629,900 622,740
621,656
Amortization of MSR Option Gain
Regulatory Liability - - - - 8,105
Electric Wholesale Sales 761,255177,908 733,559 359,814 171,219 143,269
97,567
Net Unrealized LossGain (Loss) on Forward
Electric Sales and Purchases 533 (1,315) - - - -
Other Revenues 6,603 6,308 3,908 2,964 2,981 2,565
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues $1,436,365$851,093 $1,408,669 $1,028,368 $804,083 $768,990 $729,893
=======================================================================================================
Customers (End of Period)
Residential 326,847 318,976 311,673 303,653 295,469
287,857
Commercial 31,767 31,194 30,467 29,714 28,648
28,309
Industrial 695 705 711 705 684
664
Mining 2 2 42 4 4
Public Authorities 61 61 61 61 61
- -------------------------------------------------------------------------------------------------------
Total Retail Customers 359,372 350,938 342,914 334,137 324,866 316,895
=======================================================================================================
Average Retail Revenue per kWh Sold (cents)
Residential 9.1 9.1 9.1 9.3 9.3
9.4
Commercial 10.5 10.5 10.5 10.7 10.8
11.1
Industrial and Mining 6.4 6.1 6.2 6.1 6.2 6.4
Average Retail Revenue per kWh Sold 8.3 8.1 8.1 8.1 8.2 8.4
Average Revenue per Residential Customer $886 $899 $899 $845 $855 $865
Average kWh Sales per Residential Customer 9,737 9,897 9,834 9,132 9,144 9,159
ENVIRONMENTAL MATTERS
- ---------------------
TEP is subject to environmental regulation of air and water quality,
resource extraction, waste disposal and land use by federal, state and local
authorities. TEP spent approximately $2
million in 2001, $1 million in 2000, and $3 million in 1999 for
construction costs to comply with environmental requirements. TEP believes that all existing generating facilities are in
compliance with all existing regulations and will be in compliance with
expected environmental regulations, except as described below.
Arizona and New Mexico have adopted regulations restricting the
emissions from existing and future coal, oil and gas-fired plants.
These regulations are in some instances more stringent than those
adopted by the EPA. The principal generating units of TEP are
located relatively close to national parks, monuments, wilderness
areas and Indian reservations. Since these areas have relatively
high air quality, TEP could be subject to control standards that
relate to the "prevention of significant deterioration" of
visibility and tall stack limitation rules.
The 1990 Federal Clean Air Act Amendments (CAAA) require reductions of
sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions in two phases, more
complex facility permits and other requirements. TEP is subject only to
Phase II of the SO2 and NOx emission reductions, which became effective
January 1, 2000. All of TEP's generating facilities (except 142 MW of its
internal combustion turbines) are affected.
TEP spent approximately $2
million in 2001 and $1 million annually in 2000 and 1999, and
expects to spend approximately $2 million in 2002 and 2003 complying
with these requirements.
In 1993, TEP's generating units affected by Phase II were allocated SO2
Emission Allowances based on past operational history. Each allowance gives
the owner the right to emit one ton of SO2. Beginning in the year 2000, generating
units subject to Phase II must hold Emission Allowances equal to the level of
emissions in the compliance year or pay penalties and offset excess emissions
in future years. TEP had sufficient Emission Allowances to comply with the
Phase II SO2 regulations for compliance year 2001.2002. However, due to increased
energy output, TEP may have to purchase additional Emission Allowances for
future compliance years.
Title V of the CAAA requires that all of TEP's generating facilities
obtain more complex air quality permits. All TEP facilities (including those
jointly owned and operated by others) have obtained these permits. In 1999,
TEP received Title V permits for the Springerville and Irvington generating
stations. These permits are valid for five years. TEP must pay an annual
emission-
basedemission-based fee for each generating facility subject to a Title V permit.
These emission-based fees are included in the CAAA compliance expenses
discussed above.below. The CAAA also requires multi-year studies of visibility
impairment in specified areas and studies of hazardous air pollutants. The
results of these studies will impact the development of future regulation of
electric utility generating units. Since these activities involve the
gathering of information not currently available, TEP cannot predict the
outcome of these studies.
Arizona and New Mexico have adopted regulations restricting the
emissions from existing and future coal, oil and gas-fired plants. These
regulations are in some instances more stringent than those adopted by the
Environmental Protection Agency (EPA). The EPA has issued a determination that coal and oil fired
electric utility steamprincipal generating units mustof TEP
are located relatively close to national parks, monuments, wilderness areas
and Indian reservations. Since these areas have relatively high air quality,
TEP could be subject to control their mercury
emissions. Final regulations are expectedstandards that relate to be issuedthe "prevention of
significant deterioration" of visibility and tall stack limitation rules.
TEP spent approximately $2.5 million in 2004.2002, $2 million in 2001 and $1
million in 2000, and expects to spend approximately $2 million in 2003 and
2004 complying with these requirements. TEP may incur additional costs to
comply with recent and future changes in federal and state environmental
laws, regulations and permit requirements at existing electric generating
facilities. Compliance with these changes may result in a reduction in
operating efficiency. Failure to comply with any EPA or state compliance
requirements may result in substantial penalties or fines.
In 2001, TEP appliedThe EPA has issued a determination that coal and oil fired electric
utility steam generating units must control their mercury emissions. Final
regulations are expected to be issued in 2004.
On April 29, 2002, the Arizona Department of Environmental Quality
(ADEQ) forissued a major revision tofinal permit granting the expansion of the Springerville
Generating Station Title V permit to allow for expansion of the facility to
include two new 400 MW coal-firedcoal fired generating units.
The proposed
permit would allowTEP worked with the constructionEPA and the ADEQ to determine mutually acceptable levels
of Units 3 and 4 without
subjecting thoseemissions for all four units to full review underaccomplish significant emission reductions
from current levels. If constructed, Springerville Unit 3 will be equipped
with modern emissions control technology and the CAAA regulations
concerning Prevention of Significant Deterioration (PSD). The
proposed permit would allowemissions controls on Units
31 and 4 to avoid a full PSD review
because of a "netting" proposal whereby the total2 will be upgraded. SO2 emissions from all four units wouldwill be up to
55 percent less than those currently produced from the two existing units,
while NOx emissions fromwill be up to 39 percent less. Upgrades to Units
1 and 2 today.will be paid for by the Unit 3 project. The ADEQ submitted the proposed permit to the EPA for review
and on February 13, 2002, the EPA objected to the permit application
because it concluded that emissions reductions from Units 1 and 2
may not be used for netting purposes, contending that Units 1 and 2
were not properly permitted under PSD rules at the time they were
constructed. TEP and the ADEQ have 90 days to resolve the EPA
objection.
On November 9, 2001, the Grand Canyon Trust
(GCT), an environmental activist group, has filed a petition with the EPA
to revoke the permit, based on the allegations in the litigation set forth
below.
On November 13, 2001, the GCT filed a complaint in U.S. District Court
against TEP for alleged violations of the Clean Air Act at the Springerville
Generating Station. The complaint allegesalleged that more stringent emission
standards should apply to Units 1 and 2 and that new permits and the
installation of additional facilities meeting Best Available Control
Technology standards are required for the continued operation of Units 1 and
2 in accordance with applicable law. TEP believes the claims by the GCT are
without merit and will vigorously contest these claims. However,them.
On September 10, 2002, the U.S. District Court granted TEP's motion for
summary judgment on one of the primary issues in the eventcase: whether TEP
commenced construction within 18 months and/or by March 19, 1979, after the
original 1977 air permit covering Units 1 and 2 was issued. The Court found
that TEP would behad commenced consturction of the Springerville Generating Station
in the time periods required by the original permits. There were two
remaining allegations: (1) TEP discontinued construction for a period of 18
months or longer and did not complete construction in a reasonable period of
time and (2) TEP did not commence construction, for purposes of New Source
Performance Standard applicability, by September 18, 1978. On March 4, 2002,
the U.S. District Court determined that the GCT had not commenced the case
on a timely basis and dismissed the case.
On November 1, 2002 the ACC granted TEP siting approval to install such new technology,construct
Unit 3 (and Unit 4, if Unit 4 is built) at Springerville subject to certain
conditions. Both the cost could be up to
$200 million.GCT and the Land and Water Fund of the Rockies have
opposed this approval and have filed for reconsideration which was denied
by the ACC. The GCT and the Land and Water Fund of the Rockies have
judicially appealed this decision.
MILLENNIUM ENERGY BUSINESSES
- ----------------------------
Millennium's assets comprised approximately 6% of the consolidated
assets of UniSource Energy at December 31, 2001 and
2000.2002. Millennium had an after-tax
loss of $9$15.5 million in 2002 and $9.2 million in 2001, which included a $6
million after-tax gain on the sale of a power project. In 2000, Millennium
reported losses of $4.1 million. Through its affiliates, Millennium holds
investments in the energy-
relatedenergy-related businesses which are described below.
Energy Technology Investments
-----------------------------
In 1996, Millennium and a privately held company formed an
entityparticipates in various companies designed to develop
renewable energy, thin-film technologies and thin-film technologies.
Millennium owns approximately 67% of the following entities:other emerging energy
technologies, including:
- Global Solar Energy, Inc. (Global Solar), a developer of flexible thin-filmthin-
film photovoltaic cells, started limited production of photovoltaic
cells in 1999. TargetGlobal Solar's target markets for its products include
military,commercial, space and commercialmilitary applications. Millennium currently owns
87% of Global Solar.
- Infinite Power Solutions, Inc. (IPS), a developer of thin-film
batteries. In 2001,At December 31, 2002, Millennium owns approximately 77.5% of
IPS, however this ownership share is anticipated to be reduced in 2003
as a result of planned additional external investment by Dow Corning
Enterprises, Inc. Millennium anticipates that its ultimate ownership
in IPS will be between 59% and a privately held company formed and
began to provide funding to72%.
- MicroSat Systems, Inc. (MicroSat) and
ITN Energy Systems, Inc. (ITN). MicroSat is a developer of small-small scale
satellites, focusing on research andsatellites. MicroSat funds much of the development activities related to governmentthrough
Federal Government contracts. ITN provides research and
development and other services to affiliates, the Government and
other third parties. Millennium currently owns 49% of
MicroSat, and
ITN.but pursuant to a restructuring agreement signed earlier in
the year, has agreed to reduce its ownership to 35%. Millennium expects
this change to occur in 2003.
As technology developers, these entities face many challenges, such as
developing technologies that can be manufactured on an economic scale,
technological obsolescence, known and unknown
competitors and possible reductions in government
spending to advance technological research and development activities. While
in the short-term we believe weMillennium will incur losses from the funding of
the development efforts, we believe that the investments will be profitable
in the long-term. Millennium expects to fund at least
$14between $7 million and $15
million to its various technology investments in 2002.2003. In 2002, Millennium
provided $18.5 million in debt and equity funding to the Energy Technology
Investments. See Item 7. - Management's Discussion and Analysis of Financial
Condition and Results of Operations, Results of Millennium Energy Businesses
for more information regarding these entities, including research and
development activities.
Sabinas
-------
In 2002, Millennium invested $20 million in a company created to develop
up to 800 megawatts (MW) of coal-fired generation in the Sabinas region of
Coahuila, Mexico. Millennium received a 50% share of Carboelectrica Sabinas,
S. de R.L. de C.V., a Mexican limited liability company (Sabinas). The other
50% of Sabinas is owned by Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and
certain of its affiliates. Sabinas also owns approximately 19.5% of
Minerales de Monclova, S.A. de C.V., (Mimosa). Mimosa is an owner of coal
and associated gas reserves, a supplier of metallurgical coal to the steel
industry, and a supplier of thermal coal to the Mexican electricity commission.
Since 1999, both AHMSA and Mimosa are parties to a suspension of payments
procedure, under applicable Mexican law, which is the equivalent of a U.S.
Chapter 11 proceeding. Under certain circumstances, Millennium has the right
to sell its interest (a put option) in Sabinas to an AHMSA affiliate for $20
million plus an accrued service fee. These circumstances include failure of
Sabinas to reach financial closing on the generation project within three
years. Millennium's put option is secured by collateral with a value currently
in excess of $20 million. UniSource Energy's Chairman, President and Chief
Executive Officer is a member of the board of directors of AHMSA.
Nations Energy
--------------
Nations Energy Corporation (Nations Energy), a wholly-owned subsidiary
of Millennium, was established in 1995 to develop and invest in independent
power projects worldwide. In 2001, Nations Energy sold its 26% equity
interest in a power project located in Curacao, Netherland Antilles. Nations
Energy has one remaining investment, a 40% equity interest in an independent
power producer that owns and operates a 43 MW power plant near Panama City,
Panama. Nations Energy intends to sell its interest in this project, which
has a book value of less than $1 million at December 31, 2001.2002. Millennium
does not currently intend to make any additional investments in Nations
Energy. See Item 7. - Management's Discussion and Analysis of Financial
Condition and Results of Operation - Results of Millennium Energy Businesses,
Nations Energy.
Other Millennium Investments
----------------------------
TheMillennium also has the following Millennium investments represented less than 1%
of consolidated assets and consolidated net income of UniSource
Energy at December 31, 2001 and 2000:which are consolidated:
- Southwest Energy Solutions, Inc. was established in January 1997
and(SES), a wholly-owned Millennium
subsidiary, provides electrical contracting services statewidein Arizona to
commercial, industrial and governmental customers in both high voltage
and inside wiring capacities and meter reading services for
local utilities, includingto TEP.
- Millennium Environmental Group, Inc. (MEG) was, a wholly-owned Millennium
subsidiary, established in September 2001, to managemanages and tradetrades emission
allowances, coal and other environmental related products including
financialderivative instruments.
- PowertrusionPOWERTRUSION International, Inc. (Powertrusion), is a manufacturer of
lightweight utility poles. Millennium invested $3 million in
Powertrusion in August 2001 for a controllingpoles, which is 50.5% interest in
the company.owned by Millennium.
We describe Millennium's unregulated energy businesses and other
investments in more detail in Note 4 of Notes to Consolidated Financial
Statements - Millennium Energy Businesses, and in Item 7. - - Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Results of Millennium Energy Businesses and in InvestingLiqiudity and Financing ActivitiesCapital
Resources, Millennium - Millennium.Unregulated Businesses.
UNISOURCE ENERGY DEVELOPMENT COMPANY
- ------------------------------------
UED, was established in February 2001, and engages in developing
generating resources and other project development activities. UED
owns a 20 MW gas turbine under lease to TEP. It is also the project
developer for the expansion of the coal-fired Springerville
Generating Station through construction of Springerville Units 3 and 4.
In recognition of the strong retail growth in Arizona and New
Mexico, as well as existing and projected base-load generation
capacity needs in the western region, we began to evaluatefacilitating the expansion of the
Springerville Station in 2000. On October 19,
2001, UED and Salt River Project Agricultural Improvement and Power
District (SRP) signed a joint development agreement to share
ownership and development costs ofGenerating Station. The Springerville Units 3 and 4. We
expect that SRP would also purchase 50% of the power generation from
the facility. These purchases would be pursuant to a long-term
power purchase agreement, which is in the process of being
negotiated. The balance of the power generation would be sold to
other regional power companies, possibly including TEP.
SpringervilleGenerating Station was
originally designed for four units. If constructed, each of Units 3 and 4
would consist of twoa 400 MW coal-fired, base-load generating unitsunit at the same
site as Springerville Units 1 and 2, and2. If Unit 3 (and subsequently Unit 4) is
built, this would allow usTEP to spread the fixed costs of the existing common
facilities over the two additional generating units. We are developingunit (or units).
UED currently expects to act as project manager for the development of
Springerville Unit 3 (and Unit 4, if Unit 4 is built) and anticipates that
financing and ownership will occur through third parties. The entire output
of Unit 3 is expected to be taken by regional power companies, including
Tri-State Generation and Transmission Association (Tri-State), Salt River
Project Agricultural Improvement and Power District (SRP), and TEP. It is
currently expected that SRP will purchase 100 MW, and Tri-State will take
300 MW. TEP would purchase from Tri-State up to 100 MW of capacity for no
more than five years from commercial operation. SRP also has an option to
own Unit 4 at a later date. If SRP exercises the option to own Unit 4,
TEP would be required to purchase SRP's 100 MW of output from Unit 3,
beginning with the commercial operation of Unit 4.
Tri-State and UED signed a Development Cost Agreement in January 2003
to each share 50% of the development costs of Unit 3 effective from November
6, 2002 until financial closing. As of December 31, 2002, UED had
approximately $22 million of capitalized project scopedevelopment costs on its
balance sheet.
On October 29, 2002, the ACC issued an order that affirms the
Certificate of Environmental Compatibility (CEC) granted to TEP authorizing
the construction of Unit 3, subject to compliance with certain conditions,
and schedule and definingapproved the terms of an engineering,
procurement, and construction contract. We are also continuing the
permitting process, evaluating financing plans, and negotiating with
other potential long-term power purchasers in additionCEC for Unit 4 subject to SRP.certain conditions occurring. The
ACC approved construction of a third and fourth unit at the Springerville
Generating Station in 1977 and 1987, respectively, providingbut with respect to Unit
4, the ACC provided that TEP, as plant operator, demonstrate that the fourth
unit was needed to provide an adequate, economical and reliable supply of
electric power to its customers. In July 2001, TEP filed
an application requestingThat demonstration was made as part of the
proceedings that resulted in the issuance of the ACC to schedule a hearing addressing
the need for the fourth electric generating unit. Evidentiary
hearings regarding the need for Unit 4 were held in November 2001 in
Springerville and Phoenix. The matter is pending before the ACC.
TEP is also currently involved in discussions with the EPA and
the ADEQ to determine specific levels of acceptable emissions at
Springerville. Current plans call for total emissions from all four
units to be less than the emissions from Units 1 and 2 today. The
ADEQ held a public hearing on the air quality control permit in
November 2001. On February 13, 2002, the EPA objected to the permit
application. TEP and the ADEQ have 90 days to resolve the EPA
objection. See Environmental Matters above.Order.
Environmental activist groups have expressed concerns regarding the
construction of Units 3 and 4.any new units. Such concerns have been expressed during the
permitting and ACC proceedings and may extend to other forums and to issues
apart from the proposed construction. On November 9, 2001,See Environmental Matters above.
UED expects to finalize the Grand Canyon Trust, an environmental
activist group, filed a complaint in U.S. District Court against TEP
for alleged violations of the Clean Air Act at the Springerville
Generating Station. The complaint alleges that more stringent
emission standards should apply to Units 1 and 2 and that new
permits and the installation of additional facilities meeting Best
Available Control Technology standards are required for the
continued operation of Units 1 and 2 in accordance with applicable
law. TEP believes the claims are without merit and will vigorously
contest these claims.
We anticipate that power purchase agreements, with other project
off-takers, the engineering,
procurement and construction contract, and other required project agreements
during the first half of 2003. UED expects a third party to obtain
construction financing will be in place during the third
quarter of 2002. We expect that construction will2003 and then begin by the
fourth quarter of 2002, withconstruction. UED expects
commercial operation of Unit 3 expected
to occur in early 2006, followed six to twelve months later by Unit
4.2006. We can make no assurances,
however, about the ultimate timing, or whether weUED will proceed with this
project. See also Item 7.Note 10 of Notes to Consolidated Financial Statements - Management's Discussion and Analysis of Financial Condition and
Results of Operations - Investing and Financing Activities, UED.UED
Commitments.
EMPLOYEES
- ---------
As of December 31, 2001,2002, TEP had 1,1411,134 employees and the wholly-
ownedwholly-owned
subsidiaries of Millennium had 16118 employees. The International Brotherhood
of Electrical Workers (IBEW) Local 1116 represents approximately 60%58% of TEP's
employees. A new three-year collective bargaining agreement between the IBEW
and TEP was ratified in March 1999December 2002 and extends until Januarythrough 2005. Wages for
bargaining unit employees will increase 3.5% in 2003. Wage increases for
2004 and 2005 will be determined annually during July and August of each
preceding year.
SEC REPORTS AVAILABLE ON UNISOURCE ENERGY'S WEBSITE
- ---------------------------------------------------
UniSource Energy and TEP make available their annual reports on Form 10-
K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all
amendments to those reports as soon as reasonably practicable after they
electronically file them with, or furnish them to, the SEC. These reports
are available free of charge through UniSource Energy's website address:
http://www.unisourceenergy.com. A link from UniSource Energy's website to
these SEC reports is accessible as follows: At the UniSource Energy main
page, select Investor Relations from the menu shown at the top of the page;
next select SEC filings from the menu shown on the Investor Relations page.
Information contained at UniSource Energy's website is not part of any
report filed with the SEC by UniSource Energy or TEP.
The new agreement resulted in a wage
increaseSEC also maintains an Internet site that contains reports, proxy and
information statements, and other information regarding issuers that file
electronically with the SEC. The SEC website address is http://www.sec.gov.
Interested parties may also read and copy any materials UniSource Energy and
TEP file with the SEC at the SEC's Public Reference Room at 450 Fifth Street,
NW, Washington, DC 20549. Information on the operation of 3% in 2000 and an additional 3% in 2001.the Public
Reference Room is available by calling the SEC at 1-800-SEC-0030.
ITEM 2. - PROPERTIES
- --------------------------------------------------------------------------------
TEP's transmission facilities, located in Arizona and New Mexico,
transmit electricity from TEP's remote electric generating stations at Four
Corners, Navajo, San Juan and Springerville to the Tucson area for use by
TEP's retail customers (see Item 1. - Business - Generating and Other
Resources). The transmission system is directly interconnected with systems operated by the following
utilities:
Utility Location
------- --------at various
points in Arizona Public Service Co. Arizona
Arizona Electric Power Cooperative Arizona
El Paso Electric Co.and New Mexico Texas
Public Service Co.with a number of New Mexico New Mexico
Salt River Project Arizonaregional utilities. TEP
has arrangements with approximately 120 companies
including the five listed above, to interchange generation
capacity and transmission of energy.
As of December 31, 2001,2002, TEP owned, or participated in, an overhead
electric transmission and distribution system consisting of:
- 511 circuit-miles of 500 kV lines;
- 1,122 circuit-miles of 345 kV lines;
- 372371 circuit-miles of 138 kV lines;
- 434 circuit-miles of 46 kV lines; and
- 11,52912,095 circuit-miles of lower voltage primary lines.
The underground electric distribution system is comprised of 6,870 cable-miles.7,353 cable-
miles. TEP owns approximately 77% of the poles on which the lower voltage
lines are located. Electric substation capacity consisted of 185192 substations
with a total installed transformer capacity of 5,589,7725,602,522 kilovoltamperes.
The electric generating stations (except as noted below), operating
headquarters, warehouse and service center are located on land owned by TEP.
The electric distribution and transmission facilities owned by TEP are
located:
- on property owned by TEP;
- under or over streets, alleys, highways and other public places, the
public domain and national forests and state lands under franchises,
easements or other rights which are generally subject to termination;
- under or over private property as a result of easements obtained
primarily from the record holder of title; and
- over Indian reservations under grant of easement by the Secretary of
Interior or lease by Indian tribes.
It is possible that some of the easements, and the property over which
the easements were granted, may have title defects or may be subject to
mortgages or liens existing at the time the easements were acquired.
Springerville is located on land parcels held by TEP under a long-term
surface ownership agreement with the State of Arizona.
Four Corners and Navajo are located on properties held under easements
from the United States and under leases from the Navajo Indian Tribe.Nation. TEP,
individually and in conjunction with PNMPublic Service Company of New Mexico
(PNM) in connection with San Juan, has acquired easements and leases for
transmission lines and a water diversion facility located on land owned by
the Navajo Indian Reservation.Nation. TEP has also acquired easements for transmission
facilities, related to San Juan, Four Corners, and Navajo, across the Zuni,
Navajo and Tohono O'odham Indian Reservations.
TEP's rights under these various easements and leases may be subject to
defects such as:
- possible conflicting grants or encumbrances due to the absence of or
inadequacies in the recording laws or record systems of the Bureau of
Indian Affairs and the Indian tribes;
- possible inability of TEP to legally enforce its rights against
adverse claimants and the Indian tribes without Congressional consent;
and
- failure or inability of the Indian tribes to protect TEP's interests
in the easements and leases from disruption by the U.S. Congress,
Secretary of the Interior, or other adverse claimants.
These possible defects have not and are not expected to materially
interfere with TEP's interest in and operation of its facilities.
TEP, under separate sale and leaseback arrangements, leases the
following generation facilities (which do not include land):
- coal handling facilities at Springerville;
- a 50% undivided interest in the Springerville Common Facilities;
- Springerville Unit 1 and the remaining 50% undivided interest in
Springerville Common Facilities; and
- Irvington Unit 4 and related common facilities.
See Note 7 of Notes to Consolidated Financial Statements, Long-Term
Debtand Item 7. -
Management's Discussion and Analysis of Financial Condition and Results of
Operations, Liquidity and Capital LeaseResources, Contractual Obligations, and Item 1 - Business - TEP
Generating Resources for
additional information on TEP's capital lease obligations.
Substantially all of the utility assets owned by TEP are subject to the
lien of the General First Mortgage and the General Second Mortgage.
Springerville Unit 2, which is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP, is not subject to those
liens.
ITEM 3. - LEGAL PROCEEDINGS
- --------------------------------------------------------------------------------
LITIGATION RELATED TO ACC ORDERS AND RETAIL COMPETITION
See Item 1.7. - BusinessManagement's Discussion and Analysis of Financial
Condition and Results of Operations - RatesFactors Affecting Results of Operations
for litigation related to ACC orders and Regulation.
SPRINGERVILLE GENERATING STATION COMPLAINT
Seeretail competition.
We discuss other legal proceedings in Note 10 of Notes to Consolidated
Financial Statements.
ITEM 4. - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------
Not Applicable.applicable.
PART II
ITEM 5. - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
- --------------------------------------------------------------------------------
Stock Trading
-------------
UniSource Energy's common stockCommon Stock is traded under the ticker symbol UNS.
It is listed on the New York Stock Exchange and the Pacific Stock
Exchanges and began trading under the symbol UNS on January 2, 1998.Exchange. As of
February 25, 2002,March 4, 2003, the closing price was $17.62,$16.58, with 20,29715,181 shareholders of
record.
Dividends
---------
UniSource Energy pays dividends on its common stockCommon Stock after its Board of
Directors declares them. There is no limitation on UniSource Energy paying
common stock dividends.dividends on its Common Stock.
TEP pays dividends on its common stock after its Board of Directors
declares them. UniSource Energy is the primary shareholder of TEP's common
stock. TEP has certain restrictions on paying dividends, as listed below:
- TEP can pay dividends if it maintains compliance with the TEP Credit
Agreement and certain financial covenants, including a covenant that
requires TEP to maintain a minimum level of net worth.worth, and so long as
the dividends and certain investments in affiliates would not exceed 65%
of TEP's net income.
- Under ACC restrictions, TEP can pay dividends so long as the dividends
do not exceed 75% of TEP's earnings until its equity ratio equals 37.5%
of total capital (excluding capital lease obligations).
- Under the Federal Power Act, TEP cannot pay dividends out of funds
that are properly included in the capital account.
See Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations - Dividends on Common Stock.
Common Stock Dividends and Price Ranges
-------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
----------------------------------------------------------------------------------
Quarter: Market Price per Dividends Market Price per Dividends
Share of Common PaidDeclared Share of Common PaidDeclared
Stock (1) Stock (1)
High Low High Low
---- --- ---- ---
First $20.60 $16.74 $0.125 $21.00 $15.13 $0.10
$15.25 $10.81 $0.08
Second 20.75 17.91 0.125 25.98 20.16 0.10
16.38 14.13 0.08
Third 18.89 14.05 0.125 24.05 13.80 0.10
17.25 14.75 0.08
Fourth 17.90 13.69 0.125 19.30 13.80 0.10
19.31 14.13 0.08
----------------------------------------------------------------------------------
Total $0.500 $0.40
$0.32
----------------------------------------------------------------------------------==================================================================================
(1) UniSource Energy's common stockCommon Stock price on the consolidated tape as reported by
Dow Jones.
On February 7, 2002,2003, UniSource Energy declared a cash dividend of $0.125$0.15
per share on its common stock, a 25% increase over the
prior quarter.Common Stock. The dividend is payable March 8, 20027, 2003 to
shareholders of record at the close of business February 21, 2002.2003.
TEP declared and paid cash dividends of $35 million in 2002, $50 million
in the
fourth quarter of 2001, and $30 million in the fourth quarter of 2000,
and $34 million in the fourth quarter of 1999.2000.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
- --------------------------------------------------------------------------------
UNISOURCE ENERGYUniSource Energy 2002 2001 2000 1999 1998
1997 (1)
-----------------------------------------------------------------------------------------------------------------
- In Thousands -
Summary of Dollars -Operations (except per share data)
- --------------------------------------------------------------------------------------------------
Summary of Operations
- ----------------------------------------------------------------------------------------------
Operating Revenues $1,444,708$856,222 $1,417,012 $1,033,669 $814,828 $770,597 $729,893
Income Tax Benefit Recognition
Related to Prior Period NOLs -
Part of Income Taxes - - - - $43,443
Gain on Sale of NewEnergy - - - $34,651 -
-
Net LossesLoss Before Income Taxes of Millennium
Energy Businesses (2)(1) $(30,702) $(14,455) $(12,059) $(11,276) $(11,884) $(8,182)
Income Before Extraordinary Item and
Accounting Change $33,275 $60,875 $41,891 $56,510 $28,032
$83,572
Net Income $33,275 $61,345 $41,891 $79,107 $28,032 $83,572
Basic Earnings per Share:
Before Extraordinary Item &
Accounting Change $0.99 $1.83 $1.29 $1.75 $0.87
$2.60
Net Income $0.99 $1.84 $1.29 $2.45 $0.87 $2.60
Diluted Earnings per Share:
Before Extraordinary Item &
Accounting Change $0.97 $1.79 $1.27 $1.74 $0.87
$2.59
Net Income $0.97 $1.80 $1.27 $2.43 $0.87 $2.59
Shares of Common Stock Outstanding
Average 33,39933,665 33,398 32,445 32,321 32,177
32,138
End of Year 33,579 33,502 33,219 32,349 32,258 32,139
Year-end Book Value per Share $13.05 $12.68 $11.20 $10.02 $7.65 $6.75
Cash Dividends Declared per Share $0.50 $0.40 $0.24 $0.08 -
- - ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Financial Position
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Utility Plant - Net $1,668,350 $1,677,671 $1,706,290 $1,729,856 $1,915,590
$1,935,513Investments in Lease Debt and Equity $191,867 $84,459 $71,639 $44,550 $17,813
Other Investments and Other Property $182,747 $121,811 $114,483 $110,289 $79,471$123,238 $98,288 $50,172 $69,933 $92,476
Total Assets $2,735,325$2,690,734 $2,746,717 $2,671,384 $2,656,255 $2,634,049
$2,634,409
Long-Term Debt (3)(2) $1,128,963 $802,804 $1,132,395 $1,135,820 $1,184,423
$1,215,120
Non-Current Capital Lease Obligations 801,611 853,793 857,829 880,427 889,543
890,257
Common Stock Equity 438,229 424,722 372,169 324,248 246,646
216,878
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $2,368,803 $2,081,319 $2,362,393 $2,340,495 $2,320,612
$2,322,255
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Selected Cash Flow Data
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows From Operating
Activities $172,963 $215,379 $215,034 $113,228 $160,933
$126,283
Capital Expenditures $(112,706) $(121,622) $(105,996) $(92,808) $(81,147)
$(72,475)
Other Investing Cash Flows (158,184) 4,775 (7,554) (242) (27,810)
(4,030)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows From Investing
Activities $(270,890) $(116,847) $(113,550) $(93,050) $(108,957)
$(76,505)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows From Financing
Activities $(39,299) $(33,382) $(83,768) $(20,057) $(53,065)
$(33,813)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(1) For years prior to 1998, UniSource Energy's operations and those of TEP are the same.
(2) Net LossesLoss Before Income Taxes of Millennium Energy Businesses are before income taxes, do not includefor 1999 excludes the 1999 Gain on
Sale of NewEnergy, and include operating revenues, which are also
included in the Operating Revenues line item in this schedule.
(3)NewEnergy.
(2) TEP's tax-exempt variable rate bonds in the amount of $329 million are backed by LOCs
under TEP's Credit Agreement. TEP's obligations under the Credit Agreement are
collateralized with Second Mortgage Bonds. TheIn November 2002, TEP entered into two new
LOCs expirefor $341 million to replace the LOCs provided under its then existing credit
agreement that would have expired on December 30, 2002. If the LOCs are not extended or replaced withThese new LOCs with a longer term or if
the bonds are not otherwise refinanced, the bonds would be redeemed.expire in 2006.
Accordingly, these IDBs were classified as short-term debt at December 31, 2001 and
will be
classified as long-term debt once a new LOC Facility with a later expiration date
is obtained.at December 31, 2002.
See Item 7,7. - Management's Discussion and Analysis of Financial Condition and Results of
Operations.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
- --------------------------------------------------------------------------------
TEP 2002 2001 2000 1999 1998
1997 (1)
---------------------------------------------------------------------------------------------------------------
- Thousands of Dollars -
Summary of Operations
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,436,365$851,093 $1,408,669 $1,028,368 $804,083 $768,990 $729,893
Income Tax Benefit Recognition
Related to Prior Period NOLs -
Part of Income Taxes - - - - $43,443
Net Losses of Unregulated Energy
Businesses (2) - - - - $(8,182)
Income Before Extraordinary Item
and Accounting Change $53,737 $74,814 $51,169 $50,878 $41,676
$83,572
Net Income $53,737 $75,284 $51,169 $73,475 $41,676
$83,572
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Financial Position
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Utility Plant - Net $1,668,350 $1,677,671 $1,706,290 $1,729,856 $1,915,590
$1,935,513Investments in Lease Debt and Equity $191,867 $84,459 $69,474 $44,550 $17,813
Other Investments and Other Property $105,875 $92,334 $67,838 $62,978 $79,471$21,358 $21,416 $22,860 $23,288 $45,165
Total Assets $2,633,943$2,613,590 $2,645,335 $2,600,935 $2,600,508 $2,628,588
$2,634,409
Long-Term Debt (3)(1) $1,128,410 $801,924 $1,132,395 $1,135,820 $1,184,423
$1,215,120
Non-Current Capital Lease Obligations 801,508 853,447 857,519 880,111 889,543
890,257
Common Stock Equity 337,463 322,471 295,660 270,134 229,861
216,878
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $2,267,381 $1,977,842 $2,285,574 $2,286,065 $2,303,827
$2,322,255
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Selected Cash Flow Data
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows From Operating
Activities $203,517 $261,169 $234,190 $139,957 $180,487
$126,283
Capital Expenditures $(103,307) $(103,913) $(98,063) $(90,940) $(81,011)
$(72,475)
Other Investing Cash Flows (145,271) (11,981) (23,273) (24,480) (43,937)
(4,030)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows From Investing
Activities $(248,578) $(115,894) $(121,336) $(115,420) $(124,948)
$(76,505)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows From Financing
Activities $(58,841) $(74,307) $(112,544) $(54,371) $(83,559)
$(33,813)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Ratio of Earnings to Fixed Charges 1.58 1.82 1.47 1.45 1.35
1.39
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(1) For years prior to 1998, UniSource Energy's operations and those of TEP
are the same.
(2) Net Losses of Unregulated Energy Businesses are before income taxes and include operating
revenues, which are also included in the Operating Revenues line item in this schedule.
(3) TEP's tax-exempt variable rate bonds in the amount of $329 million are backed by LOCs
under TEP's Credit Agreement. TEP's obligations under the Credit Agreement are
collateralized with Second Mortgage Bonds. TheIn November 2002, TEP entered into two new
LOCs expirefor $341 million to replace the LOCs provided under its then existing credit
agreement that would have expired on December 30, 2002. If
the LOCs are not extended or replaced withThese new LOCs with a longer term or if the bonds
are not otherwise refinanced, the bonds would be redeemed.expire in 2006.
Accordingly, these IDBs were classified as short-term debt at December 31, 2001 and
will be classified as long-term debt once a new LOC Facility with a later expiration date is obtained.at December 31, 2002.
Note: Disclosure of earnings per share information for TEP is not presented as the common
stock of TEP is not publicly traded.
See Item 7,7. - Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 7. - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
Management's Discussion and Analysis explains the results of operations,
the general financial condition, and the results of operationsoutlook for UniSource Energy and its
three primary business segments--thesegments-the electric utility business of TEP and the
unregulated energy businesses of Millennium and UED--andUED-and includes the
following:
- operating results during 2002 compared with 2001, and 2001 compared with
2000,
- factors which affect our results and during 2000
compared with 1999,outlook,
- changes inour outlook and strategy, and
- our liquidity, andcapital needs, capital resources during 2001, and - expectations of identifiable material trends which may affect our
business in the future.contractual
obligations.
TEP is the principal operating subsidiary of UniSource Energy and
accounts for substantially all of its assets and revenues. Income and losses
from Millennium's energy-related businesses have had a significant impact on
earnings reported by UniSource Energy for the years ended December 31,2002, 2001, 2000, and 1999. UED's2000. UED`s
unregulated business segment, which was established in February 2001, may
have a significant impact on consolidated net income and cash flows in the
future. OVERVIEWIn addition, in 2002, UniSource Energy entered into asset purchase
agreements for the purchase of retail electric and gas utility assets in
various locations in Arizona, which if completed, will have a significant
impact on our financial condition and results of operations.
RESULTS OF OPERATIONS
- -----------------------------
UNISOURCE ENERGY CONSOLIDATED
UniSource Energy recorded net income of $33 million in 2002, compared
with $61 million in 2001, compared with net income ofand $42 million in 2000 and $79 million in
1999.2000. UniSource Energy's total
revenues increaseddecreased by 40% to $1.4
billion$856 million in 2001,2002, resulting from
growth in retail electricity sales
andsignificantly decreased wholesale marketing activities at TEP. The following
factors contributed to the improvementchange in net income in 2002 compared with 2001:
- TEP's wholesale revenues decreased by $556 million, or 76%, due to
significantly lower prices in the western U.S. energy markets and
decreased sales activity, partially offset by a reduction of $527
million, or 66%, in fuel and purchased power expenses.
- Mild weather and lower demand from TEP's mining customers contributed
to lower retail energy sales and revenues in 2002. Despite these
factors, retail revenues fell only one percent due to continued strong
growth in number of retail customers and increased usage by residential
and commercial customers.
- TEP recorded a one-time $7 million after-tax coal contract termination
fee expense in the third quarter of 2002, which will relieve TEP of
annual $2 million after-tax take-or-pay payments in future years.
- Millennium's after-tax losses were $6 million higher in 2002 than 2001
because 2001 results included a $6 million after-tax gain on the sale of
a power project.
- TEP recognized $5 million in tax benefits from the favorable
settlement of IRS audits and the recognition of tax credits in 2002, and
Millennium recognized $2.5 million in tax benefits from the recognition
of foreign tax losses and favorable settlement of IRS audits.
The following factors contributed to the change in net income in 2001
compared with 2000:
- TEP's average number of retail customers grew by 2.5% to 347,099 in
2001 and retail revenues grew by 0.8% to $670 million;million.
- TEP's wholesale revenues more than doubled due to sales of available
generating capacity, increased trading activities and significantly
higher prices in the western U.S. energy markets in the first half of
2001;2001.
- a 5% reduction in interestInterest expense at TEP decreased by 5% due to lower debt balances and
lower rates on variable rate debt;debt.
- Nations Energy sold an independent power project in 2001 for a $6
million after-tax gain from the sale of an independent power
project by a Millennium subsidiary, Nations Energy; andgain.
- TEP recorded a one-time $8 million after-tax expense related to the
amendment of a coal supply contract recorded in the third quarter of 2000.
CONTRIBUTION BY BUSINESS SEGMENT
The table below shows the contributions to our consolidated after-tax
earnings by our three business segments, as well as parent company expenses.
2002 2001 2000
--------------------------------------------------------------------
- Millions of Dollars -
Business Segment
TEP $ 53.7 $ 75.3 $ 51.2
Millennium (15.5) (9.2) (4.1)
UED 0.8 0.8 -
UniSource Energy Standalone (1) (5.8) (5.6) (5.2)
--------------------------------------------------------------------
Consolidated Net income was lower in 2000 than in 1999 primarily due to the
following factors:
- $23 million after-tax extraordinary income from changes in
accounting for TEP's generation operations recorded in the fourth
quarterIncome $ 33.2 $ 61.3 $ 41.9
====================================================================
(1) Represents interest expense (net of 1999;
- the $21 million after-tax gaintax) on the salenote payable
from UniSource Energy to TEP.
RESULTS OF TEP
The financial condition and results of oneoperations of TEP are currently
the principal factors affecting the financial condition and results of
operations of UniSource Energy on an annual basis. The following discussion
relates to TEP's utility operations, unless otherwise noted. The results of
our unregulated energy businesses are discussed in Results of Millennium
Energy Businesses and Results of UED, below.
UTILITY SALES AND REVENUES
Customer growth, weather and other consumption factors affect retail
sales of electricity. Price changes also contribute to changes in retail
revenues. Electric wholesale revenues are affected by market prices in the
wholesale energy market, availability of TEP generating resources, and the
level of wholesale forward contract activity.
TEP experienced a significant decrease in wholesale energy sales and
revenues during 2002 compared with 2001. Market demand in the western region
declined primarily as a result of mild temperatures, and market prices fell
as a result of increased capacity in the region and declining natural gas
prices, as well as reduced demand. In comparison, during the first five
months of 2001 and the last half of 2000, TEP experienced significant growth
in wholesale energy sales and revenues, primarily due to significantly higher
regional market prices, which increased to unprecedented levels, and
opportunities to sell its excess generating capacity to California and other
western wholesale market participants. However, in June 2001 wholesale
market prices began a steady decline and by 2002, reached levels that were
more consistent with historical prices. By 2002, electric wholesale revenues
comprised only 21% of total revenues, compared with 52% in 2001 and 35% in
2000. TEP's electric wholesale sales consist primarily of four types of
sales:
(1) Sales under long-term contracts for periods of more than one year.
TEP currently has long-term contracts with three entities to sell
firm capacity and energy: SRP, the Navajo Tribal Utility Authority
and the Tohono O'odham Utility Authority. TEP also has a multi-year
interruptible contract with Phelps Dodge Energy Services, which
requires a fixed contract demand of 60 MW at all times except during
TEP's peak customer energy demand period, from July through September
of each year. Under the contract, TEP can interrupt delivery of power
if the utility experiences significant loss of any electric generating
resources.
(2) Forward contracts to sell energy for periods through the end of the
next calendar year. Under forward contracts, TEP commits to sell a
specified amount of capacity or energy at a specified price over a
given period of time, typically for one-month, three-month or one-year
periods.
(3) Short-term economy energy sales in the daily or hourly markets at
fluctuating spot market prices and other non-firm energy sales.
(4) Sales of transmission service.
The table below provides trend information on retail sales by major
customer class and on the four types of electric wholesale sales made by TEP
in the last three years.
Sales Operating Revenue
2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------------------------
- Millions of kWh - - Millions of Dollars -
Electric Retail Sales:
Residential 3,189 3,122 3,028 $ 290 $ 284 $ 276
Commercial 1,609 1,573 1,497 168 164 158
Industrial 2,261 2,271 2,262 161 162 163
Mining 695 1,041 1,141 28 42 48
Public Authorities 258 254 258 19 18 19
- -----------------------------------------------------------------------------------------------
Total Electric Retail Sales 8,012 8,261 8,186 666 670 664
- -----------------------------------------------------------------------------------------------
Electric Wholesale Sales Delivered:
Forward Contracts 983 3,546 2,612 32 480 129
Long-term Contracts 981 1,219 1,234 51 52 52
Short-term Sales and Other 2,567 1,968 2,363 91 198 174
Transmission - - - 4 4 5
- -----------------------------------------------------------------------------------------------
Total Electric Wholesale Sales 4,531 6,733 6,209 178 734 360
- -----------------------------------------------------------------------------------------------
Total 12,543 14,994 14,395 $ 844 $1,404 $1,024
===============================================================================================
2002 Compared with 2001
-----------------------
TEP's average number of retail customers increased by 2.4% to 355,486,
while kWh sales to retail customers decreased by 3.0% in 2002 compared with
2001. This decrease in kWh energy sales was primarily due to a 33% reduction
in sales to copper mining customers. Sales to residential, commercial and
non-mining industrial customers as a group actually increased by 1.3% in
2002, despite milder temperatures in 2002. Cooling Degree Days decreased 3%
for the year, and also decreased slightly when compared with the 10-year
average. Heating Degree Days decreased 16% for 2002 and 4% compared with the
10-year average. Revenue from sales to retail customers decreased only
slightly in 2002 compared with 2001, reflecting the increased kWh sales to
non-mining customers.
Electric wholesale sales decreased by 33% in 2002 compared with 2001
while revenues decreased by 76%. The decrease in revenue resulted from
decreased sales activity and the sharp decline in market prices from those in
2001. The average market price for around-the-clock energy decreased $67 per
MWh, compared with 2001. Sales and revenues from forward contracts
experienced the largest declines, reflecting lower demand and lower market
prices in the forward energy markets. Short-term sales were higher, however,
due to sales of excess energy in the daily and hourly markets. Despite the
higher short-term sales volumes, revenues from short-term sales were
significantly lower in 2002 due to the lower average market prices. Factors
contributing to the lower market prices include more generation online in the
western U.S., lower natural gas prices, increased hydropower supply, and
weaker demand.
2001 Compared with 2000
-----------------------
TEP's kWh sales to retail customers increased by 1% in 2001 compared
with 2000, despite a 2.5% increase in the average number of retail customers
to 347,099. Sales to mining customers decreased by 9%, offset by increased
sales to residential and commercial customers. The decrease in mining
consumption is due to cutbacks in production by both of TEP's large mining
customers in response to lower copper prices. Milder summer temperatures
also reduced demand by retail customers. Cooling Degree Days decreased by 4%
in 2001, from 1,552 to 1,484 days. Revenue from sales to retail customers
increased by 1% in 2001 compared with 2000, reflecting the slight increase in
consumption.
Kilowatt-hour electric wholesale sales increased by 8% in 2001 compared
with 2000, while revenues increased by 104%. The largest increase in sales
and revenues was in forward contracts, which represents increased purchase
and resale transactions. Revenues also increased as a result of the
settlement of sales contracts that were established when market prices were
higher earlier in the year. Short-term economy sales in the daily and hourly
markets at higher market prices made it economical for TEP to run its gas
generation units to produce energy to sell to other regional utilities and
marketers during the first six months of 2001. Although kWh sales in the
short-term economy markets were lower in 2001 than 2000, revenues from these
sales were higher, due to higher average market prices in 2001. Factors
contributing to the higher market prices include increased demand due to
population and economic growth in the region, higher natural gas prices,
dysfunction in the California marketplace, increased maintenance outages due
to higher than normal operating levels, lower availability of hydropower
resources, transmission constraints, and environmental constraints.
OPERATING EXPENSES
2002 Compared with 2001
-----------------------
Fuel and Purchased Power expenses decreased by $527 million, or 66%, in
2002 compared with 2001. Fuel expense at TEP's generating plants decreased
by $49 million, or 19%, in 2002 primarily attributable to lower wholesale
demand, which resulted in decreased natural gas usage for generation, and
lower gas purchase prices. Contributing to higher gas purchase prices in
2001 was approximately $9 million in costs associated with two gas swap
agreements entered into in May 2001 to hedge the risk of price fluctuation.
Fuel expense in 2002 included $2.3 million related to an arbitration ruling
that increased the price of coal purchased between 1997 and May 2002 for the
Navajo Generating Facility. The average cost of fuel per kWh generated was
1.83 cents in 2002 and 2.12 cents in 2001. See Market Risks - Commodity
Price Risk.
Purchased Power expense decreased by $478 million, or 88%, due
principally to decreased volume of wholesale forward contract activity and
significantly lower wholesale prices. In the third quarter of 2001, TEP
incurred approximately $12 million in additional costs from several forward
purchase contracts that were entered into in May 2001 to assure service
reliability in the summer months. TEP paid an average price of $186 per MWh
for those forward contracts in 2001. TEP entered into similar contracts in
2002 at an average price of $37 per MWh. Forward purchase contract activity
decreased corresponding with the reduction in forward sales activity
discussed above.
TEP recorded an $11 million (pre-tax) charge in the third quarter of
1999;
-2002 as a result of terminating the Irvington long-term coal supply
agreement. This expense will be mitigated by TEP not being required to make
take-or-pay payments of up to $3.5 million annually. In July 2002, TEP
reversed the $2.4 million accrued portion of the 2002 take-or-pay penalty.
Despite the large decreases in Fuel and Purchased Power expenses, TEP's
gross margin (Operating Revenue less Fuel and Purchased Power expense)
decreased by $30 million or 5% in 2002 compared with 2001. This decline was
primarily due to decreased sales volumes and lower prices in the wholesale
energy markets.
Other Operations and Maintenance expense increased by $5 million, or 3%,
in 2002 compared with 2001, due primarily to a $2 million increase in pension
and post-retirement medical benefit costs and maintenance at the Four Corners
and Springerville generating stations.
Depreciation and Amortization expense increased by $7 million, or 6%, in
2002 compared with 2001. Depreciation expense increased due to depreciation
of solar generating facilities and a $125 million increase in the depreciable
asset base, which represents: (i) new line extensions to support new
business, (ii) the addition of a 75 MW gas turbine placed in-service in June
2001, and (iii) routine improvements to TEP's system. These increases were
partially offset by reduced depreciation resulting from a change in the
second quarter of 2002 to increase the estimated useful lives of gas-fired
generating units and internal combustion turbines located in Tucson. See
Note 6 of Notes to Consolidated Financial Statements. See Critical
Accounting Policies, below, for expected changes to depreciation expense
resulting from adopting Statement of Financial Accounting Standards No. 143
(FAS 143), Accounting for Asset Retirement Obligations.
Amortization of Transition Recovery Asset increased by $3 million, or
14%, in 2002 compared with 2001. The Transition Recovery Asset (TRA) and its
related amortization result from the Settlement Agreement reached with the
ACC in 1999. The Amortization of Transition Recovery Asset totaled $25
million in 2002, up from $22 million in 2001. Amortization amounts are
scheduled to increase annually until the entire TRA has been amortized, no
later than December 31, 2008. The monthly amount of amortization recorded is
a function of the remaining TRA balance and total retail kWh consumption by
TEP distribution customers.
2001 Compared with 2000
-----------------------
Fuel and Purchased Power expenses increased by $354 million, or 79%, in
2001 compared with 2000. Fuel expense at TEP's generating plants increased
by $19 million, or 8%, primarily because of higher natural gas prices and
increased usage of gas generation to meet increased kWh sales in the first
five months of 2001. This increase was partially offset by decreased usage
of gas generation in the last half of the year, as wholesale market prices
fell, making it less economical for TEP to run its gas generation units to
produce energy to sell to other regional utilities and marketers. Gas
expense also includes the new gas-fired peaking units, which went in-service
in June 2001, and the $9 million additional cost associated with gas swap
agreements we entered into in tax benefits recordedMay 2001. The average cost of fuel per kWh
generated was 2.12 cents in 2001 and 2.01 cents in 2000. See Market Risks,
Commodity Price Risk.
Purchased Power expense increased by $335 million, or 161%, because of
higher wholesale energy prices and increased purchases in the fourthforward and
spot energy markets to resell to wholesale customers. Purchased Power
expense remained high, even after wholesale market prices began to fall in
June 2001, due to the settlement of wholesale energy purchase contracts,
which were established when forward power prices were higher. Also, in May
2001, TEP entered into several forward purchase contracts to assure service
reliability in the summer months and to mitigate the risk of the potential
loss of 110 MW under an exchange agreement with SCE. The additional cost to
assure service reliability was approximately $12 million.
TEP recorded a $13 million pre-tax ($8 million after-tax) one-time
charge in the third quarter of 1999;
-2000 as a one-time $8 million after-tax expense related to the amendmentresult of a coal supply contract
amendment related to the San Juan Generating Station. See Note 10 of Notes
to Consolidated Financial Statements.
Despite the large increases in Fuel and Purchased Power expenses, TEP's
gross margin (Operating Revenue less Fuel and Purchased Power expense)
improved by $27 million or 5% in 2001 compared with 2000. This improvement
was primarily due to increased sales volumes and higher prices in the
wholesale energy markets.
Other Operations and Maintenance expense decreased by $4 million, or 3%
in 2001 compared with 2000. TEP established a reserve in 2000 for wholesale
energy sales to California, $7 million of which was recorded as an expense.
In contrast, in 2001, TEP recorded an additional reserve of $7 million in the
first quarter of 2001, of which $5 million was charged to expense, but
reversed $8 million in December. See Note 11 of Notes to Consolidated
Financial Statements. Various other production expenses increased by $4
million and maintenance expense increased by $2 million in 2001 compared with
2000. The higher Maintenance expense is the result of scheduled maintenance
at the Irvington, Springerville Unit 2 and San Juan generating plants.
The Amortization of Transition Recovery Asset totaled $22 million in
2001, up from $17 million in 2000.
INTEREST INCOME
TEP's income statement for both 2002 and 2001 includes interest income
of $9 million on its promissory note from UniSource Energy. See Note 1 of
Notes to Consolidated Financial Statements - Nature of Operations and Summary
of Significant Accounting Policies-Basis of Presentation. On UniSource
Energy's consolidated income statement, this income is eliminated as an
intercompany transaction.
Other Interest Income was $8 million higher in 2002 compared with 2001
due to TEP's additional $132 million investment in Springerville lease debt
in 2002.
Other Interest Income was higher in 2001 compared with 2000 due to
higher average cash balances and increased interest income on investments in
Springerville Unit 1 Lease Debt.
INTEREST EXPENSE
Interest Expense was $5 million, or 3% lower in 2002 than in 2001 due to
lower average interest rates on variable rate tax-exempt debt and lower debt
balances. In 2001, Interest Expense was $8 million or 5% lower than in 2000
for the same reasons. See TEP Credit Agreement, below, for the impact of
TEP's new Credit Agreement on future interest expense.
INCOME TAXES
Income taxes decreased $21 million in 2002 compared with 2001 due
primarily to lower pre-tax income, a $4 million tax benefit from the
reduction of the valuation allowance and the favorable settlement of an IRS
audit in the third quarter of 2000;2002, and $2 million in tax credits recognized
in 2002.
Income taxes increased $29 million in 2001 compared with 2000 as a
result of higher pre-tax income and the recognition of $6 million in tax
benefits in the second quarter of 2000 from the resolution of various IRS
audits.
See Note 10 of Notes to Consolidated Financial Statements - Commitments
and Contingencies.
RESULTS OF MILLENNIUM ENERGY BUSINESSES
The table below provides a breakdown of the impactnet income and losses
recorded by the Millennium Energy Businesses for the last three years. These
results exclude sales and related costs to TEP.
2002 2001 2000
- -------------------------------------------------------------------------------------------------
- Millions of Dollars -
Energy Technology Investments
Global Solar and IPS
Research & Development Contract Revenues from Third Parties $ 1.1 $ 1.7 $ 3.6
Research & Development Contract Expenses and Losses (3.4) (4.6) (4.9)
Research & Development - Internal Development Expenses (3.8) (4.0) (2.8)
Depreciation & Amortization Expense (2.9) (2.1) (1.0)
Administrative & Other Costs (13.2) (8.3) (4.5)
Income Tax Benefits 8.9 6.7 3.6
- -------------------------------------------------------------------------------------------------
Total Global Solar and IPS Net Loss (13.3) (10.6) (6.0)
MicroSat and ITN Energy Systems Inc. Net Loss (0.6) (3.3) -
- -------------------------------------------------------------------------------------------------
Total Energy Technology Investments Net Loss (13.9) (13.9) (6.0)
Nations Energy Net Income 0.4 4.5 0.7
Other Millennium Investments Net (Loss) Income (2.0) 0.2 1.2
- -------------------------------------------------------------------------------------------------
Total Millennium Loss, after-tax $(15.5) $ (9.2) $ (4.1)
=================================================================================================
Energy Technology Investments
-----------------------------
Global Solar is primarily engaged in the development of accounting changesthin-film
flexible photovoltaic material. These products are designed to be
lightweight and durable. Thin-film photovoltaic cells can be used for
military, commercial and space applications. IPS' business focus is the
development of thin-film solid state rechargeable batteries. Thin-film
batteries are intended to be used in various products including medical
devices, "smart cards" and semi-conductors. Global Solar's research and
development costs, the costs of refining Global Solar's manufacturing
processes to increase efficiency, and administrative costs all contributed to
Global Solar and IPS' after-tax losses of $13.3 million, $10.6 million and
$6.0 million in 2002, 2001 and 2000, respectively. In 2002 and 2001,
Millennium recorded after-tax losses relating to MicroSat and ITN Energy
Systems Inc. (ITN) of $0.6 million and $3.3 million, respectively. These
losses are related to the discontinuationdevelopment of FAS 71 regulatory accountingsmall-scale satellites and other
research and development activities.
Nations Energy
--------------
Nations Energy had minimal activity in 2002 as it is attempting to sell
its remaining investment, an interest in a project in Panama with a book
value of less than $1 million.
In 2001, Nations Energy sold its investment in a power project in
Curacao, resulting in an after-tax gain of $6 million. Nations Energy
received a promissory note as part of the sale. See Market Risks, Credit
Risk, below.
In 2000, Nations Energy sold a minority interest in a power project in
the Czech Republic for a pre-tax gain of $3 million. During 2000, Nations
Energy recorded decreases of $3 million in the market value of its Panama
investment. This was offset by a tax benefit of $3 million recorded in 2000
related to market value adjustments on the Panama investment.
Other Millennium Investments
----------------------------
Results from Other Millennium Investments in 2002 include an after-tax
loss of $2.2 million from Powertrusion. Powertrusion's efforts have been
focused on development and sale of lightweight utility pole products. MEG,
SES and TruePricing, Inc. (TruePricing), each recorded after-tax losses of
less than $1 million. These losses were offset by earned interest and a tax
benefit from final resolution of IRS audits.
In 2000, Millennium recorded net income of $1 million from interest
income on a note receivable received as part of the sale of NewEnergy to AES
Corporation in 1999.
RESULTS OF UED
UED, established in February 2001, recorded a net profit of $0.8 million
in both 2002 and 2001. This income represents rental income, less expenses,
under the operating lease of a 20 MW gas turbine to TEP through September
2002, when TEP purchased the turbine from UED. This rental income was
eliminated from UniSource Energy's consolidated after-tax earnings as an
intercompany transaction.
INCOME TAX POSITION
- -------------------
At December 31, 2002, UniSource Energy and TEP had, for consolidated
federal income tax filing purposes:
- $21 million of NOL carryforwards expiring in 2006 through 2009;
- $6 million of unused ITC expiring in 2003 through 2022; and
- $91 million of Alternative Minimum Tax credit that will carry forward
to future years.
We have recorded deferred tax assets and valuation allowances related to
these amounts. See Note 12 of Notes to Consolidated Financial Statements-
Income Taxes.
Due to the issuance of common stock to various creditors of TEP in 1992,
a change in TEP ownership was deemed to have occurred for tax purposes in
December 1991. As a result, TEP's generation operations in
November 1999.use of the NOL and ITC generated before
1992 is limited under the tax code. At December 31, 2002, pre-1992 federal
NOL and ITC carryforwards which are subject to the limitation were
approximately $21 million and $4 million, respectively. See Factors Affecting Results of Operations and Results of Operations,Critical
Accounting Policies Deferred Tax Valuation, below.
Outlook and Strategy
--------------------
Our financial prospects and outlookASSET PURCHASE AGREEMENTS
- -------------------------
On October 29, 2002, UniSource Energy entered into two Asset Purchase
Agreements with Citizens Communications Company (Citizens) for the next few yearspurchase
by UniSource Energy of Citizens' Arizona electric utility and gas utility
businesses for a total of $230 million in cash. The purchase price of each
is subject to adjustment based on the date on which the transaction is closed
and, in each case, on the amount of certain assets and liabilities of the
purchased business at the time of closing. If the transaction closes before
July 28, 2003, the purchase price is reduced by $10 million. If the
transaction closes after October 29, 2003, the purchase price is increased by
$5 million. In addition, the purchase price in each transaction may also be
adjusted if there is a casualty loss, governmental taking, or discovery of
substantial additional environmental liabilities, in each case subject to
materiality thresholds, prior to the closing. UniSource Energy will assume
certain liabilities associated with the purchased assets, but will not assume
Citizens' obligations under the industrial development revenue bonds issued
to finance certain of the purchased assets for which Citizens will remain
the economic obligor. The asset purchases are expected to close in the
second half of 2003 after the conditions to the consummation of the
transactions, including federal and state regulatory approvals, are satisfied
or waived.
The closing of the transactions is subject to approval by the ACC, the
FERC and the SEC under the Public Utility Holding Company Act of 1935, as
amended. The closing is also subject to the filing of the requisite
notification with the Federal Trade Commission and the Department of Justice
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and other
customary closing conditions.
The Asset Purchase Agreements are subject to termination if the closing
has not occurred within 15 months of the date of the Asset Purchase
Agreements (subject to extension in limited circumstances), if a governmental
authority seeks to prohibit the transactions, if required regulatory
approvals are not obtained with satisfactory terms and conditions, or if
either party is in material breach and such breach is not cured. If one
Asset Purchase Agreement is terminated, the other will also be automatically
terminated. If the Asset Purchase Agreements are terminated by Citizens due
to UniSource Energy's breach, UniSource Energy must pay to Citizens a $25
million termination fee as liquidated damages. If the Asset Purchase
Agreements are terminated by UniSource Energy due to Citizen's breach,
Citizens must pay to UniSource Energy a $10 million termination fee as
liquidated damages. The termination fees are also payable in certain other
limited circumstances.
Citizens had two cases pending before the ACC requesting rate relief for
both the Arizona electric and Arizona gas assets prior to entering into the
Asset Purchase Agreements with UniSource Energy. The requested electric rate
increase is to recover purchased power costs and the gas rate increase is a
base rate increase. In December 2002, UniSource Energy and Citizens filed a
Joint Application with the ACC requesting smaller increases in both pending
cases. Under the proposal, UniSource Energy asked that the 45% electric rate
increase requested by Citizens be reduced to 22%, and that the 29% increase
in gas rates be reduced to 23%. UniSource Energy believes that the smaller
proposed rate increases are sufficient in light of the discounted purchase
price. We are currently in settlement discussions with the ACC Staff and
intervenors regarding the Joint Application. The ACC Administrative Law
Judge (ALJ) set a hearing date of May 1, 2003 for this matter. We currently
anticipate the ACC to review this case and issue a decision by June 2003.
We expect that the purchase price will be affectedfinanced by many competitive, regulatoryfunds from
UniSource Energy and economic factors.
Our plansits affiliates and strategies includedebt secured by the following:
- Enhancepurchased assets.
TEP is limited by its Credit Agreement, however, as to the valueamount of
our transmission system while continuingaffiliate investments or loans it may make. See Liquidity and Capital
Resources, Financing Activities, TEP Credit Agreement, below. UniSource
Energy may also consider financing a portion of the purchase with new equity,
depending on market conditions and other considerations. UniSource Energy
expects to provide reliable accessform a new subsidiary to generation for our retail customers
and market access for all generatinghold the purchased assets. This new
subsidiary will include
focusing on completingmaintain a transmission lineseparate rate structure from TEP. If UniSource
Energy is unable to an electric
distribution company in Nogales, Arizona. This line could
eventually be connectedobtain financing and therefore fails to Mexico's utility system.
- Facilitateconsummate the
construction of Springerville Units 3 and 4, which
will allow us to spread over four units the fixed costs of TEP's
Springerville Units 1 and 2. This includes obtaining construction
financing in 2002.
- Reduce TEP's debt as appropriate, using some of our excess cash
flows. In addition to our required debt retirements, in the last
three years we invested $54 million in Springerville Unit 1 lease
debt and in January 2002, we invested $96 million in Springerville
Fuel Handling Facilities lease debt. We will continue to look for
opportunities to retire or refinance higher coupon debt and make
additional investments in lease debt.
- Proactively maintain our transmission and distribution system to
ensure reliable service to our retail customers.
- Efficiently manage our generating resources and look for ways to
reduce or control our operating expenses in order to improve
profitability. We added peaking resources in the Tucson area in
2001 and will continue to evaluate additional needs for 2002 and
beyond.
- Actively participate in the formation of regulatory policy and
actions, including reconsideration of the current requirement to
transfer TEP's generation assets to a wholly-owned subsidiary by
December 31, 2002.
- Focus the efforts of Millennium's technology entities primarily
to begin larger scale production of Global Solar Energy's thin-film
photovoltaic cells and develop thin-film battery technology. Seek
strategic partners and investors to achieve commercial operationpurchase of these businesses.
To accomplish our goals, we estimate that during 2002, TEP will
spend $124assets, this would constitute a breach under the contracts
and termination damages of $25 million on capital expenditures, Millennium will provide
at least $14 million of funding to its technology investments, and
we will provide between $30 million and $100 million in funding to
UED. Our funding to UED will depend upon the timing of the
financial close of the Springerville Unit 3 and 4 project and UED's
ultimate ownership percentage of the project. While we believe that
our plans and strategies will continue to have a positive impact on
our financial prospects and position, we recognize that we continue
towould be highly leveraged, and as a result, our access to the capital
markets may be limited or more expensive than for less leveraged
companies.payable.
FACTORS AFFECTING RESULTS OF OPERATIONS
- ---------------------------------------
COMPETITION
The electric utility industry has undergone significant regulatory
change in the last few years designed to encourage competition in the sale of
electricity and related services. However, the recent experience in
California with deregulation has caused many states, including Arizona, to
step back and reexamine the viability of retail electric deregulation.
As of January 1, 2001, all of TEP's retail customers were eligible to
choose an alternate energy supplier. Although there is one ESP certified to
provide service in TEP's retail service area, currently none of TEP's retail
customers have opted to receive service from this ESP. TEP has met all
conditions required by the ACC to facilitate electric retail competition,
including obtaining ACC approval of TEP's direct access tariffs. However, ESPs must
meet certain conditions before electricity can be sold competitively in
TEP's service territory. Examples of these include ACC certification of
ESPs, and execution of and compliance with direct access service agreements
with TEP.
TEP also competes against gas service suppliers and others who provide
energy services. Other forms of energy technologies, such as fuel cells, may
provide competition to TEP's services in the future, but to date, are not
financially viable alternatives. Self-
generationSelf-generation by TEP's large industrial
customers could also provide competition for TEP's services in the future,
but has not had a significant impact to date.
In the wholesale market, TEP competes with other utilities, power
marketers and independent power producers in the sale of electric capacity
and energy.
INDUSTRY RESTRUCTURING
RETAIL
TEP's Settlement Agreement and Retail Electric Competition Rules
----------------------------------------------------------------
In December 1996,September 1999, the ACC adoptedapproved Rules that provided a framework for
the introduction of retail electric competition in Arizona. These Rules, as amended and modified, were approved by the
ACC in September 1999. In November
1999, the ACC approved the Settlement Agreement between TEP and certain
customer groups relating to the implementation of retail electric
competition, including TEP's recovery of its transition recovery assets and
the unbundling of tariffs. The major provisionsSee Note 2 of theNotes to Consolidated Financial
Statements for more information on TEP's Settlement Agreement.
The Settlement Agreement as
approved, were:
- Consumer choice for energy supply began in 2000, and by January
1, 2001 consumer choice was available to all retail customers.
- After certain rate reductions implemented in 1998 through 2000,
TEP's retail rates are frozen until December 31, 2008, except under
certain circumstances.
- TEP's frozen rates include two Competition Transition Charge
(CTC) components designated for the recovery of its transition
recovery assets.
- A Fixed CTC component that equals a fixed charge per
kilowatt-hour sold; and
- A Floating CTC component that equals the amount of the
frozen retail rate less the price of retail electric
service.
- By June 1, 2004,originally required TEP will be required to file a general rate case
for its transmission and distribution business, including an updated
cost-of-service study.
- TEP is currently required to transfer its
generation and other competitive assets to a wholly-owned subsidiary by
December 31, 2002. The Settlement Agreement also requiresrequired that by December
31, 2002, TEP as the Utility Distribution Company (UDC) mustwould acquire at
least 50% of its requirements through a competitive bidding process, while
the remainder may be purchased under contracts with TEP's generation
subsidiary or other energy suppliers. Approval ofThese requirements were amended by the
Settlement Agreement caused TEP to
discontinue regulatory accounting under FAS 71 for its generation
operations in November 1999. See Note 2 of Notes to Consolidated
Financial Statements - Regulatory Matters.September 2002 ACC order described below.
Recent Developments in the Arizona Regulatory Environment
---------------------------------------------------------
In February 2002, the ACC consolidated several retail competition
mattersproceedings to reexamine circumstances that havehad changed since the ACC
adoptedapproved the Rules in 1996. In1999. The outstanding issues were divided into two
groups-"Track A" and "Track B" issues. Track A related primarily to the
divestiture of generation assets while Track B related primarily to the
competitive energy bidding process.
On September 10, 2002, the ACC issued the Track A Order, which
eliminated the requirement that TEP transfer its generating assets to a
letter dated January
14, 2002,subsidiary. At the same time, the ACC Chairman William Mundell suggested three possible
outcomes:
- Implementationordered the parties, including TEP, to
develop a competitive bidding process, and reduced the amount of power to be
acquired in the competitive bidding process to only that portion not supplied
by TEP's existing resources.
On February 27, 2003, the ACC issued the Track B Order, which defines
the process by which TEP will be required to obtain its capacity and energy
requirements beyond what is supplied by TEP's existing resources. For the
period 2003 through 2006, TEP estimates the amount it will be required to
bid for is 50,000 MWh of energy in 2003, or approximately 0.5% of its retail
load, gradually increasing to 104,000 MWh by in 2006.
TEP is also required to bid out its Reliability Must Run (RMR)
generation requirements, amounting to 758 MW of capacity and 183,000 MWh of
energy in 2003, and increasing to 898 MW and 276,000 MWh in 2006. TEP's RMR
generation requirements are currently met by its existng local generation
units. TEP does not anticipate that any near-term RMR requirements will be
met through this competitive bidding process because of the locational and
operational restrictions of TEP's RMR requirements as well as TEP's belief
that its existing RMR generation solutions are economically sound.
The Track B Order further requires TEP to bid out "Economy Energy", or
short-term energy purchases, that it estimates it will make in the 2003 to
2006 period (210,000 to 181,000 MWh). TEP will then evaluate if purchases
through this process will provide a better economic result than purchases
made as needed in the short-term markets.
TEP is not required to purchase any power through this process that it
deems to be uneconomical, unreasonable or unreliable. The Track B bidding
process will involve the ACC Staff and an independent monitor. The Track B
Order also confirms that it is not intended to change the current rate-base
status of TEP's existing assets.
TEP expects to issue requests for proposals in March 2003 and complete
the selection process by June 1, 2003.
As part of its reexamination of the Rules, accordingthe ACC had planned to
address the existing schedule,
- Delayedrequirement for Arizona electric utilities to participate in the
Arizona Independent Scheduling Administrator (AISA) organization. The Rules
originally required the formation and implementation of the RulesAISA; however,
the ACC opened a docket in July 2001 to provide an opportunity to
consider the extent to which Rule modificationrevisit this obligation. This issue
is pending and variance is in
the public interest, including changing the direction to retail
electric competition,
- Step back from electric restructuring until the Commission is
convinced that there exists a viable competitive wholesale electric
market to support retail electric competition in Arizona.
The ACC sent questions regarding retail competition issues to
stakeholders and required responses by February 25, 2002. An Open
Meeting, with opportunity for public comment, will be set. We
cannot predictaddressed separately from the outcome of these proceedings.
On January 28, 2002, TEP filed a request with the ACC for an
extension of the generation separation and the 50% competitive bid
requirements of its Settlement Agreement until the latter of
December 31, 2003 or six months after the ACC has issued a final
order in the current docket pertaining to electric restructuring
issues. TEP's filing was consolidated with the generic docket and a
procedural conference began on March 4, 2002.issues identified above.
The status of the Rules and the ability of ESPs to continue to sell
competitive services may also be subject to change due to recent court
proceedings. Several parties, including certain rural electric cooperatives
(Cooperatives), filed lawsuits in Maricopa County Superior Court challenging
the Rules, contending, among other
things, that allowing marketplace competition to determine rates
violated the ACC's constitutional duty to set rates.Rules. In November 2000, the Court found the Rules to be
unconstitutional and unlawful due to the failure of the Rules to establish a fair value rate
base for competitive ESPs and because certain of the Rules were not submitted for certification to the Arizona
Attorney General.General for certification. The Court also invalidated all ACC orders granting certificates of
convenience and necessity to competitive ESPs in Arizona.
The ACC, RUCO (Residential Utility Consumer Office) and certain
large industrial customers havedecision was appealed the decision to the Court
of Appeals. In addition, the Cooperatives filed a notice of cross
appeal of certain aspects of the decision. ImplementationAppeals and implementation of the judgment was stayed and the Rules remain
in effect pending the outcome of the appeals.
TEP cannot predict the effect of the recent court decision or the
outcome of these appeals to which it is a party or the effect of the
judgment, if affirmed upon appeal, on the introduction of retail electric
competition in Arizona.
State and Federal Legislation
-----------------------------
In 2001, federalthe current session, the state legislature will address a power plant
valuation proposal that will clarify the valuation methodology of centrally
assessed generation facilities and state legislative interest focused on the
California energy crisis. Federal legislators introduced several
pieces of legislation, but by year-end all momentum had been
refocused on national security issues.may affect TEP's property tax expense.
The Congress will debate the President's Clear Sky Initiative which
proposes a new regulatory regime for controlling power plant emissions. The
Congress will also consider legislation that proposes to expand the
regulatory authority of EPA in 2002 will
likely focus on administrative controls and oversightthe area of carbon dioxide. Proposed Federal
energy legislation has considered the implementation of a national renewable
portfolio standard of 10% of retail energy industry as a result of the Enron bankruptcy filing in December
2001.
The Arizona State legislature was also concerned with the
State's preparedness to meet growing electric demand. The siting
and construction of new generation and transmission facilities is
ongoing and closely monitoredsold by the legislature. The 2002
legislature is expected to review legislation to modify the
valuation of power plants within the state.certain utilities.
WESTERN ENERGY MARKETS
As a participant in the western U.S. wholesale power markets, TEP is
directly and indirectly affected by changes affecting these markets and
market participants. DuringIn 2000 and 2001, a significant portion of TEP's
revenues and earnings resulted from its wholesale marketing activities, which
benefited from strong demand and high wholesale prices in the western U.S.
These market conditions were the result of a number of factors, including
power supply shortages, high natural gas prices, transmission, and
environmental constraints. During this period, these markets experienced
unprecedented price volatility, bankruptciesas well as payment defaults and payment defaultsbankruptcies
by several of its largest participants, and
increased attention and intervention by regulatoryparticipants. Regulatory agencies became concerned
with the outcomes of deregulation of the electric power industry.
Ratesindustry and
intervened in the operation of these markets.
In the last 18 months, conditions in the western energy markets have
changed significantly as a result of various regulatory actions, moderate
weather, a decrease in natural gas prices, the addition of new generation in
the region, and the slowdown of the regional economy. In addition, the
presence of fewer creditworthy counterparties, as well as legal, political
and regulatory uncertainties have reduced market liquidity and trading
volume. Several companies that were large market participants have either
curtailed their activities or exited the business completely. These factors
placed downward pressure on wholesale electricity prices, and resulted in
significantly lower wholesale electricity sales and revenues at TEP in 2002.
Market Prices
-----------------------
In-------------
The chart below shows the Fall of 1997, FERC granted TEP a tariff to sell at
market-based rates. Prior to that, the FERC set rates in formal
proceedings that generally did not exceed cost of service. With
respect to wholesale power sold during 1998quarterly and 1999, TEP's
wholesale rates were generally substantially below rates determined
on a fully allocated cost of service basis, but, in all instances,
rates exceeded the level necessary to recover fuel and other
variable costs. During 2000 and 2001, rates earned on wholesale
sales in the short-termannual average market generally equaled or exceeded rates
determined on a fully allocated cost of service basis. Wholesale
sales on long-term contracts entered into prior to 1998 continued to
be at rates below fully allocated costs, but recovered the cost of
fuel and other variable costs.
In the 2001 wholesale power market, wholesale prices in
the
forward, day-ahead2002, 2001, and real-time (hourly) markets typically exceeded
TEP's total cost of service. The average market price2000 for around-
the-clockaround-the-clock energy based on the Dow Jones Palo
Verde Index was $94 perIndex:
Average Market Price for Around-the-Clock Energy 2002 2001 2000
--------------------------------------------------------------------------
MWh
Quarter ended March 31, $24 $178 $ 27
Quarter ended June 30, 24 135 65
Quarter ended September 30, 28 40 124
Quarter ended December 31, 31 23 129
Year ended December 31, 26 94 86
--------------------------------------------------------------------------
Beginning in 2001, compared with $87 per MWh in 2000. TheJune 2001, average market prices declined sharply,
returning to historical price represents a steep decline, however, from $156 per MWh inlevels throughout 2002. In the first half of 2001 to $23 per MWh in the fourth quarter
of 2001.
This reduction was2003, however, both the natural gas and western U.S. wholesale electricity
markets have experienced some price spikes and volatility due to a number of factors, including more
generation onlinesevere
winter weather in the western U.S., lower naturalcertain regions, as well as high gas prices,
increased hydropower supply, and weaker demand.storage withdrawals
due to lagging production. As of February
2002,March 2003, the average forward around-the-clockaround-the-
clock market price for the balance of the year 20022003 was approximately $27$51 per
MWh, based on the
Dow Jones Palo Verde Index. As a result, we expect ourforward broker market quotes. TEP cannot predict, however,
whether average wholesale revenues to be significantly lowerelectricity prices will remain higher than in 2002
than in 2001. A large
portion of ourand what the impact will be on TEP's sales and revenues in 2001 were from sales contracted at higher
prices in the first half of the year that settled in the second half
of the year. Therefore, we continued to benefit from the higher
prices in the second half of the year even though market prices had
declined. We cannot predict whether these lower prices will
continue, or whether changes in various factors that influence
demand and capacity will cause prices to rise again during the
remainder of 2002.
We expect2003.
TEP expects the market price and demand for capacity and energy to
continue to be influenced by the following factors, among others, during the
next few years:
- continued population growth andin the western U.S.;
- economic conditions in the western U.S.;
- availability of capacity throughout the western U.S.;
- the extent of electric utility industry restructuring in Arizona,
California and other western states;
- the effect of FERC regulation of wholesale energy markets;
- the availability and price of natural gas;
- precipitation, which affects hydropower availability;
- transmission constraints; and
- environmental restrictions and the cost of compliance.
Payment Defaults and Allowances for Doubtful Accounts
-----------------------------------------------------
In early 2001, California's two largest utilities, SCE and PG&E,Pacific Gas &
Electric Company (PG&E), defaulted on payment obligations owed to various
energy sellers, including the CPXCalifornia Power Exchange (CPX) and the CISO.
The CPX and the CISO defaulted on their payment obligations to market
participants, including TEP. PG&E and CPX filed for protection under Chapter 11 of the U.S.
Bankruptcy Code.While SCE has remained out of bankruptcy but in a
weakened financial condition. SCE has publicly disclosed that on
March 1, 2002, SCE obtained financing and made payments so that they
have no material undisputedsubsequently satisfied its
obligations that are past due or in
default. These payments included a payment to the CPX. However,CPX, TEP didhas not correspondingly receivereceived a corresponding payment from the
CPX. PG&E
has filed a plan of reorganization which provides for payment of
all creditors on or around January 1, 2003. The plan requires various
approvalstotal amount owed to TEP by the CPX and numerous parties have expressed opposition to the plan.
On December 2,CISO is $16 million. In
late 2001, Enron Corp. (Enron) filed for protection under Chapter
11 of the U.S. Bankruptcy Code.bankruptcy protection. At thethat
time, of the bankruptcy
filing, TEP had an outstanding receivable from Enron of $0.8 million from Enron
for power delivered in November 2001, as well as certain forward
contracts for the delivery of power through June 2002. The bankruptcy
filing constitutedmillion. TEP has
established an event of default under TEP's contracts with Enron.
Therefore, TEP suspended all trading activities and terminated all
contracts with Enron.
As a result of payment defaults made by market participants in
California and by Enron, TEP established allowancesallowance for doubtful accounts.accounts of $8 million related to these
payment defaults.
See Critical Accounting Policies - Payment Defaults and Allowances for
Doubtful Accounts, below, and Note 11 of Notes to Consolidated Financial
StatementsStatements.
California Refund Proceedings
-----------------------------
On June 25, 2001, a FERC ALJ convened a settlement conference to address
potential refunds owed by sellers of energy into the California market.
California claims that it was overcharged up to $9 billion for wholesale
power purchases since May 2000, and is seeking refunds from numerous power
generators, including TEP. The settlement conference, which included
representatives from over 100 parties and participants in the western power
market, including the State of California and power generators, was
unsuccessful. On July 25, 2001, the FERC ordered hearings to determine
refunds/offsets applicable to wholesale sales into the CISO's spot markets
for the period from October 2, 2000 to June 20, 2001. The order established
a methodology to calculate the amount of refunds and specified that the price-
mitigation formula contained in its June 19, 2001 order be applied to the
period from October 2, 2000 to June 20, 2001.
In August 2002, the FERC staff proposed revised calculations to
determine amounts due from the CPX and the CISO, based on concern that
natural gas prices were manipulated. If TEP were to apply these proposed
adjustments to amounts due to TEP, TEP could receive as little as $4 million,
plus interest, of the amounts due from the CPX and the CISO. The FERC has
not yet confirmed or rejected the calculation proposed by its staff. Under
earlier calculations proposed by the FERC staff, TEP could receive up to $11
million plus interest. The ALJ has issued a proposed finding under which TEP
would receive approximately $8.4 million, plus interest. This represents
amounts owed to TEP net of TEP's estimated refund liability. FERC is
accepting additional information and is expected to issue a ruling on the
recommended order later in 2003.
TEP is not able to predict the length and outcome of the FERC hearings
and the outcome of any subsequent lawsuits and appeals that might be filed.
As a participant in the June 2001 refund proceedings, TEP will be subject to
any final refund orders. TEP does not expect its refund liability, if any,
to have a significant impact on the financial statements. See Critical
Accounting Policies - Payment Defaults and Allowances for Doubtful Accounts,
below.
SCE Power Exchange Agreement
----------------------------
A power exchange agreement betweenMarket Manipulation Investigations
----------------------------------
In May 2002, the FERC initiated an investigation into potential
manipulation of the California electric and natural gas markets. The FERC
requested specific data and information with respect to certain trading
strategies in which companies may have engaged. This request was made to
all sellers of wholesale electricity and/or ancillary services, including
TEP, to the CISO and/or the CPX during 2000 and SCE requires SCE2001. In May 2002, TEP
responded to provide firm system capacitythe FERC, certifying that TEP did not engage in any of 110 MW to TEP during summer months.
TEP is then obligated to return to SCEthe
trading activities listed in the winter months the same
amount of energy that TEP received from SCEdata request during the preceding
summer. Since 1995, TEP has relied upon this 110 MW from SCE.
During 2000 and 2001, volatility2001. TEP also
certified that it had not in the westernpast, nor does it now, model or forecast
California's energy markets and did not purchase energy from, or sell energy
to, any company as part of any of the deterioration in SCE's financial condition created uncertainty
for TEP regardingtypes of potentially market manipulative
transactions as identified by the availability of this resource for TEP's summer
peaking needs. Except for a few occasions inFERC during 2000 and 2001, SCE
provided TEP with requested energy under the power exchange
agreement. Since June 2001, western power markets have stabilized
and SCE's financial condition appears to be improving. As such, we
believe that there is more certainty to the availability of this
resource for TEP in the summer of 2002. Nevertheless, TEP plans to
make forward purchases of approximately 50 MW for the summer peaking
season to mitigate the risk of loss of this or other resources.2001.
MARKET RISKS
We are exposed to various forms of market risk. Changes in interest
rates, returns on marketable securities, and changes in commodity prices may
affect our future financial results.
For additional information concerning risk factors, including market
risks, see Safe Harbor for Forward-Looking Statements, below.
Interest Rate Risk
------------------
TEP is exposed to risk resulting from changes in interest rates on
certain of its variable rate debt obligations. At December 31, 20012002 and
2000,2001, TEP's debt included $329 million of tax-exempt variable rate debt. The
average interest rate on TEP's variable rate debt (excluding letter of credit
fees) was 1.41% in 2002 and 2.68% for 2001in 2001. TEP also has approximately $70
million in outstanding principal amount of variable rate lease debt related
to its Springerville Common Facilities Leases. Interest on this lease debt
is payable at LIBOR plus 2.50%. The average interest rate on this lease debt
was 5.14% in 2002 and 4.17% for 2000.8.63% in 2001. A one percent increase (decrease) in
average interest rates would result in a decrease (increase) in TEP's pre-tax
net income of approximately $3$4 million. See Note 8 of Notes to Consolidated Financial Statements -
Fair Value of UniSource Energy Financial Instruments.
Marketable Securities Risk
--------------------------
TEP and Millennium areis exposed to fluctuations in the return on its marketable
securities, which arecomprised of investments in debt securities. At December 31,
20012002 and 2000,2001, TEP had marketable debt securities with an estimated fair
value of $74$196 million and $76 million, which$74 million. At December 31, 2002 and 2001, the
fair value exceeded the carrying value by $4 million and $3 million,
and $7 million,
respectively. At December 31, 2001, Millennium had no marketable
debt securities, and at December 31, 2000, had marketable debt
securities with an estimated fair value of $2 million and a carrying
value of $2 million. These debt securities represent TEP's and
Millennium's investments in lease
debt underlying certain of TEP's capital lease obligations. In 2001, TEP purchased from Millennium
the $2 million in debt securities it owned at December 31, 2000. Changes in the
fair value of such debt securities do not present a material risk to TEP, as
TEP intends to hold these investments to maturity.
As of December 31, 2001, TEP had an investment in an undivided
ownership interest with an estimated fair value of $13 million and a
carrying value of $13 million. This ownership interest represents
the investment in Springerville Coal Handling Facilities made by TEP
in December 2001. See Note 8 of Notes to Consolidated Financial
Statements, Fair Value of UniSource Energy Financial Instruments.
Risk Management Committee
-------------------------
We have a Risk Management Committee which is responsible for the oversight of
commodity price risk and credit risk related to the wholesale energy
marketing activities of TEP and the emissions allowance and coal trading
activities of MEG. Our Risk Management Committee consists of officers with responsibility forfrom
the finance, accounting, legal, wholesale marketing, and the generation
operations departments of UniSource Energy. To limit ourTEP and MEG's exposure
to commodity price risk, the Risk Management Committee approvessets trading policies
and limits, which are reviewed frequently to respond to constantly changing
market conditions. To limit ourTEP and MEG's exposure to credit risk in these
activities, the Risk Management Committee approvesreviews counterparty credit
exposure, as well as credit policies and limits, and reviews counterparty credit exposure on a monthly basis.
Commodity Price Risk
--------------------
We are exposed to commodity price risk primarily relating to changes in
the market price of electricity, natural gas, coal and emissions allowances.
To manage its exposure to energy price risk, TEP enters into forward
contracts to buy or sell energy at a specified price andfor a future delivery
period. Generally, TEP commits to future sales based on expected excess
generating capability, forward prices and generation costs, using a
diversified market approach to provide a balance between long-term, mid-term
and spot energy sales. Similarly, TEP enters into forward purchases during its summer
peaking period to ensure it can meet its load and reserve requirements and
account for other contract and resource contingencies. TEP also enters into
limited forward purchases and sales to optimize its resource portfolio and
take advantage of locational differences in price. These positions are
managed on both a volumetric and dollar basis and are closely monitored using
risk management policies and procedures with oversightoverseen by the Risk Management
Committee. For example, the risk management policies provide that TEP should not
take a short position in the third quarter and shouldmust have supplyowned generation
backing up all forward sales positions.
TEPpositions at the time the sale is made. TEP's risk
management policies also entersrestrict entering into limited forward purchases and sales to
take advantage of market price changes with the intent to reverse
the forward positions at a profit. These typeswith
maturities extending beyond the end of transactionsthe next calendar year.
The majority of TEP's forward contracts are considered to be our trading positions."normal
purchases and sales" of electric energy and are not considered to be
derivatives under Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities (FAS 133).
TEP records revenues on its "normal sales" and expenses on its "normal
purchases" in the period in which the energy is delivered. From time to
time, however, TEP enters into forward contracts that meet the definition
of a derivative under FAS 133. When TEP has derivative forward contracts, it
marks its trading
positionsthem to market on a daily basis using actively quoted prices obtained
from brokers for power traded over-the-counter at Palo Verde for forward periods of up to five years. As of December 31,
2001, all of TEP's forwardand at other
southwestern U.S. trading contracts were for settlement
within twelve months. TEP's trading policies restrict forward
trading positions to mature no longer than the end of the next
calendar year. Because of the short-term duration ofhubs. TEP believes that these trading
positions, we believe that the market is liquid and that the various broker quotations
used to calculate the mark-to-market values represent accurate measures of
the fair values of these positions.
An unrealized lossTEP's positions, because of $0.5 million was recorded onthe short-term nature of TEP's
balance
sheetpositions, as of December 31, 2001 to adjustlimited by risk management policies, and the value of its trading
positions to fair value.
Unrealized Gain (Loss) of TEP's Contracts
- Millions of Dollars -
----------------------------------------------------------
Source of Fair Value Maturity Maturity Maturity over Total Unrealized
At December 31, 2001 0 - 6 mos. 6 - 12 mos. 1 yr. Gain (Loss)
- --------------------------------------------------------------------------------------
Prices actively quoted $(0.5) - - $(0.5)
Prices provided by other
external sources - - - -
Prices based on models and
other valuation methods - - - -
The following chart shows the changesliquidity in the
fair value of TEP'sshort-term market. When TEP has derivative forward contracts, from January 1, 2001 to December 31, 2001, and quantifies the
reasons for the changes. Our definitions of Trading Activity and Cash
Flow Hedges, as used in this chart, are included in Note 3 of Notes to
Consolidated Financial Statements - Accounting for Derivative Instruments
and Hedging Activities.
Unrealized Gain (Loss)
----------------------
Cash
Trading Flow
Activity Hedges Total
- ---------------------------------------------------------------------------------------
- Millions of Dollars -
Unrealized gain (loss) of contracts as of January
1, 2001 $ 0.8 $(23.0) $(22.2)
Less contracts settled (realized) during 2001:
Related to trades entered in prior years (4.0) 18.6 14.6
Related to trades entered in 2001 (8.5) 18.2 9.7
Change in fair value attributable to market changes:
Related to trades entered in prior years 3.2 4.4 7.6
Related to trades entered in 2001 8.0 (18.2) (10.2)
- ---------------------------------------------------------------------------------------
Unrealized gain (loss) of contracts as of December
31, 2001 (1) $(0.5) - $ (0.5)
=======================================================================================
(1) The unrealized loss is recorded as a liability on the balance sheet.
The unrealized gain (loss) of new contracts on the date they are
entered into is generally zero, because they are entered into at current
market prices.
TEPit uses a
sensitivity analysis to measure the impact of an unfavorable change in market
prices on the fair value of its trading
positions.derivative forward contracts. As of December
31, 2002, TEP had no forward contracts that are considered derivatives. TEP
had no unrealized gain or loss on its December 31, 2002 balance sheet. TEP
had a cumulative unrealized loss of $0.5 million on its December 31, 2001
a 10% unfavorable change inbalance sheet, which was reversed during 2002 as the market prices of electric power from year-end levels would have
decreasedcontracts settled. This
demonstrates the fair value of these instrumentslimited derivative forward contract activity conducted by
less than $1
million. Beginning in 2001, changes inTEP and the fair value of these
derivative instruments are measured in ourlimited impact on TEP's operating results and financial
statements in
accordance with FAS 133. See Note 3 of Notes to Consolidated
Financial Statements and Accounting for Derivative Instruments and
Hedging Activities, below.condition.
During the fourth quarter of 2001, we entered into the business
ofMEG began managing and trading
emission allowances, coal and other
environmental related products, including financial instruments
through MEG, a wholly-owned subsidiary of Millennium.instruments. We manage the market risk
of this new line of business by setting notional limits by product, as well as
limits to the potential change in fair market value under a hypothetical 33% change in
price or volatility. We closely monitor MEG's trading activities, are closely monitoredincluding
swap agreements, options and forward contracts, using risk management
policies and procedures with oversightoverseen by the Risk Management Committee. MEG marks
its trading positions to market on a daily basis using actively quoted prices
obtained from brokers.brokers and options pricing models for positions that extend
through 2005. As of December 31, 2002, the fair value of MEG's trading
positions combined with emissions allowances it holds in escrow was $0.2
million. At December 31, 2001, the fair value of MEG's trading positions was
less than($0.1) million. During 2002, MEG had a $0.2 million unrealized gain and a
$0.1 million.
TEP experienced increased commodity price risk during the third
quarter of 2001, due to uncertainty regarding availability of a
power resource from the SCE Power Exchange. (See Western Energy
Markets, SCE Power Exchange Agreement, above.) To mitigate the risk
that this resource would be unavailable to TEP, and/or the risk of
other unexpected losses of generation resources due to unplanned
outages or natural disasters, TEP purchased energymillion realized loss on a forward
basis to protect its retail customers from power interruptions for
the summer of 2001. TEP also relied upon two new peaking units
which went in-service in June 2001, interruptible contracts, load-
shifting by large mining customers, and reserve sharing arrangements
with other utilities as resources. Under the terms of its
Settlement Agreement, TEP's retail rates are frozen through December
31, 2008, except under certain circumstances. As such, TEP cannot
recover increased purchased power costs without further ACC action.
See Competition - Retail, above.income statement.
Unrealized Gain (Loss) of MEG's Trading Activities
- Millions of Dollars -
----------------------------------------------------------
Source of Fair Value Maturity Maturity Maturity over Total Unrealized
At December 31, 2002 0 - 6 mos. 6 - 12 mos. 1 yr. Gain (Loss)
- --------------------------------------------------------------------------------------
Prices actively quoted $(0.8) $(0.2) $3.6 $ 2.6
Prices provided by other
external sources - - - -
Prices based on models and
other valuation methods (1.7) (0.7) - (2.4)
- --------------------------------------------------------------------------------------
Total $(2.5) $(0.9) $3.6 $ 0.2
======================================================================================
TEP also purchases coal and natural gas in the normal course of business
forto fuel for its generating plants. TEP acquiresThe majority of its coal supplies are
purchased under long-term coal supply contracts. Purchasescontracts, which result in very predictable prices.
TEP's usage of natural gas to fuel generating plants has historically providedcomprised
less than 5% of its generation output and 2% of its total fuel for only 3-4%costs. This
historical natural gas usage has been to meet the summer peak demands of its
firm electric wholesale and retail customers and transmission import
requirements. Natural gas usage to meet these demands is expected to
increase at approximately 1% - 2% of total generation.
Beginninggeneration output per year. Due
to its limited and historically seasonal usage of natural gas for firm
electric wholesale and retail customers, TEP typically purchases its gas
needs in the third quarterspot and short-term markets. In 2002, natural gas fueled 6% of
2000 through Juneour total generation output and resulted in $32 million of fuel expense,
compared with 9% gas usage and $76 million in expense in 2001. The higher
usage and costs during 2001 however,are primarily the sustained high levelsresult of strong wholesale
energypower markets and higher natural gas prices in the western
U.S. made it profitable for TEP to fuel its gas-fired generating
units more frequently to sell into the wholesale market. As a
result, during 2001, approximately 9% of TEP's generation was
fueled by natural gas. Market prices of natural gas also increased
in the latter part of 2000 and the first six months of 2001, before
beginning to fall in the third quarterhalf of 2001.
These high market
prices, combined with increased gas usage, resulted in gas expense
comprising 29% of total fuel expense for 2001 compared with 25% in
2000. TEP is assured ofobtains its gas supply as a retail customer of the local gas
supplier.supplier, Southwest Gas Corporation (SWG). TEP periodically negotiates its
contract with its gas supplier to establish terms relating to pricing and
scheduling of gas delivery. TEP also entered into two swapfixed price gas purchase
agreements in May 2001and June 2002 to hedge ourits risk of fluctuations in the
market price of gas related tofor June through October 2002. The agreements covered
approximately a third30% of ourTEP's anticipated gas purchases for that period. SWG is
affected by recent FERC actions relating to its gas allocations from Junethe San
Juan and Permian basins. A FERC order is expected on this issue in the
summer of 2003, and at that time, TEP will renegotiate its gas supply and
transportation agreement with SWG. In the interim, TEP and SWG have agreed
on an extension of the current contract terms through October 2001. See
Results of Operations - Operating Expenses, below.31, 2003. TEP
does not anticipate any material difference in operational or economic terms
in the new agreement, which is estimated to begin November 1, 2003.
Credit Risk
-----------
UniSource Energy is exposed to credit risk in its energyenergy-related
marketing and trading activities related to potential nonperformance by
counterparties. We manage the risk of counterparty default by performing
financial credit reviews, and setting limits and monitoring exposures, requiring
collateral when needed, and using a standardized agreement which allows for
the netting of current period exposures to and from a single counterparty.
Despite such mitigation efforts, there is a potential for defaults by
counterparties to occur from time to time. In the fourth quarter of 2000 and
the first quarter of 2001, TEP was affected by payment defaults by SCE and
PG&E for amounts owed to the CPX and CISO. In the fourth quarter of 2001,
Enron defaulted on amounts owed to TEP for energy sales.
We calculate counterparty credit exposure by adding any outstanding
receivable (net of amounts payable if a netting agreement exists) to the mark-to-marketmark-
to-market value of any forward contracts. As of December 31, 2001,2002, TEP's
total credit exposure related to its wholesale tradingmarketing activities
(excluding defaulted amounts owed by the CPX, the CISO and Enron), was less
than $10$7 million of
which 98% was with counterparties with investment grade ratings. At
December 31, 2001,and MEG's total credit exposure related to its trading
activities was nominal due$7 million. TEP and MEG's credit exposure is diversified
across approximately 26 counterparties. Approximately $1 million of exposure
is to non-investment grade companies.
UniSource Energy is also exposed to credit risk related to the start-up naturesale of
assets owned by Nations Energy. In September 2001, Nations Energy sold its
26% equity interest in a power project located in Curacao, Netherland
Antilles to a subsidiary of Mirant Corporation (Mirant). Nations Energy
received $5 million in cash proceeds and recorded an $11 million note
receivable from the sale at its net present value of $8 million, with the
discount amortized to interest income over the five-year life of the business. Basednote.
The note is guaranteed by Mirant Americas, Inc., a subsidiary of Mirant.
Payments on the note receivable are expected as follows: $2 million in July
2004, $4 million in July 2005, and $5 million in July 2006.
In October 2002, the major rating agencies downgraded the ratings of
Mirant and certain of its subsidiaries citing Mirant's significantly lower
operating cash flow relative to its debt burden coupled with the likelihood
that future operating cash flow levels may weaken further. Their ratings are
now below investment grade. As of December 31, 2002, Nations Energy's
receivable from Mirant is approximately $9 million. We cannot predict what
effect the downgrade of Mirant will have on its ability to make its required
payments to Nations Energy when due, beginning in July 2004. Nations Energy
has not recorded an allowance for doubtful accounts and we will continue to
evaluate whether any further ratings events or actions by Mirant will impact
the collectibility of the receivable.
OUTLOOK AND STRATEGIES
Our financial prospects and outlook for the next few years will be
affected by many competitive, regulatory and economic factors. Our plans and
strategies include the following:
- Complete the Arizona electric utility and gas utility asset
acquisition from Citizens described above.
- Facilitate the construction of Springerville Unit 3, which will allow
TEP to spread the fixed costs of its Springerville Units 1 and 2 Common
Facilities over an additional unit.
- Enhance the value of TEP's transmission system while continuing to
provide reliable access to generation for TEP's retail customers and
market access for all generating assets. This will include focusing on
completing the Tucson - Nogales transmission line, which could
eventually be connected to Mexico's utility system, and completing a reviewnew
one mile 500-kV line to enhance TEP's distributin system's link to the
regional high voltage transmission system.
- Improve production of Global Solar's thin-film photovoltaic cells and
seek strategic partners.
- Reduce TEP's debt as appropriate, using some of our credit exposuresexcess cash flows.
Although no specific retirements are planned at December 31, 2001,this time, TEP expects
to use $30 million to $50 million annually for debt reductions.
- Efficiently manage TEP's generating resources and look for ways to
reduce or control our operating expenses in order to improve
profitability.
To accomplish our goals, we do not anticipate any
nonperformance by anyestimate that during 2003, TEP will spend
$121 million on capital expenditures, Millennium will provide between $7
million and $15 million of funding to its Energy Technology Investments, and
we will provide between $4 million and $50 million in funding to UED. Our
funding to UED will depend upon the timing of the financial close of the
Springerville expansion project and UED's ultimate ownership percentage. In
addition, we plan to pay $230 million for the acquisition of the Arizona
electric utility and gas utility assets from Citizens.
While we believe that our other counterparties. See Critical
Accounting Policies - Payment Defaultsplans and Allowancesstrategies will continue to have a
positive impact on our financial prospects and position, we recognize that we
continue to be highly leveraged, and as a result, our access to the capital
markets may be limited or more expensive than for Doubtful
Accounts, below.less leveraged companies.
CRITICAL ACCOUNTING POLICIES
- ----------------------------
In preparing financial statements under GAAP,Generally Accepted Accounting
Principles (GAAP), management exercises judgementjudgment in the selection and
application of accounting principles, including making estimates and
assumptions. WeUniSource Energy and TEP consider Critical Accounting Policies
to be those that could result in materially different financial statement
results if our assumptions regarding application of accounting principles
were different. WeUniSource Energy and TEP describe our Critical Accounting
Policies below. Other significant accounting policies and recently issued
accounting standards are discussed in Note 1 of Notes to Consolidated
Financial Statements - Nature of Operations and Summary of Significant
Accounting Policies.
ACCOUNTING FOR RATE REGULATION
TEP generally uses the same accounting policies and practices used by
unregulated companies for financial reporting under GAAP. However, sometimes
these principles, such as FASStatement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation (FAS 71), require
special accounting treatment for regulated companies to show the effect of
regulation. For example, in setting TEP's retail rates, the ACC may not allow
TEP to currently charge its customers to recover certain expenses, but instead
requires that these expenses be charged to customers in the future. In this
situation, FAS 71 requires that TEP defer these items and show them as
regulatory assets on the balance sheet until TEP is allowed to charge its
customers. TEP then amortizes these items as expense to the income statement
as those charges are recovered from customers. Similarly, certain revenue
items may be deferred as regulatory liabilities, which are also eventually
amortized to the income statement as rates to customers are reduced.
The conditions a regulated company must satisfy to apply the accounting
policies and practices of FAS 71 include:
- an independent regulator sets rates;
- the regulator sets the rates to cover specific costs of delivering
service; and
- the service territory lacks competitive pressures to reduce rates
below the rates set by the regulator.
In November 1999, upon approval by the ACC of TEP's Settlement Agreement
relating to recovery of TEP's transition costs and standard retail rates, we
stopped applying FAS 71 to our generation operations.
We continueTEP continues to apply FAS 71 in accounting for the distribution and
transmission portions of TEP's business, ourits regulated operations. WeTEP
periodically assessassesses whether weit can continue to apply FAS 71. If weTEP stopped
applying FAS 71 to TEP'sits remaining regulated operations, weTEP would write off
the related balances of TEP's regulatory assets as a charge in ourthe income
statement. Based on the balances of TEP's regulatory assets at December 31,
2001,2002, if weTEP had stopped applying FAS 71 to TEP's remaining regulated
operations, weTEP would have recorded an extraordinary loss, after-tax, of
approximately $245$233 million. OurTEP's cash flows would not be affected if weTEP
stopped applying FAS 71 unless a regulatory order limited ourits ability to
recover the cost of that regulatory asset.assets.
See Note 2 of Notes to Consolidated Financial Statements - Regulatory
Matters.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In 1998,ASSET RETIREMENT OBLIGATIONS
FAS 143 requires entities to record the Financial Accounting Standards Board (FASB) issued
Statementfair value of Financial Accounting Standards No. 133 (FAS 133),
Accountinga liability for Derivative Instruments and Hedging Activities.a
legal obligation to retire an asset in the period in which the liability is
incurred. A derivative financial instrumentlegal obligation is a liability that a party is required to
settle as a result of an existing or other contract derives its value
from another investmentenacted law, statute, ordinance or
designated benchmark. Becausecontract. When the liability is initially recorded, the entity should
capitalize a cost by increasing the carrying amount of the complexityrelated long-lived
asset. Over time, the liability is adjusted to its present value by
recognizing accretion expense as an operating expense in the income statement
each period, and the capitalized cost is depreciated over the useful life of
derivatives, the FASB establishedrelated asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a Derivatives
Implementation Group (DIG). During 2001,gain or loss if
the DIG issued new
guidance, which changedactual costs differ from the contracts that qualifiedrecorded amount.
Prior to adopting FAS 143, costs for final removal of all owned
generation facilities were accrued as derivatives
underan additional component of depreciation
expense. Under FAS 133.
When we adopted143, only the costs to remove an asset with legally
binding retirement obligations will be accrued over time through accretion of
the asset retirement obligation and depreciation of the capitalized asset
retirement cost.
TEP will adopt FAS 133143 on January 1, 2001, some2003, as required. TEP has
identified legal obligations to retire generation plant assets specified in
land leases for its jointly-owned Navajo and Four Corners generating
stations. The land on which the Navajo and Four Corners generating stations
reside is leased from the Navajo Nation. The provisions of the forward
contractsleases
require the lessees to remove the facilities upon request of the Navajo
Nation at the expiration of the leases. TEP also has certain environmental
obligations at the San Juan generating station. TEP has estimated that we usedits
share of the cost to buyremove the Navajo and sell wholesale powerFour Corners facilities and settle
the San Juan environmental obligations is approximately $38 million at the
date of retirement. No other legally binding retirement obligations for
generation plant assets were consideredidentified. Millennium and UED have no asset
retirement obligations.
TEP has various Transmission and Distribution lines that operate under
various land leases and rights of way that contain end dates and restorative
clauses. TEP operates its Transmission and Distribution lines as if they
will be operated in perpetuity and would continue to be derivatives based onused or sold without
land remediation. As a result, TEP will not recognize the accounting guidance at
that time. Somecosts of final
removal of the contracts qualifiedTransmission and Distribution lines in the financial
statements.
Upon adoption of FAS 143 on January 1, 2003, TEP expects to record an
asset retirement obligation of $38 million at its net present value of $1.1
million, increase depreciable assets by $0.1 million for hedgeasset retirement
costs, reverse $112.8 million of costs accrued for final removal from
accumulated depreciation, reverse previously recorded deferred tax assets by
$44.2 million and recognize the cumulative effect of accounting while some were consideredchange as
gain of $111.7 million ($67.5 million net of tax). TEP expects that adopting
FAS 143 will result in a reduction to depreciation expense charged throughout
the year as well. For 2003, this amount is approximately $6 million.
Amounts recorded under FAS 143 are subject to various assumptions and
determinations, such as determining whether a legal obligation exists to
remove assets, estimating the fair value of the costs of removal, estimating
when final removal will occur, and the credit-adjusted risk-free interest
rates to be trading activities. See Note 3 of
Notesutilized on discounting future liabilities. Changes that may
arise over time with regard to Consolidated Financial Statements.
Wethese assumptions will change amounts recorded
in the cumulative effects of adopting FAS 133future as expense for asset retirement obligations.
If TEP in our
financial statements by recording the following unrealized gains or
losses on our forward contracts as of January 1, 2001:
- Income Statement: after-tax unrealized gain of $470,000.
- Balance Sheet:
- Other Comprehensive Income, a component of stockholders'
equity: after-tax unrealized loss of $14 million, and
- Forward Sale and Purchase Contracts Liability of $22
million.
The financial statements for periods prior to 2001 do not
reflect the requirements of FAS 133.
Under FAS 133, we record unrealized gains and losses on our
forward contracts and swap agreements and adjust the relatedfact retires any asset
or liability on a monthly basis to reflect the market prices at the end of its useful life, without
a legal obligation to do so, it will record retirement costs at that time as
incurred or accrued. TEP does not believe that the month. The market prices used to determine fair value
for these contracts are estimated based on various factors including
broker quotes, exchange prices, over the counter prices and time
value. We report the unrealized gain (loss) on forward sales net of
the unrealized (gain) loss on forward purchases as a component of
operating revenues. The net pre-tax unrealized loss for the year
ended December 31, 2001 was approximately $1 million. See Note 3 of
Notes to Consolidated Financial Statements. At December 31, 2001,
we reported the fair value of our forward sale and purchase
contracts as other current liabilities and we reported the fair
value of MEG's emission allowance inventory as other current assets.
In June 2001, the DIG issued guidance which provided that
certain forward power purchase or sales agreements, including
capacity contracts, could be excluded from the requirementsadoption of FAS 133. We implemented this new guidance, on a prospective basis,
beginning July 1, 2001. As a143 will
result we determined the cash flow
hedge items could be excluded from the FAS 133 requirements. We did
not reverse the unrealized gains (losses) relatedin any change in retail rates since all matters relating to the cash flow
hedges in June. Instead, because allrate-
making treatment of TEP's generating assets have been determined pursuant to
the contracts were settled by
December 31, 2001, as the contracts settled we:
- reversed the unrealized gain (loss) included in Other
Comprehensive Income; and
- recorded the realized gain (loss) in the income statement.
To date, the DIG has issued more than 100 interpretations to
provide guidance in applying FAS 133. As the DIG or the FASB
continues to issue interpretations, we may change the conclusions
that we have reached and, as a result, the accounting treatment and
financial statement impact could change in the future.Settlement Agreement.
PAYMENT DEFAULTS AND ALLOWANCES FOR DOUBTFUL ACCOUNTS
We record an allowance for doubtful accounts when we determine that an
account receivable will not be collected. As a result of payment defaults
made by market participants in California, TEP's collection shortfall from
the CPX and CISO was approximately $9 million for sales made in 2000 and $7
million for sales made in 2001. WeTEP recorded an allowance for doubtful
accounts for the full amount of these uncollected amounts in the fourth
quarter of 2000 and the first quarter of 2001, totaling $16 million. In addition,
TEP has cash collateral of approximately $1 million on deposit in an
escrow account with the CPX, which is currently unavailable to TEP
due to the bankruptcy stay.
In the
fourth quarter of 2001, weTEP decreased the reserve for
energy sales made to the CPX and CISO by $8 million, or 50%, of
the outstanding receivable. This $8 million of income is included in
other operations and maintenance expense on the income statement.
Recentreceivable because events haveduring 2001 caused us to believe
that it is probable that at least 50% of the amount due to TEP will be
repaid. These include: (1) the stabilization of western power markets, (2)
rate increases achieved by PG&E and SCE, (3) settlements made by California
utilities with various power providers, (4) the CPUC approval of SCE's
financing plan to pay its creditors by the end of the first quarter of 2002,
and (5) data in filings of FERC refund hearings. The amount that weTEP
ultimately collectcollects would have an impact on our earnings if the amount is more
or less than the $8 million we haveTEP has reserved. If we collectTEP collects all of the $16
million, pre-tax income will increase by $8 million. If we doTEP does not collect
any of the $16 million, pre-tax income will decrease by $8 million. WeTEP also
believebelieves that we areit is due interest on the amounts we areTEP is owed.
As of December 31, 2001, TEP's net receivable exposure to Enron
was $0.8 million. In addition,
TEP had forward electricity sales
contracts for periods through June 30, 2002 with an estimated mark-
to-market valuehas cash collateral of approximately $1 million. The unrealized gains
associatedmillion on deposit in an escrow
account with these contracts were removed from TEP's revenues as
ofthe CPX, which is currently unavailable to TEP due to the CPX's
bankruptcy stay.
At December 31, 2001. TEP made a reserve of $0.4 million against
the outstanding receivable owed by Enron. TEP has filed a claim in
Enron's bankruptcy proceedings for its receivable2002 and for the mark-
to-market value of defaulted forward contracts.
At December 31, 2001, the reserve for electric
wholesale accounts receivable on TEP's balance sheet was approximately $8
million.
See Note 11 of Notes to Consolidated Financial Statements.
CAPITALIZATION OF UED PROJECT DEVELOPMENT COSTS
UED capitalizes project development costs when it is probable that the
project will be completed and we expectit expects to recover the costs of the project.
UED and SRP entered into a Joint Development
Agreement in October 2001, to develop two 400 MW coal-fired units at
TEP's existing Springerville Station. UED and SRP each committed
$12.5 million for a totalAt December 31, 2002, capitalized project development funding of $25 million
for professional services and other third party costs.costs on UED's balance
sheet were approximately $22.4 million. If the Springerville expansion
project does not proceed, the capitalized project development costs will be
immediately expensed.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLAN ASSUMPTIONS
TEP records plan assets, obligations, and expenses as appropriate,
related to its pension and other postretirement benefit plans based on
actuarial valuations. Inherent in these valuations are key assumptions
including discounts rates, expected returns on plan assets, compensation
increases and health care cost trend rates. These actuarial assumptions are
reviewed annually and modified as appropriate. The effect of modifications
is generally recorded or amortized over future periods. TEP believes that
the assumptions utilized in recording obligations under the plans are
reasonable based on prior experience, market conditions and from the advice
of plan actuaries.
TEP discounted its future pension and other postretirement plan
obligations using a rate of 6.75% at December 31, 2002, compared to 7.25% at
December 31, 2001. TEP determines the appropriate discount annually based on
the current rates earned on long-term bonds that receive one of the two
highest ratings given by a recognized rating agency. The pension liability
and future pension expense both increase as the discount rate is reduced.
For TEP's pension plans, a 25 basis point decrease in the discount rate would
increase the accumulated benefit obligation by approximately $3.7 million and
the related plan expense for 2003 by approximately $0.6 million. A similar
increase in the discount rate would decrease the accumulated benefit
obligation by approximately $3.5 million and the related plan expense for 2003
by approximately $0.6 million. For TEP's plan for other postretirement
benefits, a 25 basis point decrease in the discount rate would increase the
accumulated benefit obligation by approximately $1.5 million and the related
plan expense for 2003 by approximately $0.1 million. A similar increase in
the discount rate would decrease the accumulated benefit obligation by
approximately $1.5 million and the related plan expense for 2003 by
approximately $0.1 milllion.
At December 31, 2002, TEP assumed that its plans' assets would generate
a long-term rate of return of 8.75%. This rate is lower than the assumed
rate of 9.0% used at December 31, 2001. In establishing its assumption as to
the expected return on plan assets, TEP reviews the plans' asset allocation
and develops return assumptions for each asset class based on advice from the
plans' actuaries that includes both historical performance analysis and
forward looking views of the financial markets. Pension expense increases as
the expected rate of return on plan assets decreases. A 25 basis point
decrease in the expected return on plan assets would increase pension expense
for 2003 by approximately $0.3 million. A similar increase in the expected
return on plan assets would decrease pension expense for 2003 by approximately
$0.3 million.
In recognition of significant increases in health care costs, TEP
increased the initial health care cost trend rate used in valuing its
postretirement benefit obligation to 12.0% at December 31, 2002. The rate
assumed at December 31, 2001 capitalized
project development costswas 8.5%. Assumed health care cost trend rates
have a significant effect on UED's balance sheetthe amounts reported for health care plans. A
one percentage-point increase in assumed health care cost trend rates would
increase the postretirement benefit obligation by approximately $5 million
and the related plan expense by approximately $1 million. A similar decrease
in assumed health care cost trend rates would decrease the postretirement
benefit obligation by approximately $4 million and the related plan expense
by approximately $1 million.
As discussed in Note 13, TEP recorded a minimum pension liability of
$6.7 million at December 31, 2002 primarily because of current stock market
conditions and a reduction in the assumed discount rate.
Based on the above assumptions, TEP will record pension expense of $8.5
million and other postretirement benefit expense of $6.6 million in 2003.
TEP will make required pension plan contributions of $2.8 million in 2003.
TEP's other postretirement benefit plan is not funded. TEP expects to make
benefit payments to retirees under this plan of approximately $2 million in
2003.
See Note 13 of Notes to Consolidated Financial Statements.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING
ACTIVITIES
On January 1, 2001, TEP adopted FAS 133. A derivative financial
instrument or other contract derives its value from another investment or
designated benchmark. When TEP adopted FAS 133, some of the forward
contracts that it used to buy and sell wholesale power were considered to be
derivatives based on the accounting guidance at that time. Other contracts
qualified for hedge accounting.
Because of the complexity of derivatives, the FASB established a
Derivatives Implementation Group (DIG). During 2001, the DIG issued new
guidance, which changed the contracts that qualified as derivatives under FAS
133. To date, the DIG has issued more than 100 interpretations to provide
guidance in applying FAS 133. As the DIG or the FASB continues to issue
interpretations, TEP may change the conclusions that it has reached and, as a
result, the accounting treatment and financial statement impact could change
in the future.
Under FAS 133, TEP records unrealized gains and losses on its derivative
forward contracts and adjusts the related assets and liabilities on a monthly
basis to reflect the market prices at the end of the month. Similarly, in
accordance with the accounting guidance for energy-related trading
activities, MEG records unrealized gains and losses on its trading activities
and adjusts the related assets and liabilities on a monthly basis to reflect
the market prices at the end of the month. The market prices used to
determine fair value for these derivative instruments and trading activities
are estimated based on various factors including broker quotes, exchange
prices, over the counter prices and time value. TEP reports its unrealized
gain/loss on derivative forward sales net of its unrealized gain/loss on
derivative forward purchases as a component of Operating Revenues. MEG
reports its unrealized gain/loss on trading activities net of its realized
gain/loss on trading activities as a component of Operating Revenues. The
net pre-tax gain on TEP forward contracts and MEG trading activities for the
year ended December 31, 2002, were approximately $7 million. In addition, under certain limited circumstances
associated with$0.5 million and $0.1
million, respectively. At December 31, 2002, the withdrawal fromfair value of MEG's trading
assets totaled $10.5 million, which is reported in Other Current Assets, and
the project, UED would be
obligatedfair value of MEG's trading liabilities totaled $10.3 million, which is
reported in Other Current Liabilities. TEP had no open forward contracts at
December 31, 2002 that are considered derivatives.
See Note 3 of Notes to reimburse SRP for zero, 50% or 100% of SRP's previously
paid funding amounts, depending on the withdrawal circumstances.Consolidated Financial Statements.
UNBILLED REVENUE
TEP's electric retail sales revenues include an estimate of MWhs
delivered but unbilled at the end of each period. The unbilled revenue is
estimated by comparing the actual MWhs generated to the MWhs billed to our
retail customers. The excess of MWhs generated over MWhs billed is then
allocated to the retail customer classes based on estimated usage by each
customer class. WeTEP then recordrecords revenue for each customer class based on
the various bill rates for each customer class. Due to the seasonal
fluctuations of ourTEP's actual load, the unbilled revenue amount is greater in
the summer months than it is in the winter months.
RESULTS OF OPERATIONS
- ---------------------
UniSource Energy recorded total revenues of $1.4 billion in
2001,DEFERRED TAX VALUATION
We record deferred tax liabilities for amounts that will increase income
taxes on future tax returns. We record deferred tax assets for amounts that
could be used to reduce income taxes on future tax returns. We record a
40% increase overvaluation allowance, or reserve, for the $1 billion in total revenues recorded
in 2000. This increase in revenues resulted from significant growth
in wholesale marketing activities and modest growth in retail
electricity sales at TEP. TEP's retail revenues grew by only 1%,
largelydeferred tax asset amount that we
may not be able to use on future tax returns. We estimate the result of cutbacks in consumption by both of its large
mining customers. Wholesale revenues more than doubled due to sales
of available generating capacity, increased trading activities and
significantly higher prices in the western U.S. energy markets in
the first five months of 2001.
In 2001, UniSource Energy's consolidated net income was $61
million or $1.84 per share of common stock, compared with $42
million or $1.29 per share of common stock in 2000, and $79 million
or $2.45 per share of common stock in 1999. Consolidated earnings
were higher in 2001 than in 2000 as a resultvaluation
allowance based on our interpretation of the robust wholesale
marketing conditions in the first five monthstax rules, prior tax audits, tax
planning strategies, scheduled reversal of the year.
Contribution by Business Segment
--------------------------------deferred tax liabilities, and
projected future taxable income.
The table below shows the contributions to our consolidated
after-tax earnings by our three business segments, as well as parent
company expenses and inter-company eliminations.
2001 2000 1999
---------------------------------------------------------------------
- Millions of Dollars -
Business Segment
TEP $75.3 $51.2 $73.5
Millennium (9.2) (4.1) 10.9
UED 0.8 - -
Inter-Company Eliminations (5.6) (5.2) (5.3)
---------------------------------------------------------------------
Consolidated Net Income $61.3 $41.9 $79.1
---------------------------------------------------------------------
Inter-Company Eliminations include:
- eliminationvaluation allowance of inter-company sales between business segments.
- elimination of the inter-company note and interest between
UniSource Energy and TEP. See Note 1 of Notes to Consolidated
Financial Statements - Basis of Presentation.
- elimination of UED's rental income and TEP's rental expense from
UED's turbine lease to TEP.
The operating revenues and expenses from the Millennium Energy
Businesses are currently included as part of UniSource Energy's
Operating Revenues and Operating Expenses. See Note 4 of Notes to
Consolidated Financial Statements - Millennium Energy Businesses.
The financial condition and results of operations of TEP are
currently the principal factors affecting the financial condition
and results of operations of UniSource Energy on an annual basis.
The following discussion relates to TEP's utility operations, unless
otherwise noted. The results of our unregulated energy businesses
are discussed in Results of Millennium Energy Businesses and Results
of UED, below.
TEP stopped applying regulatory accounting principle FAS 71 to
its generation operations during the fourth quarter of 1999 in
response to its Settlement Agreement with the ACC. As a result, the
operating results for 2001 and 2000 are not directly comparable with
1999 because the presentation and calculation of certain financial
statement line items changed. Reported earnings in 1999 are higher
than in 2000 due primarily to:
- the 1999 change in accounting for capital leases. Previously, we
recorded lease expense consistent with our rate-making treatment and
recorded equal annual expense amounts over the lease term. Under
current accounting treatment, capital lease expense is higher in the
earlier years of the lease term because the interest expense
component is calculated on a mortgage basis.
- the 1999 reclassification of our generation-related regulatory
assets to the Transition Recovery Asset, which shortened the
amortization period for these assets to nine years and thereby
increased the annual amortization amounts.
Utility Sales and Revenues
--------------------------
Customer growth, weather and other consumption factors affect
retail sales of electricity. Price changes also contribute to
changes in retail revenues. Electric wholesale sales are affected
by market prices in the wholesale energy market, competing sources
of energy and capacity in the region.
During the first five months of 2001 and the last half of 2000,
TEP experienced significant growth in wholesale energy sales and
revenues, primarily due to significantly higher regional market
prices and opportunities to sell its excess generating capacity to
California and other western wholesale market participants. In June
2001, however, wholesale market prices began, and continued, to
decline. In spite of this price drop, electric wholesale revenues
grew dramatically throughout 2001 due to the settlement of energy
sales contracts established when regional market prices were high.
In 2001, electric wholesale revenues comprised 53% of total
revenues, compared with 35% in 2000 and 21% in 1999. TEP's electric
wholesale sales consist primarily of four types of sales:
(1) Sales under long-term contracts for periods of more than
one year. TEP currently has long-term contracts with three
entities to sell firm capacity and energy: Salt River
Project, the NTUA and the TOUA. TEP also has a long-term
interruptible contract with PDES, which requires a fixed
contract demand of 60 MW at all times except during TEP's
peak customer energy demand period, from July through
September of each year. Under the contract, TEP can
interrupt delivery of power if the utility experiences
significant loss of any electric generating resources.
(2) Forward contracts to sell energy for periods through the
end of the next calendar year. Under forward contracts, TEP
commits to sell a specified amount of capacity or energy at a
specified price over a given period of time, typically for
one-month, three-months or one-year periods.
(3) Short-term economy energy sales in the daily or hourly
markets at fluctuating spot market prices and other non-firm
energy sales.
(4) Sales of transmission service.
The tables below provide trend information on retail sales and
on the four types of electric wholesale sales made by TEP in the
last three years.
Sales Operating Revenues
2001 2000 1999 2001 2000 1999
- -----------------------------------------------------------------------------------------------
- Millions of kWh - - Millions of Dollars -
Electric Retail Sales 8,261 8,186 7,789 $ 670 $ 664 $ 630
- -----------------------------------------------------------------------------------------------
Electric Wholesale Sales Delivered:
Long-term Contracts 1,614 1,234 927 79 52 44
Forward Contracts 3,546 2,612 2,258 480 129 72
Short-term Sales and Other 1,968 2,363 2,039 198 174 50
Transmission - - - 4 5 5
- -----------------------------------------------------------------------------------------------
Total Electric Wholesale Sales 7,128 6,209 5,224 761 360 171
- -----------------------------------------------------------------------------------------------
Total 15,389 14,395 13,013 $1,431 $1,024 $ 801
- -----------------------------------------------------------------------------------------------
2001 Compared with 2000
-----------------------
In 2001, kWh sales to retail customers increased by 1% compared
with 2000, despite an increase in the average number of retail
customers of 2.5% to 347,099. Sales to mining customers decreased
by 9%, offset by increased sales to residential and commercial
customers. The decrease in mining consumption is due to cutbacks in
production by both of our large mining customers in response to
lower copper prices. Milder summer temperatures also reduced demand
by retail customers. Cooling Degree Days decreased by 4% in 2001,
from 1,552 to 1,484 days. Revenue from sales to retail customers
increased by 1% in 2001 compared with 2000, reflecting the slight
increase in consumption.
Kilowatt-hour electric wholesale sales increased by 15% in 2001
compared with 2000, while revenues increased by 111%. The largest
increase in sales and revenues was in forward contracts, which
represents increased purchase and resale transactions. Revenues
also increased as a result of the settlement of sales contracts that
were established when market prices were higher earlier in the year.
Sales and revenues from long-term contracts were higher in 2001 due
to the new contract with PDES, effective March 2001. Short-term
economy sales in the daily and hourly markets at higher market
prices made it economical for TEP to run its gas generation units to
produce energy to sell to other regional utilities and marketers
during the first six months of 2001. Although KWh sales in the
short-term economy markets were lower in 2001 than 2000, revenues
from these sales were higher, due to higher average market prices in
2001. Factors contributing to the higher market prices include
increased demand due to population and economic growth in the
region, higher natural gas prices, dysfunction in the California
marketplace, increased maintenance outages due to higher than normal
operating levels, lower availability of hydropower resources,
transmission constraints, and environmental constraints.
2000 Compared with 1999
-----------------------
In 2000, kWh sales to retail customers increased by 5% compared
with 1999. This increase is the result of an increase in the
average number of retail customers and increased usage by
residential and small commercial customers. The average number of
retail customers grew by 2.7% to 338,766 in 2000. Warmer weather,
as measured by a 27% increase in Cooling Degree Days, contributed to
higher retail energy usage in 2000. Revenues from sales to retail
customers increased by 5.5% in 2000 compared with 1999, reflecting
the higher kWh sales. These increases were offset, in part, by the
effect of a 1% across-the-board rate reduction effective July 1,
2000. TEP established a new peak demand on August 4, 2000. The
maximum momentary peak on that day was 1,871 MW and the net hourly
peak was 1,862 MW.
Kilowatt-hour electric wholesale sales increased by 19% in 2000
compared with 1999, while revenues from electric wholesale sales
increased by 110% for the same period. The largest increase in
revenues was in short-term economy sales in the daily and hourly
markets. Sustained higher market prices, particularly in the third
and fourth quarters, made it economical for TEP to run its gas
generation units to produce energy to sell into California and to
other regional utilities and marketers. Sales under long-term
contracts increased because contractual rates at which the buyers
could take energy were attractive compared to prevailing market
prices. TEP also increased its sales activity in the forward
markets (up to one year) in 2000, including both forward sales to
hedge excess generating capacity as well as increased trading
activity. Factors contributing to the higher market prices include
increased demand due to population and economic growth in the
region, higher natural gas prices, dysfunction in the California
marketplace, increased maintenance outages due to higher than normal
operating levels, lower availability of hydropower resources,
transmission constraints, and environmental constraints.
Operating Expenses
------------------
2001 Compared with 2000
-----------------------
Fuel and Purchased Power expenses increased by $382 million or
85% in 2001 compared with 2000. Fuel expense at TEP's generating
plants increased by $19 million or 8% primarily because of higher
natural gas prices and increased usage of gas generation to meet
increased kWh sales in the first five months of 2001. This increase
was partially offset by decreased usage of gas generation in the
last half of the year, as wholesale market prices fell, making it
less economical for TEP to run its gas generation units to produce
energy to sell to other regional utilities and marketers. Gas
expense also includes the new gas-fired peaking units, which went in-
service in June 2001, and the $9 million additional cost associated
with gas swap agreements we entered into in May 2001. See Market
Risks, Commodity Price Risk. The average cost of fuel per kWh
generated was 2.12 cents in 2001 and 2.01 cents in 2000.
Purchased Power expense increased by $363 million, or 175%,
because of higher wholesale energy prices and increased purchases in
the forward and spot energy markets for trading purposes to resell
to wholesale customers. Purchased Power expense remained high, even
after wholesale market prices began to fall in June 2001, due to the
settlement of wholesale energy purchase contracts, which were
established when forward power prices were higher. Also, in May
2001, we entered into several forward purchase contracts to assure
service reliability in the summer months to mitigate the risk of the
potential loss of 110 MW under an exchange agreement with SCE. The
additional cost to assure service reliability was approximately $12
million.
Despite the large increases in Fuel and Purchased Power
expenses, TEP's gross margin (Operating Revenue less Fuel and
Purchased Power expense) improved by $26 million or 5% in 2001
compared with 2000. This improvement was primarily due to increased
sales volumes and higher prices in the wholesale energy markets.
TEP recorded a $13 million pre-tax ($8 million after-tax) one-
time charge in the third quarter of 2000 as a result of a coal
supply contract amendment related to the San Juan Generating
Station. See Note 10 of Notes to Consolidated Financial Statements.
Other Operations and Maintenance expense decreased by $4
million, or 3% in 2001 compared with 2000. We established a reserve
in 2000 for wholesale energy sales to California, $7 million of
which was recorded as an expense. In contrast, in 2001, we recorded
an additional reserve of $7 million in the first quarter of 2001, of
which $5 million was charged to expense, but reversed $8 million in
December. Various other production expenses increased by $4 million
and maintenance expense increased by $2 million in 2001 compared
with 2000. The higher Maintenance expense is the result of
scheduled maintenance at the Irvington, Springerville Unit 2 and San
Juan generating plants. See Note 11 of Notes to Consolidated
Financial Statements.
The Transition Recovery Asset (TRA) and its related
amortization result from the Settlement Agreement reached with the
ACC in 1999. The Amortization of Transition Recovery Asset totaled
$22 million in 2001, up from $17 million in 2000. Amortization
amounts are scheduled to increase annually until the entire TRA has
been amortized, no later that December 31, 2008. The monthly amount
of amortization recorded is a function of the remaining TRA balance
and total retail kWh consumption by TEP distribution customers.
2000 Compared with 1999
-----------------------
Fuel and Purchased Power expenses increased by $161 million or
56% in 2000 compared with 1999. Fuel expense at TEP's generating
plants increased by $46 million or 24% primarily because of higher
natural gas prices and increased usage of gas generation to meet
increased kWh sales. The average cost of fuel per kWh generated was
2.01 cents and 1.75 cents for 2000 and 1999, respectively. The
increase reflects the increased usage of gas as fuel in 2000.
Purchased Power expense increased by $115 million or 125% because of
higher wholesale energy prices and increased purchases in the
forward and spot energy markets for trading purposes, under
agreements to resell to wholesale customers, and to meet certain
peak hourly retail demand requirements.
Despite the large increases in Fuel and Purchased Power
expenses, TEP's gross margin (Operating Revenue less Fuel and
Purchased Power expense) improved by $63 million or 12% in 2000
compared with 1999. This improvement was primarily due to increased
sales volumes and higher prices in the wholesale energy markets.
TEP recorded a $13 million pre-tax ($8 million after-tax) one-
time charge in the third quarter of 2000 as a result of a coal
supply contract amendment. See Note 10 of Notes to Consolidated
Financial Statements - Commitments and Contingencies.
The presentation and calculation of certain financial statement
line items changed in November 1999 as a result of the
discontinuation of regulatory accounting (FAS 71) for TEP's
generation operations. Accordingly, beginning in November 1999,
Capital Lease expense is included in Depreciation and Amortization
and in Interest on Capital Leases. The increase in Depreciation and
Amortization for 2000 compared to 1999 is primarily due to this new
presentation and additional property and equipment that were placed
in service during 2000. Because we stopped applying FAS 71, we
discontinued amortization of the Springerville Unit 1 Allowance
contra-asset and the corresponding recognition of Interest Imputed
on Losses Recorded at Present Value.
Other Operations and Maintenance expenses increased 14% in
2000, partially because we established reserves to cover our credit
exposure for risk of non-payment for wholesale sales made in
December 2000. The remainder of the increase supports customer
growth and higher kWh sales in 2000 compared to 1999.
The Amortization of Transition Recovery Asset totaled $17
million in 2000 and $2 million in 1999. The 1999 amount reflects
only two months of amortization, beginning in November 1999.
Interest Income
---------------
TEP's income statement includes interest income of $9 million
for both 2001 and 2000 and $10 million for 1999 on its promissory
note from UniSource Energy. See Note 1 of Notes to Consolidated
Financial Statements - Nature of Operations and Summary of
Significant Accounting Policies-Basis of Presentation. On UniSource
Energy's income statement, this income is eliminated as an inter-
company transaction.
Other Interest Income was higher in 2001 than in 2000 due to
higher average cash balances and increased interest income on
investments in Springerville Unit 1 Lease debt.
Interest Expense
----------------
2001 Compared with 2000
-----------------------
Interest Expense was $8 million, or 5% lower in 2001 than in
2000 due to lower average interest rates on long-term variable rate
tax-exempt debt and lower debt balances.
2000 Compared with 1999
-----------------------
Because we stopped applying FAS 71 to generation operations in
November 1999, we had the following changes, which had the effect of
increasing interest expense:
- We reclassified Capital Lease Interest Expense from Operating
Expenses to Interest Expense; and
- We stopped recording the Interest Imputed on Losses Recorded at
Present Value due to the elimination of the Springerville Unit 1
Allowance.
Absent these accounting changes, Interest Expense for 2000
would have been lower compared to 1999 primarily due to lower
amortization of losses on reacquired debt and lower letter of credit
fees.
During the third quarter of 2000, we began to record small
amounts of Imputed Interest on Losses Recorded at Present Value
related to the San Juan Coal Contract Amendment Fee.
Income Taxes
------------
Income taxes increased $29 million in 2001 compared with 2000
as a result of higher pre-tax income and the recognition of $6
million in tax benefits in the second quarter of 2000 from the
resolution of various IRS audit issues.
Income Taxes were slightly higher in 2000 compared to 1999 due
to higher pre-tax income, which was somewhat offset by the
recognition of tax benefits from the resolution of various IRS audit
issues in the second quarter of 2000.
See Note 10 of Notes to Consolidated Financial Statements -
Commitments and Contingencies.
Extraordinary Income - Net of Tax
---------------------------------
When TEP ceased applying FAS 71 for its generation operations
in November 1999, it recorded $23 million of extraordinary net
income consisting of the following after-tax items:
- $31 million in income from recognizing all remaining usable
investment tax credit benefits;
- $2 million of expense from a change in accounting related to
certain emission allowance transactions; and
- $7 million expense true-up from recording generation-related
property-tax expense on an accrual basis rather than the regulatory
basis.
TEP recognized the $31 million in income from recognition of
its remaining usable ITC benefits in 1999. Prior to November 1,
1999, TEP amortized ITC to income that was included in the Other
Income section. Consistent with the ACC rate-making treatment, the
ITC was amortized over the tax life of the property generating the
ITC. The recognition of this one-time benefit will reduce future
earnings by the amount that would have been amortized to income.
See Note 2 of Notes to Consolidated Financial Statements -
Regulatory Matters.
RESULTS OF MILLENNIUM ENERGY BUSINESSES
- ---------------------------------------
The table below provides a breakdown of the net income and
losses recorded by the Millennium Energy Businesses for the last
three years ended December 31.
2001 2000 1999
- -------------------------------------------------------------------
- Millions of Dollars -
Energy Technology Investments $(13.9) $(6.0) $(1.0)
Nations Energy 4.5 0.7 (9.2)
Other 0.2 1.2 21.1
- -------------------------------------------------------------------
Total Millennium $ (9.2) $(4.1) $10.9
- -------------------------------------------------------------------
Energy Technology Investments
-----------------------------
Global Solar's development of its solar modules and Infinite
Power Solutions' expenditures to develop thin-film solid state
rechargeable batteries contributed after-tax losses of $11 million,
$6 million and $1 million in 2001, 2000 and 1999, respectively. In
2001, MicroSat and ITN incurred a $3 million after-tax loss related to
the development of small-scale satellites and other research and
development activities.
Nations Energy
--------------
Nations Energy sold its investment in a power project in
Curacao in 2001 resulting in an after-tax gain of $6 million.
Nations Energy is attempting to sell its remaining Panama
investment, which has a remaining book value of less than $1
million.
In 2000, Nations Energy sold a minority interest in a power
project in the Czech Republic for a pre-tax gain of $3 million.
During 2000, Nations Energy recorded decreases of $3 million in the
market value of its Panama investment. This was offset by a tax
benefit of $3 million recorded in the fourth quarter of 2000 related
to the 1999 and 2000 market value adjustments on the Panama
investment.
Nations Energy reported a net loss of $9 million in 1999 due to
development costs, expenses related to the exercise of an option to
invest in the power project in the Czech Republic and the write-off
of investments, primarily in its Panama project.
Other Millennium Investments
----------------------------
In 2001, the results in the "Other" line item relate primarily
to the after-tax interest of $1.2 million earned by Millennium,
offset by Millennium's standalone results of operations and losses
on its other investments.
Amounts shown in the "Other" line item in 2000 primarily
represent the results of Millennium's subsidiary MEH and results
relating to its investment in NewEnergy. MEH recorded net income of
$1 million in 2000 from interest income on a note receivable
received as part of the sale of NewEnergy to AES Corporation in
1999.
MEH recorded net income in 1999 as a result of the July 1999
sale of its equity investment in NewEnergy to AES Corporation. MEH
received $50 million in consideration from the sale consisting of
$27 million in AES common stock and secured promissory notes issued
by NewEnergy totaling $23 million, which were paid in full by July
31, 2001. MEH recognized an after-tax gain of $21 million on the
transaction. The AES common stock was sold in 1999 at a small gain.
RESULTS OF UED
- --------------
UED was established in February 2001 and owns a 20 MW gas
turbine, which it leases to TEP under an operating lease
arrangement. UED recorded a net profit of $0.8 million for 2001.
UED's income represents rental income, less expenses, under the
operating lease. This rental income is eliminated from UniSource
Energy after-tax earnings as an inter-company transaction.
UED and SRP are jointly developing Springerville Units 3 and 4
for the expansion of the Springerville Generating Station.
Development costs related to that project are currently being
capitalized and total approximately $7.3$16 million at December 31, 2001. If2002, which
reduces the project is not completed, UED would immediately
expenseDeferred Tax Asset balance, relates to net operating loss and
investment tax credit carryforward amounts. In the capitalized costs. In addition, under certain limited
circumstances associated with the withdrawal from the project, UEDfuture, if TEP determines
that TEP would be obligatedable to reimburse SRP for zero, 50%use all or 100%a portion of SRP's
previously paid fundingthese amounts depending on tax
returns, then TEP would reduce the withdrawal
circumstances. As of February 28, 2002, the capitalized costs of
UED's balance sheet are approximately $11reserve and recognize a tax benefit up to
$16 million. See Critical
Accounting Policies - Capitalization of UED Project Development
Costs, above.
DIVIDENDS ON COMMON STOCK
- -------------------------
UniSource Energy
----------------
In February 2002, UniSource Energy declared a cash dividend of
$0.125 per share on its common stock. The dividend, totaling
approximately $4 million, is payable March 8, 2002 to shareholders
of record at the close of business February 21, 2002. During 2001,
UniSource Energy paid equal quarterly dividends to its shareholders
of $0.10 per share, totaling $13 million.
UniSource Energy's Board of Directors will review our dividend
level on a continuing basis, taking into consideration a number of
factors including our results of operations and financial condition,
general economic and competitive conditions and the cash flows from
our subsidiary companies, TEP, Millennium and UED.
TEP
---
TEP declared and paid dividends of $50 million in December
2001, $30 million in 2000, and $34 million in 1999. UniSource
Energy is the primary holder of TEP's common stock.
TEP can pay dividends if it maintains compliance with the TEP
Credit Agreement and certain financial covenants, including a
covenantFactors that requirescould cause TEP to maintain a minimum level of net worth.
As of December 31, 2001,recognize the required minimum net worth was $263
million. TEP's actual net worth at December 31, 2001 was $322
million. See Investing and Financing Activities, TEP Bank Credit
Agreement, below. As of December 31, 2001, TEP was in compliance
withtax benefit
include new or additional guidance through tax regulations, tax rulings, case
law and/or the terms of the Credit Agreement.
The ACC Holding Company Order states that TEP may not pay
dividends to UniSource Energy in excess of 75% of its earnings until
TEP's equity ratio equals 37.5% of total capital (excluding capital
lease obligations). As of December 31, 2001, TEP's equity ratio on
that basis was 22%.
In addition to these limitations, the Federal Power Act states
that dividends shall not be paid out of funds properly included in
the capital account. Although the terms of the Federal Power Act
are unclear, we believe that there is a reasonable basis to pay
dividends from current year earnings. Therefore, TEP declared its
December 2001, 2000, and 1999 dividends from 2001, 2000, and 1999
earnings, respectively, since it had an accumulated deficit, rather
than positive retained earnings.
Millennium and UED
------------------
Millennium did not pay any dividends to UniSource Energy in
2001 or 2000. In the third quarter of 1999, Millennium paid a $10
million cash dividend to UniSource Energy. We cannot predict the
amount or timing of future dividends from Millennium. UED has not
paid any dividends to UniSource Energy.
INCOME TAX POSITION
- -------------------
At December 31, 2001, UniSource Energy and TEP had, for federal
income tax purposes:
- $142 million of NOL carryforwards expiring in 2006 through 2009;
- $11 million of unused ITC expiring in 2003 through 2005; and
- $83 million of Alternative Minimum Tax credit that will carry
forward to future years.
We have recorded deferred tax assets related to these amounts.
See Note 12 of Notes to Consolidated Financial Statements-Income
Taxes.
Due to the issuance of common stock to various creditors of TEP
in 1992, a change in TEP ownership was deemed to have occurred for
tax purposes in December 1991. As a result, our use of the NOL and
ITC generated before 1992 is limited under thesuch benefits on future tax code. At
December 31, 2001, pre-1992 federal NOL and ITC carryforwards which
are subject to the limitation were approximately $136 million and
$11 million, respectively. The $6 million of post-1992 federal NOL
at December 31, 2001 is not subject to the limitation.returns.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
OVERALL LIQUIDITY
OurUNISOURCE ENERGY CONSOLIDATED CASH FLOWS
2002 2001 2000
---------------------------------------------------------------------
- Millions of Dollars -
Cash provided by (used in):
Operating Activities $ 173 $ 215 $ 215
Investing Activities (271) (117) (113)
Financing Activities (39) (33) (84)
---------------------------------------------------------------------
Net Increase (Decrease) in Cash $(137) $ 65 $ 18
=====================================================================
UniSource Energy's primary source of liquidity is ourits cash flow from
operations, which exceeded $200 million in both 2001 and 2000.
These cash flows areis derived primarily from retail and wholesale energy sales
at TEP, net of the related payments for fuel and purchased power. In the last two years,2001
and 2000, our cash flows have benefited from higher margins on wholesale energy
sales in the western U.S. power markets. This enabled us to increase our
cash levels from $145$163 million at year-end 19992000 to $228 million at year-
endyear-end
2001. We have been usingused our available cash to finance capital expenditures, primarily
at TEP, to make investments in our energy technology affiliates, to pay
dividends to shareholders, and to reduce leverage at TEP by repaying high
coupon debt and investing in lease debt.
For example, in January 2002, we purchased $96 million
of lease debt bearing an average coupon of 14.3%. We will benefit
from after-tax interest savings of an average of $5.3 million
annually for the next five years from this transaction. The
benefits will be larger in the earlier years.
We do not expect the wholesale energy market conditions to be
as favorable in 2002, with market prices and margins lower than we
saw in the last two years. Another factor that could affect ourNet cash flows from operations is reduced energy demandoperating activities in 2002 decreased from 2001,
primarily as a result of the following factors:
- $42 million decrease in cash receipts from sales to wholesale and
retail customers, net of fuel and purchased power costs;
- $11 million cash payment to terminate an Irvington coal supply
agreement in September 2002;
- $15 million cash payment to amend a San Juan coal supply agreement in
December 2002; offset by
our large
mining customers. As we have reported elsewhere- $11 million decrease in this document,
our two major mining customers have reduced operations during the
last few yearscapital lease interest paid as a result of
lower lease obligation balances and lower interest rates on variable
rate lease debt; and
- $10 million decrease in income taxes paid due to lower copper prices. This trend will continuepre-tax income
and income tax benefits in 20022002.
In 2001, net cash flows from operating activities increased slightly
compared with 2000 due to higher cash receipts from sales to retail and
we expect a 40 MW load reduction to our system peak
demand. We expect that these load reductions will be offset,
however, by lowerwholesale customers, net of fuel and purchased power costs and lower capital
lease interest payments, offset by higher income tax payments and higher
wages and other operations and maintenance costs.
Net cash used for investing activities was higher in 2002 than in 2001
primarily due to cover summer peaking
needsinvestment in $135 million of Springerville lease debt. TEP
spent $113 million for construction expenditures and by salesMillennium contributed
$24 million in investments and loans to Millennium Energy Businesses in 2002.
Other significant investing activities in 2001 included: (1) TEP spent $104
million for construction expenditures; (2) we received $5 million in proceeds
from the sale of excess capacity, when profitable,Nations Energy's interest in the first, second,Curacao project, along with
the return of $16 million in deposits; (3) UED purchased a 20 MW gas turbine
for $15 million; (4) we received the final promissory note payment of $11
million from NewEnergy; and fourth quarters.(5) TEP sold real estate for $7 million.
Net cash used for financing activities was higher in 2002 compared with
2001 primarily due to increased common stock dividends and expenses
associated with the refinance of TEP's bank credit facility. In 2002,
UniSource Energy paid approximately $17 million in dividends to its common
shareholders and TEP retired $20 million in capital lease obligations and
made $2 million in bond payments. In addition, in November 2002, TEP paid $5
million in upfront fees associated with the refinance of its bank facility.
See TEP - Electric Utility, Financing Activities, TEP Bank Credit Agreement,
below. In contrast, in 2001 UniSource Energy paid $13 million in dividends
to its common shareholders and TEP paid $26 million to retire capital lease
obligations and made $2 million in bond payments.
As a result of the activities described above, our consolidated cash and
cash equivalents decreased to $91 million at December 31, 2002 from $228
million at December 31, 2001. TEP's cash and cash equivalents decreased to
$56 million at December 31, 2002 compared with $160 million at December 31,
2001. At March 4, 2003, our consolidated cash balance, including cash
equivalents, was approximately $30 million, including TEP's cash balance of
approximately $10 million. We do not, therefore, expect
these reductions to have a significant impactinvest cash balances in high-grade money market
securities with an emphasis on cash flows.preserving the principal amounts invested.
In the event that we experience lower cash from operations due
to these, or other events,in 2003, we
will adjust our discretionary uses of cash accordingly. We believe, however,
that we will continue to have sufficient cash flow to cover our capital
needs, as well as required debt payments and dividends to shareholders.
Furthermore, we believe that even with lower wholesale energy prices and
lower demand from mining customers, we will have sufficient excess cash flow
to continue to make annual discretionary debt reductions or lease debt
investments at TEP in the range of $30 million.
TEP's $100 million Revolving Credit Facility provides us with
another major source of liquidity. TEP has borrowed under this
facility only one time for a period of approximately one month
during the past four years. At December 31, 2001, there were no
outstanding borrowings under this facility. If TEP encountered
temporary cash needs during the course of the year, it would borrow
from this Revolving Credit Facility.
The Revolving Credit Facility is part of TEP's Bank Credit
Agreement, which matures on December 30, 2002. The Credit Agreement
also includes a $341 million Letter of Credit Facility which
supports $329 million of tax-exempt variable rate bonds. If TEP
fails to extend or replace the LOCs or to otherwise refinance the
bonds prior to the expiration date, the bonds would be subject to
mandatory redemption. Therefore, the $329 million in bonds have
been classified as current liabilities on our balance sheet as of
December 31, 2001. TEP has commenced negotiations with its banks
and believes that it will be able to negotiate a new credit
agreement prior to the maturity of its existing Credit Agreement.
At that time, the $329 million in tax-exempt variable rate bonds
will be classified as Long-Term Debt. See TEP Bank Credit
Agreement, below.
The following chart displays TEP's contractual obligations by
maturity and by type of obligation.
TEP's Contractual Obligations
- Millions of Dollars -
---------------------------------------------------------------------------------
IDBs Total
Supported Long- Capital Unconditional Contractural
Payments Due in Years by Expiring Term Lease Operating Purchase Cash
Ending December 31, LOCs (1) Debt Obligations Leases (2) Obligations (3) Obligations
- ---------------------------------------------------------------------------------------------------------
2002 $ 329 $ 2 $ 90 $ 2 $ 90 $ 513
2003 - 2 123 2 85 212
2004 - 2 125 1 82 210
2005 - 2 125 1 78 206
2006 - 21 127 1 77 226
- ---------------------------------------------------------------------------------------------------------
Total 2002 - 2006 329 29 590 7 412 1,367
Thereafter - 775 1,125 3 389 2,292
Less: Imputed Interest - - (842) - - (842)
- ---------------------------------------------------------------------------------------------------------
Total $ 329 $804 $ 873 $ 10 $ 801 $2,817
- ---------------------------------------------------------------------------------------------------------
(1) TEP's $341 million LOC Facility secures the payment of principal and interest on $329 million
of IDBs. The LOCs expire on December 30, 2002. If the LOCs are not extended or replaced
with new LOCs with a longer term or if the bonds are not otherwise refinanced, the bonds would
be redeemed. Accordingly, these IDBs were classified as short-term debt at December 31, 2001,
and will be classified as long-term debt once a new LOC Facility with a later expiration date
is obtained.
(2) Excludes TEP's lease of the 20 MW gas turbine from UED, as such rental expense is elimidated in
UniSource Energy consolidation as an inter-company transaction.
(3) These obligations represent future guaranteed payments under TEP's natural gas, coal and rail
transportation contracts.
Contractual obligations of Millennium and UniSource Energy are
not significant.
UniSource Energy has contingent obligations under various
surety bonds that total approximately $2 million.
As discussed above, TEP has the full amount available under its
$100 million Revolving Credit Facility. If TEP draws any amount
under this facility, such borrowing would become a contractual
obligation of TEP at that time. We have no other commercial
commitments to report.
We have reviewed our contractual obligations and provide the
following information:
- TEP does not have any triggers in any of its debt or lease
agreements that would cause an event of default or cause amounts to
become due and payable in the event of a credit rating downgrade.
- None of our contracts or financing structures contain triggers or
acceleration clauses due to changes in our stock price.
- TEP's Credit Agreement contains pricing tied to a grid based on
the ratings of TEP's senior secured debt. A change in TEP's credit
rating can cause an increase or decrease in the amount of interest
and fees TEP pays for these facilities.
- TEP's Credit Agreement contains certain financial and other
restrictive covenants, including interest coverage, leverage and net
worth tests. Failure to comply with these covenants would entitle
the lenders to accelerate the maturity of all amounts outstanding.
At December 31, 2001, TEP was in compliance with these covenants.
See TEP Bank Credit Agreement, below.
- Neither UniSource Energy nor TEP have issued guarantees to third
parties.
- TEP conducts its wholesale trading activities under the Western
Systems Power Pool Agreement (WSPP) which contains provisions
whereby TEP may be required to post margin collateral due to a
change in credit rating or changes in contract values. As of
December 31, 2001, TEP has not been required to post such
collateral.
CASH FLOWS
UniSource Energy Consolidated Cash Flows and Liquidity
------------------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------
- Millions of Dollars -
Cash provided by (used in):
Operating Activities $ 215.4 $ 215.0 $ 113.2
Investing Activities (116.8) (113.5) (93.1)
Financing Activities (33.4) (83.8) (20.0)
- -----------------------------------------------------------------------
Net Increase in Cash $ 65.2 $ 17.7 $ 0.1
- -----------------------------------------------------------------------
Net cash flows from operating activities increased slightly in
2001 compared with 2000, primarily as a result of the following
factors:
- $77 million increase in cash receipts from sales to wholesale and
retail customers, net of fuel and purchased power costs; and
- $11 million decrease in capital lease interest paid; offset by
- $47 million increase in income taxes paid (including a $12
million income tax refund received in 2000); and
- $40 million increase in payments of wages and other operations
and maintenance costs.
In 2000, net cash flows from operating activities increased
significantly compared with 1999 primarily due to higher cash
receipts from sales to retail and wholesale customers, net of fuel
and purchased power costs, lower income tax payments and tax
refunds received. Also, in 1999 we made a $22 million cash tax
settlement and we purchased $14 million of emission allowance
credits.
Net cash used for investing activities was higher in 2001
compared with 2000, primarily because of increased capital
expenditures. Capital expenditures were $16 million higher in 2001,
primarily the result of UED's purchase of a 20 MW gas turbine, which
was placed in-service in June 2001. Other significant investing
activities in 2001 included: (1) $18 million in investments in and
loans to Millennium Energy Businesses; (2) $13 million investment in
Springerville Coal Handling Facility Lease Equity by TEP; (3) $5
million in proceeds from the sale of Nations Energy's interest in
the Curacao project, along with the return of $16 million in
deposits; (4) $11 million in proceeds from the final payment of a
promissory note from NewEnergy to MEH; and (5) $7 million in
proceeds from the sale of real estate.
Net cash used for investing activities was higher in 2000 than
in 1999 mostly because of higher capital expenditures and increases
in investments and loans to affiliates. Capital expenditures
increased by $13 million in 2000. Other significant investing
activities in 2000 included: (1) $28 million purchase of
Springerville Unit 1 lease debt by TEP and Millennium; (2) net new
investment of $5 million by Nations Energy in a power project in
Curacao; (3) $10 million in investments and capital expenditures in
energy technology investments; (4) $20 million in proceeds from the
sale of Nations Energy's investment in the Czech Republic power
project; and (5) $11 million in proceeds from the payment of a
promissory note from NewEnergy to MEH.
Net cash used for financing activities was significantly less
in 2001 compared with 2000 because our long-term debt retirement
requirements were lower. In 2001, we paid $13 million in dividends
to UniSource Energy common shareholders and TEP retired $26 million
in capital lease obligations and $2 million in bond sinking fund
payments and other redemptions. In contrast, in 2000, we paid $10
million in dividends to UniSource Energy common shareholders, and
TEP retired $47 million of its maturing 12.22% Series First Mortgage
Bonds, $39 million in capital lease obligations, and made $3 million
of other bond sinking fund payments and redemptions. We also
received cash proceeds of $13 million from the exercise of UniSource
Energy warrants in December 2000.
As a result of activities described above, our consolidated
cash and cash equivalents increased to $228 million at December 31,
2001 from $163 million at December 31, 2000. TEP's cash and cash
equivalents approximated $160 million at December 31, 2001 compared
with $89 million at December 31, 2000. At February 25, 2002, our
consolidated cash balance, including cash equivalents, was
approximately $99 million, and TEP's was approximately $42$50 million.
Our cash balances declined since year-end 2001 because in January
2002 we purchased $96 million of Springerville Coal Handling
Facilities lease debt. See Investments in Springerville Lease Debt,
below. We invest cash balances in high-grade money market
securities with an emphasis on preserving the principal amounts
invested.
INVESTING AND FINANCING ACTIVITIES
UNISOURCE ENERGY --- PARENT COMPANY
Our primary cash needs are to fund investments in the unregulated energy
businesses, to pay dividends to shareholders, and interest payments on our
promissory note to TEP. In addition, as part of our
ACC Holding Company Order, we must invest 30% of any proceeds of equity
issuances in TEP through December 31, 2002.until TEP's equity reaches 37.5% of total capital (excluding
capital leases).
Our primary sources of cash are dividends from our
subsidiaries, primarily TEP. In 20012002, TEP paid
dividends to its
parentUniSource Energy of $50$35 million, compared with $50 million in
2001 and $30 million in 2000 and $34
million in 1999.2000.
In 1999, Millennium paid $10 million in dividends
to its parent.
We also received $13 million in December 2000 from the exercise
of 791,9662003, UniSource Energy Warrants into UniSource Energy common
stock,will need funds to finance the purchase of which 30%, or $4 million, was invested in TEP as requiredthe
Citizens Arizona electric and gas utility assets. To finance this purchase,
we plan to issue debt secured by the ACC Holding Company Order. See Note 15 of Notes to
Consolidated Financial Statements - Warrants.
Although no specific offerings are currently contemplated, wepurchased assets and may also issue debt and/orconsider
financing a portion of the purchase with new equity, securities from time to time.depending on market
conditions and other factors.
If cash flows were to fall short of expectations, we wouldwill reevaluate the
investment requirements of the unregulated energy businesses and/or seek
additional financing for, or investments in, those businesses by unrelated
parties.
TEP - ELECTRIC UTILITY
TEP's capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt and capital lease
obligations. As shown in the chart below, during the last three years, TEP
had sufficient cash available after capital expenditures, and scheduled debt
payments and capital lease obligations to provide for other investing and
financing activities:
2001 2000 1999
- -------------------------------------------------------------------------------------
- Millions of Dollars -
Cash from Operations $ 261.2 $ 234.2 $ 140.0
Capital Expenditures (103.9) (98.1) (90.9)
Required Debt Maturties (1.7) (48.6) (1.7)
Retirement of Capital Lease Obligations (25.9) (38.9) (23.6)
- -------------------------------------------------------------------------------------
Net Cash Flows Available after Required
Payments $ 129.7 $ 48.6 $ 23.8
- -------------------------------------------------------------------------------------
2002 2001 2000
----------------------------------------------------------------------
- Millions of Dollars -
Cash from Operations $ 204 $ 261 $ 234
Capital Expenditures (103) (104) (98)
Debt Maturities (2) (2) (48)
Retirement of Capital Lease Obligations (20) (26) (39)
----------------------------------------------------------------------
Net Cash Flows Available after Required
Payments $ 79 $ 129 $ 49
======================================================================
During 2002,2003, TEP expects to generate sufficient internal cash flows to
fund its operating activities, construction expenditures, required debt
maturities, and to pay dividends to UniSource Energy. However, TEP's cash
flows may vary due to changes in wholesale revenues, changes in short-term
interest rates, and other factors. At December 31, 2002, TEP had $60 million
available under its Revolving Credit Facility. In January 2003, TEP borrowed
$25 million under its Revolving Credit Facility and repaid it within 20 days.
If cash flows were to fall short of expectations or if monthly cash requirements
temporarily exceededexceed available cash balances, TEP wouldwill borrow from its
Revolving Credit Facility.
AtOperating Activities
--------------------
In 2002, net cash flows from operating activities at TEP exceeded $200
million for the third year in a row, but were lower than 2001 primarily due
to decreased sales to wholesale customers. TEP made cash payments of $27
million in 2002 related to coal contract amendment and termination fees.
Partially offsetting these cash decreases were lower income tax payments due
to lower pre-tax income and certain tax benefits received, and lower capital
lease interest paid due to lower lease obligation balances and lower
variable interest rates.
Wholesale energy market conditions were not as favorable in 2002 as they
were in the previous two years, with market prices and margins significantly
lower. Another factor that affects TEP's cash flows from operations is reduced
energy demand by its large mining customers. As reported elsewhere in this
document, TEP's two major mining customers have reduced operations during the
last few years due to lower copper prices. This trend is likely to continue
in 2003. TEP expects that these load reductions will be offset, however, by
lower purchased power costs to cover summer peaking needs and by sales of
excess capacity, when profitable, in the first, second, and fourth quarters.
TEP does not, therefore, expect these reductions to have a significant impact
on cash flows.
Investing Activities
--------------------
Net cash used for investing activities was higher in 2002 compared with
2001, primarily due to TEP's investment in Springerville lease debt. In
2002, TEP paid $135 million to purchase Springerville Lease debt, spent $103
million on construction expenditures, and $15 million to purchase the 20 MW
gas turbine from UED. In 2001, construction expenditures were $104 million
and TEP received $7 million in proceeds from the sale of real estate.
Investments in Springerville Lease Debt and Equity
--------------------------------------------------
TEP made the following investments in Springerville Lease debt in 2002:
Principal Average
Date Amount Debt Purchased Coupon Rate
- ------------------------------------------------------------------------------------
January 2002 $ 96 million Springerville Coal Handling Lease Debt 14.3%
May 2002 3 million Springerville Unit 1 Lease Debt 10.7%
September 2002 33 million Springerville Unit 1 Lease Debt 10.6%
TEP purchased $2 million of Springerville Unit 1 Lease debt in 2001 from
Millennium. Millennium previously purchased these notes in the open market
in the first quarter of 2000. As of December 31, 2002, TEP's total
investment in Springerville lease debt was $192 million, at yields ranging
from 8.9% to 12.7%.
In December 2001, TEP had $100purchased a 13% equity ownership interest in the
Springerville Coal Handling Facilities Leases for $13 million. In March
2002, TEP terminated the leases related to its equity interest and cancelled
the associated debt that we held. As a result of the lease termination, TEP
recorded a $21 million available underreduction to the capital lease obligation, a $27
million reduction of its Revolving Credit Facility.investment in lease debt, and a $6 million increase
in the capital lease asset, which represents the residual value of TEP's
interest in the leased asset and is carried at cost.
See Note 7 of Notes to Consolidated Financial Statements.
Capital Expenditures
--------------------
TEP's forecasted construction expenditures for the next five years are:
$124 million in 2002, $156$121 million in 2003, $85$126 million in 2004, $82$163 million in 2005, and $74$107
million in 2006.2006, and $110 million in 2007. These estimated capital
expenditures for 2002-20062003-2007 break down in the following categories:
- $289$347 million for transmission, distribution and other facilities in
the Tucson area;
- $44$154 million for production facilities;
- $32 million in renewable energy projects, including expansion of its
solar generation portfolio;
- $118$15 million in a new production facility for production facilities;a 75 MW combustion
turbine;
- $4 million in environmental projects; and
- $70$75 million for the proposed 345 kV transmission line to Nogales,
Arizona.
These estimated expenditures include costs for TEP to comply with
current federal and state environmental regulations. All of these estimates
are subject to continuing review and adjustment. Actual construction
expenditures may be different from these estimates due to changes in business
conditions, construction schedules, environmental requirements, and changes
to our business arising from retail competition. TEP plans to fund these
expenditures through internally generated cash flow.
Forecasted construction expenditures for 2003 include approximately $10
million for completing a new one mile 500-kV transmission line to enhance
TEP's distribution system link to the regional high voltage transmission
system.
In January 2001, TEP and Citizens Communications Company entered into a project development
agreement for the joint construction of a 62-mile transmission line from
Tucson to Nogales, Arizona. In January 2002, the ACC approved the location
and construction of the proposed 345 kV line. Pending federal studies and
approvals for the portion of the line that will pass through a national
forest, construction could begin as early as the first
quarter of 2003,mid-2004, with an expected in-servicein-
service date eight months following start of December 31,
2003.construction. Construction costs
are expected to be approximately $70$75 million. TEP has also applied to the
U.S. Department of Energy for a Presidential Permit that would allow building
an extension of the line across the international border with Mexico to
interconnect with Mexico's utility system, providing further reliability and
market opportunities in the region.
The estimated expenditures listed above do not include any amounts for
the potential expansion of the Springerville Generating Station.
Springerville generation expenditures are expected to be made by another
UniSource Energy subsidiary. See Investing and
Financing ActivitiesUED - UED,Unregulated Energy Business, below.
In addition to TEP's forecasted construction expenditures, TEP's other
capital requirements include its required debt maturities and capital lease
obligations. See Note 7 of Notes to Consolidated Financial Statements - Long-Term DebtStatements.
Financing Activities
--------------------
Net cash used for financing activities was significantly less in 2002
compared with 2001 primarily because TEP's dividends to its common
shareholders and Capital Lease
Obligations.payments on capital leases obligations were lower. In
2002, TEP paid $35 million in dividends to UniSource Energy and its other
common shareholders, retired $20 million in capital lease obligations and
paid $2 million in bond sinking fund payments and other redemptions. In
addition, we paid approximately $5 million in bank financing fees associated
with our new bank facilities. In contrast, in 2001, TEP paid $50 million in
dividends to UniSource Energy and its other common shareholders, retired $26
million in capital lease obligations and paid $2 million in bond sinking fund
payments and other redemptions.
Bond Issuance and Redemption
----------------------------
During 2002, TEP purchased and retired $0.4 million of its 8.50% First
Mortgage Bonds due in 2009 and made required sinking fund payments of $2
million. During 2001, TEP purchased and retired $0.2 million of its 8.50%
First Mortgage BondBonds due in 2009 and made required sinking fund payments of
$2 million.
During 2000, TEP repaid $47 million of its 12.22% Series First
Mortgage Bonds which matured on June 1. In addition, TEP purchased
and retired $2 million of its 7.50% First Collateral Trust Bonds and
made required sinking fund payments of $2 million.
Investments in Springerville Lease Debt
---------------------------------------
TEP invested $2 million in 2001 and $25 million in 2000 in
Springerville Unit 1 lease debt. TEP purchased these notes from
Millennium in May 2001 and November 2000. Millennium previously
purchased these notes in the open market in the first quarter of
2000. As of December 31, 2001, TEP's total investment in
Springerville Unit 1 lease debt was $71 million. These investments
bear interest at 10.21% and 10.73%, with yields ranging from 8.9% to
11.1%. See Note 8 of Notes to Consolidated Financial Statements.
In January 2002, TEP purchased all $96 million of the
outstanding Springerville Coal Handling Facilities Lease Debt, for a
purchase price of $101 million. This lease debt carries a weighted
average coupon rate of 14.3%.
Investment in Springerville Lease Equity
----------------------------------------
In December 2001, TEP purchased a 13% ownership interest in the
Springerville Coal Handling Facilities Leases for $13 million. In
the first quarter of 2002, TEP intends to cancel that portion of the
leases related to its ownership interest, as it now holds both the
ownership interest and the debt.
TEP Bank Credit Agreement
-------------------------
In November 2002, TEP hasentered into a $441new $401 million Credit Agreement
with a number of banks
which matures onto replace the credit facilities provided under its then existing $441
million credit agreement that would have expired December 30, 2002. The new
agreement consists of a $100$60 million Revolving Credit Facility and atwo letter
of credit (LOC) facilities (Tranche A and Tranche B) totaling $341 million Letter of
Credit Facility.million.
The Revolving Credit Facility is used to provide liquidity for general
corporate purposes. The Letter of Credit
Facility supportsLOC Facilities support $329 million aggregate
principal amount of tax-
exempttax-exempt variable rate debt.debt obligations. The Revolving
Credit Facility is a 364-day facility that expires on November 13, 2003. The
Tranche A letters of credit, totaling $135 million, expire in January 2006,
and the Tranche B letters of credit, totaling $206 million, expire in
November 2006.
The new facilities are secured by $441$401 million in aggregate principal
amount of Second Mortgage Bonds.Bonds issued under TEP's General Second Mortgage
Indenture. The new Credit Agreement contains a number of restrictive
covenants that are similar to TEP's previous credit agreement, including
restrictions on additional indebtedness, liens, sale of assets, or mergers and
sale-leasebacks. The new Credit Agreement, like the previous agreement, also
contains several financial covenants includingincluding: (a) a minimum Consolidated
Tangible Net Worth, equal to the sum of $133 million
plus 40% of cumulative Consolidated Net Income since January 1,
1997, (b) a minimum Cash Coverage Ratio, ranging from 1.50 in 2001
and increasing to 1.55 in 2002, and (c) a maximum
Leverage Ratio
ranging from 6.40Ratio. Under the terms of the new Credit Agreement, TEP may pay
dividends so long as it maintains compliance with the Credit Agreement;
however, dividends and certain investments in 2001 and decreasing to 6.20affiliates may not exceed 65%
of TEP's net income so long as the Tranche B LOCs are outstanding. The new
Credit Agreement also provides that under certain circumstances, certain
regulatory actions could result in 2002.a required reduction of the commitments.
As of December 31, 2001,2002, TEP was in compliance with these financial covenants.
The $329 million in aggregate principal amount of tax-exempt variable
rate debt that is supported by the LOC Facilities were classified as Current
Maturities of Long-Term Debt on TEP's Balance Sheet at December 31, 2001
because the previous letter of credit facility matured on December 30, 2002.
When the new LOCs were issued on November 25, 2002, TEP classified the bonds
as Long-Term Debt because the maturities of the new LOCs are in January 2006
and November 2006.
Due to prevailing market conditions at the time of refinancing,
particularly in the energy sector, the amount of interest and fees that TEP
will pay on its new Credit Facilities is significantly higher than that of
its previous credit agreement. TEP's annual interest expense, including LOC
fees, related to its Credit Agreement will increase from approximately $6
million to approximately $19 million.
If TEP borrows under the Revolving Credit Facility, the borrowing costs
would be at a variable interest rate consisting of a spread over LIBOR or an
alternate base rate. The spread is based upon a pricing grid tied to theTEP's
credit rating on TEP's senior
secured debt.ratings. Also, TEP pays a commitment fee on the unused portion of the
Revolving Credit Facility, and a fee on the Letter of Credit
Facility. TheseLOC Facilities. The chart below
shows the per annum rates and fees are also dependentin effect on TEP's Credit Facilities as of
December 31, 2002, based on its credit ratings.ratings, as well as the possible range
of rates and fees if TEP's credit ratings were to change:
Current Rate/ Range of
Fee Rate / Fees
-------------------------------------------------------------------------
Revolving Credit Facility
- Commitment Fee 0.35% 0.25% to 0.40%
- Borrowing Rate (spread over LIBOR) 4.00% 3.50% to 4.25%
Tranche A LOCs (including LOC Fronting Fee) 4.25% 3.75% to 4.50%
Tranche B LOCs (including LOC Fronting Fee) 5.75% 5.75%
At December 31, 2001, the commitment fee was 0.25% per year, and the
letter of credit fee (excluding letter of credit fronting fees of
0.125%) was 1.125% per year.2002, there were no outstanding borrowings under this
facility. In January 2003, TEP had no borrowings outstandingborrowed $25 million under theits Revolving
Credit Facility at December 31, 2001.and repaid it within 20 days. If TEP intends to enter into a new credit agreement prior toencounters temporary
cash needs during the maturitycourse of the year, it will borrow from its existingRevolving
Credit Agreement, in a structure
substantially similar to its existing facilities. We cannot,
however, predict the terms and the pricing that will be available at
this time. The $329 million in aggregate principal amount of tax-
exempt variable rate debt that is supported by the Letter of Credit
Facility has been classified as Current Maturities of Long-Term Debt
on TEP's Balance Sheet for the period ended December 31, 2001
because the Letter of Credit Facility matures on December 30, 2002.
When a longer term Letter of Credit Facility has been completed, the
bonds will be classified as Long-Term Debt.Facility.
Tax-Exempt Local Furnishing Bonds
---------------------------------
TEP has financed a substantial portion of utility plant assets with
industrial development revenue bonds issued by the Industrial Development
Authorities of Pima County and Apache County. The interest on these bonds is
excluded from gross income of the bondholder for federal tax purposes. This
exclusion is allowed because the facilities qualify as "facilities for the
local furnishing of electric energy" as defined by the Internal Revenue Code.
These bonds are sometimes referred to as "tax-exempt local furnishing bonds."
To qualify for this exclusion, the facilities must be part of a system
providing electric service to customers within not more than two contiguous
counties. TEP provides electric service to retail customers in the City of
Tucson and certain other portions of Pima County, Arizona and to Fort
Huachuca in contiguous Cochise County, Arizona.
TEP has financed the following facilities, in whole or in part, with the
proceeds of tax-exempt local furnishing bonds: Springerville Unit 2,
Irvington Unit 4, a dedicated 345-kV transmission line from Springerville
Unit 2 to TEP's retail service area (the Express Line), and a portion of
TEP's local transmission and distribution system in the Tucson metropolitan
area. As of December 31, 2001,2002, TEP had approximately $580$584 million of tax-exempttax-
exempt local furnishing bonds outstanding. Approximately $325$331 million in
principal amount of such bonds financed Springerville Unit 2 and the Express
Line. In addition, approximately $72$65 million of remaining lease debt related
to the Irvington Unit 4 lease obligation was issued as tax-exempt local
furnishing bonds.
Various events might cause TEP to have to redeem or defease some or all
of these bonds:
- formation of an RTO or ISO;
- transfer of generating assets to a separate subsidiary;
- asset divestiture;
- changes in tax laws; or
- changes in system operations.
TEP believes that its qualification as a local furnishing system should
not be lost so long as (1) the RTO or ISO would not change the operation of
the Express Line or the transmission facilities within TEP's local service
area, (2) the RTO or ISO allows pricing of transmission service such that the
benefits of tax-
exempttax-exempt financing continue to accrue to retail customers, and
(3) energy produced by Springerville Unit 2 and by TEP's local generating
units continues to be consumed in TEP's local service area. However, there
is no assurance that such qualification can be maintained. Any redemption or
defeasance of tax-exempt local furnishing bonds would likely require the
issuance and sale of higher cost taxable debt securities in the same or a
greater principal amount.
Mortgage Indentures
-------------------
TEP's first mortgage indenture and second mortgage indenture create
liens on and security interests in most of TEP's utility plant assets.
Springerville Unit 2, which is owned by San Carlos, is not subject to these
liens and security interests. TEP's mortgage indentures allow TEP to issue
additional mortgage bonds on the basis of: (1) a percentage of net utility
property additions and/or (2) the principal amount of retired mortgage bonds.
The amount of bonds that TEP may issue is also subject to a net earnings test
under each mortgage indenture.
At December 31, 2001, TEP hadTEP's Credit Agreement contains limits on the ability to issue
approximately $152 millionamount of new First and Second
Mortgage Bonds on the basis
of property additions. TEP also had the ability to issue about $519
million of new First Mortgage Bonds on the basis of retired First
Mortgage Bonds.
TEP'sthat may be outstanding. The Credit Agreement allows no more
than $411$222 million of First Mortgage Bonds to be outstanding, and no more than
$623 million in First and Second Mortgage bonds, combined to be outstanding.
There were $224At December 31, 2002, TEP had $222 million of First Mortgage Bonds outstanding at December 31, 2001. Additionally,and a
total of $623 million in First and Second Mortgage Bonds outstanding.
Although the first and second mortgage indentures would allow TEP to issue
additional bonds based on property additions and/or retired bond credits, the
limits imposed by the Credit Agreement contains certain financial covenants that limitare more restrictive and are currently
the amount of new debt obligations TEP may issue. See TEP Bank Credit
Agreement above. Currently, TEP has no plans to issue additional
First Mortgage Bonds.
If TEP issued Second Mortgage Bonds based on retired First
Mortgage Bonds, the amount of retired First Mortgage Bonds available
to issue new First Mortgage Bonds would be reduced by the same
amount.
At December 31, 2001, TEP had the ability to issue about $726
million of new Second Mortgage Bonds on the basis of net property
additions. Also, TEP had the ability to issue approximately $672
million of new Second Mortgage Bonds on the basis of retired bonds.
Using an interest rate of 7.5%, the net earnings test would allow
such issuance of Second Mortgage Bonds. These calculations assume
that no additional First Mortgage Bonds would be issued other than
to refund First Mortgage Bonds outstanding at December 31, 2001.
However, issuance of these amounts would be limited by financial
covenants in TEP's bank Credit Agreement.governing limitations.
TEP also has the ability to release property from the liens of the
mortgage indentures on the basis of net property additions and/or retired
bond credits. The Credit Agreement also limits the amount of property that
can be released from the second mortgage indenture to $25 million.
Springerville Common Facilities Leases
--------------------------------------
In 1985, TEP sold and leased back its undivided one-half ownership
interest in the common facilities at the Springerville Generating Station.
Under the terms of the Springerville Common Facilities Leases, TEP must
periodically refinance or refund the secured notes underlying the leases
prior to the named date in order to avoid a special event of loss. If the
lease debt is not refinanced prior to the special event of loss date
(currently June 30, 2003), the leases would be terminated and TEP would be
required by its current
Settlement Agreement to form a wholly-owned generation subsidiary by
December 31, 2002. If this process proceeds,repurchase the facilities.
In January 2003, TEP filed an application with the ACC for authorization
to amend the Springerville Common Facilities Leases and refinance the $70
million of associated lease debt. The interest rate on new lease debt will
be transferring certain property toa function of market conditions at the generation subsidiarytime of refinancing, the lender's
view of TEP's creditworthiness, and may
release all or a portionthe lender's evaluation of the property fromcollateral
for the lienssecured notes. As a result of the indentures basedcurrent market conditions and a
smaller financing market overall, we expect that the interest rate on the fair market valuesnew
debt will likely be higher than the current variable interest rate of the properties
transferred.LIBOR
plus 2.50%, resulting in higher rents payable by TEP.
MILLENNIUM --- UNREGULATED ENERGY BUSINESSES
During 2001 and 2000, we have taken the opportunity to realize
the value from certain of the more capital-intensive investments and
focus on emerging energy production and storage technologies. We
expect this trend to continue in 2002 as we look to sell our interests
in our remaining Nations Energy investments and continue to clarify and
narrow the focus of our Energy Technology Investments.
Below we discuss our significant investments, commitments and investment
proceeds from 2002, 2001 and 2000.
Investments in Energy Technologies
----------------------------------
As of December 31, 2001, Millennium had provided the following funding underto its commitments to these Energy Technology
Investments:
2002 2001 2000
---------------------------------------------------------------------
- $19 million in debt toMillions of Dollars -
Cash Funding Provided To:
Global Solar drawn on a $20 million line
of credit commitment;$ 13 $ 15 $ 18
IPS 4 6 -
$6 million in debtITN 1 5 -
MicroSat - 10 -
---------------------------------------------------------------------
Total Cash Funding Provided to fully fund a credit commitment to Infinite
Power Solutions;
- $10 million in equity contributions to fully fund an equity
commitment to MicroSat; and
- $3 million in equity contributions and $2 million in debt on a $4
million line of credit commitment to ITN Energy
Systems.Technology Investments $ 18 $ 36 $ 18
=====================================================================
Millennium expects to fund the remaining balance of $14between $7 million under its current commitmentsand $15 million to its
various energy technology
investmentsEnergy Technology Investments in 2002.2003. By March 5, 2003,
approximately $4 million of Millennium's remaining commitment had been
funded. A significant portion of the funding under these agreements has been
and will be utilizedused for research and development purposes, establishment of the
production line, and other administrative costs. As these funds are expended
for these
purposes, we will recognizeresearch and development and for administrative costs, Millennium
recognizes expense.
As of December 31, 2001,2002, including accumulated deferred tax benefits
relating to these investments, Millennium had approximately $45$50 million
investedremaining investment in thesethe Energy Technology Investments. IfAs discussed
above, we fund
the $14 million as expected in 2002, our total investment will be
$59 million. We may commit to provide additional funding to these investments.
During 2002,2003, we will analyze the prospects for each of these investments and
determine if additional internal funding is needed, and
whether we will provide suchneeded. In addition, external
sources of funding or if we will lookare being sought for outside
funding sources.these investments. If management
determines that any of these entities are not viable, weMillennium would takerecord
expense up to the appropriate write-offs.entire remaining investment balance of such entity.
Nations Energy
--------------
In 2002, Millennium did not and currently does not intend to make any
material investments in new projects through Nations Energy. Millennium
continues to review options for the sale of Nations Energy's remaining
investment, a power project in Panama with a book value of less than $1
million.
In 2001, Nations Energy recorded an after-tax gain of $6 million from
the sale of its interest in the Curacao project. Nations Energy received $5
million in cash proceeds and recorded ana net present valued $8 million note
receivable in connection with this transaction. In addition, $15 million in
related construction deposits were returned to Nations Energy. At December
31, 2002, including accretion, the note receivable balance is $9 million. We
describe this note more fully in Note 4 of Notes to Consolidated Financial
Statements - Millennium Energy Businesses - Nations Energy Contingency.
In 2000, Nations Energy sold its interest in a project located in the
Czech Republic resulting in a $3 million pre-tax gain.
Currently we do not intend to make any material investments in
new projects through Nations Energy and we continue to review
options for the sale of Nations Energy's remaining investment.
Other Investments and Commitments
---------------------------------
During 2001,
Millennium provided funding to the following investments:
Millennium invested $20 million in Sabinas. Sabinas also owns 19.5% of
Mimosa. In December 2002, Millennium received a return of capital of $0.5
million, bringing Millennium's investment at December 31, 2002 to
approximately $19.5 million. In the first quarter of 2003, Millennium
received an additional return of capital of $0.5 million. Millennium owns
50% of Sabinas; the other half is owned by AHMSA. UniSource Energy's
Chairman, President and Chief Executive Officer is a member of the board of
directors of AHMSA.
In 2002, Millennium provided a loan of approximately $5 million to MEG.
In 2001, Millennium contributed $5 million in capitalequity and a $4 million in
debtloan to
MEG. SuchThese funds were used to provide sufficient working capital to facilitate MEG's
entry intoactivities in the emission allowance and coal markets.
Millennium contributed $2 million in 2002 and $3 million in 2001 in
equity funding to Powertrusion, in exchange forPowertrusion. Millennium owns a controlling 50.5% interest
in Powertrusion.
Maintaining controlMillennium provided funding to TruePricing of Powertrusion will depend upon
many factors, including providing an additional $2 million in contingent consideration by August 2002. Contribution2002 and
$1.1 million in 2001. TruePricing is a start-up company established to
market energy related products. In February 2003, Millennium committed to
fund up to an additional $1.2 million in equity to TruePricing of the
contingent additional investment will be solely determined by
Millennium.which $0.4
million was funded on March 5, 2003.
Millennium contributed $4$1 million in 2002, $4.2 million in 2001 and $1.4
million in 2000 to Haddington Energy Partners II LP, a limited partnership
that funds energy related investments. This investment brings Millennium's
funding to approximately $6$6.6 million. The funding is part of a $15 million
commitment made during 2000. The remaining funds are expected to be invested
within two to three years. A member of the UniSource Energy Board of
Directors has a minor investment in the project. An affiliate of such board
member serves as the general partner.
Millennium madehas a $1$6 million investment incapital commitment to a venture capital fund. The fund
will focusthat focuses on information technology, opticsmicroelectronics, and biotechnology
investments primarily within the retail service
territory of TEP. This funding was made as part of a $5 million
commitment made during 2000. Millennium expects to fund
approximatelyin Arizona, Southern California, New Mexico, Colorado and Utah.
Approximately $1 million underhas been funded from inception through December 31,
2002. Millennium does not currently expect to provide additional funding to
this agreementcommitment in 2002. A2003. Another member of the UniSource Energy Board of
Directors ownsis a general partner of the company that manages the fund.
Sale of NewEnergy, Inc.
-----------------------
During 1999, MEH sold its 50% ownership in NewEnergy to the AES
Corporation (AES) for approximately $50 million. The transaction
resulted in a pre-tax gain of $35 million and the receipt of two
promissory notes totaling $23 million. One of the promissory notes
in the principal amount of $11 million was paid during 2000 and the
remaining promissory note was paid during 2001.
UED -- UNREGULATED ENERGY BUSINESS
UED is responsible as project developer for facilitating the
Springerville Generating Station expansion project construction. If
constructed, each of Springerville Units 3 and 4. On October 19, 2001,4 would consist of a 400 MW coal-fired, base-
load generating unit at the same site as Springerville Units 1 and 2. This
would allow TEP to spread the fixed costs of the existing common facilities
over the additional generating unit (or units). Upon completion of Unit 3,
TEP expects to receive annual benefits of approximately $10 million to $15
million in the form of cost savings, rental payments and other fees. TEP
will also benefit from upgraded emissions controls for Units 1 and 2 that
will be paid for by the Unit 3 project.
To date, we have funded approximately $22 million for development of the
project. In January 2003, UED and SRPTri-State signed a joint development agreementDevelopment Cost
Agreement to each share ownership and50% of the remaining development costs of Springerville Units 3 and 4. We expect that
SRP would also purchase 50% of the power generation from the
facility. These purchases would be pursuant to a long-term power
purchase agreement, which is in the process of being negotiated.
The balance of the power generation would be sold to other regional
power companies, possibly including TEP. We anticipate that power
purchase agreements with other project off-takers, the engineering,
procurement and construction contract, and the construction
financing will be in place during the third quarter of 2002. We
expect that construction will begin by the fourth quarter of 2002,
with commercial operation of Unit 3
expected to occur in early 2006,
followed six to twelve months later by Unit 4. We expecteffective from November 6, 2002 until financial close. UED expects to
provide between $30 million and $100an additional $4 million in funding for development prior to a third
party obtaining the construction financing. UED during 2002.expects the third party to
obtain construction financing in the second quarter of 2003. Our funding to
UED for equity will depend upon the timinglevel of ownership by the financial
close of the project and UED's ultimate ownership percentage of the
project. Total construction costs for this project are expected to
range from $900 million to $1 billion from 2002 to 2006, and total
project costs, which include construction costs, various development
costs and interest during construction, are expected to exceed $1.4
billion.third party.
We can make no assurances, however, about the ultimate timing, or whether weUED
will proceed with this project.
FINANCING RISKS
UniSource Energy and TEP are exposed to risks related to the ability to
obtain financing at reasonable costs for various projects, agreements to
which they are a party, and their debt obligations. During 2002, the market
for bank financings was less liquid and more volatile than in recent years
due to a number of defaults and deteriorating financial condition of many
corporate borrowers, particularly in the energy industry. As a result, when
TEP refinanced its bank Credit Agreement in November 2002, it was required to
pay significantly higher interest and fees on its new credit facilities than
it paid on its previous credit facilities. See TEP Bank Credit Agreement,
above. During 2003, UniSource Energy, TEP and UED will be subject to
financing risks and capital market conditions related to the following:
- UniSource Energy has entered into Asset Purchase Agreements to
purchase the Citizens Arizona electric utility and gas utility assets
for $230 million. UniSource Energy expects that a portion of the
purchase price will be financed with debt secured by the purchased
assets. UniSource Energy may also consider financing a portion of the
purchase price with new equity, depending on market conditions and other
considerations. If UniSource Energy were unable to obtain financing,
and therefore were unable to consummate the purchase of these assets,
this would constitute a breach under the contracts and termination
damages would be payable.
- UED is currently evaluating opportunities to expand the Springerville
Station by assigning the rights to construct Springerville Units 3 and 4
to unrelated third parties. As of December 31, 2002, UED had
approximately $22 million of capitalized project development costs on
its balance sheet. If a third party does not obtain financing for this
project and as a result, this project does not proceed, the capitalized
project development costs would immediately be expensed.
- TEP must refinance or extend the $70 million of lease debt related to the
Springerville Common Facilities Leases before June 30, 2003. Due to the
ongoing difficult captial market conditions in the energy sector, TEP
will likely be required to pay a higher rate of interest on the new debt
than its existing rate of LIBOR plus 2.5%.
- TEP intends to refinance or extend its 364 day Revolving Credit Facility,
which expires on November 13, 2003.
CONTRACTUAL OBLIGATIONS
The following charts display TEP's contractual obligations by maturity
and by type of obligation, and provide additional detail on TEP's capital
lease obligations.
TEP's Contractual Obligations
- Millions of Dollars -
- ---------------------------------------------------------------------------------------------------------
IDBs Total
Supported Long- Capital Unconditional Contractual
Payments Due in Years by Expiring Term Lease Operating Purchase Cash
Ending December 31, LOCs (1) Debt Obligations (2) Leases Obligations (3) Obligations
- ---------------------------------------------------------------------------------------------------------
2003 $ - $ 2 $ 121 $ 2 $ 81 $ 206
2004 - 2 124 1 78 205
2005 - 2 125 1 75 203
2006 329 21 127 1 72 550
2007 - 1 128 1 72 202
- ---------------------------------------------------------------------------------------------------------
Total 2003 - 2007 329 28 625 6 378 1,366
Thereafter - 773 965 3 278 2,019
Less: Imputed Interest - - (746) - - (746)
- ---------------------------------------------------------------------------------------------------------
Total $ 329 $801 $ 844 $ 9 $ 656 $2,639
=========================================================================================================
(1) TEP's tax-exempt variable rate bonds (IDBs) in the amount of $329 million are backed by LOCs
under TEP's Credit Agreement. TEP's obligations under the Credit Agreement are collateralized
with Second Mortgage Bonds. These IDBs were classified as short-term debt at December 31,
2001, because the existing LOCs were scheduled to expire on December 30, 2002. New LOC
facilities were obtained in November 2002 and the IDBs were classified as long-term debt
December 31, 2002.
(2) See TEP's Capital Lease Contractual Obligations table below.
(3) These obligations represent future guaranteed payments under TEP's natural gas, coal and rail
transportation contracts.
TEP's Capital Lease Obligations
- Millions of Dollars -
- --------------------------------------------------------------------------------------------------------------
Springerville Springerville Irvington Springerville Rail Car Total Capital
Payments Due in Years Unit 1 Coal Unit 4 Common Lease Lease
Ending December 31, Handling Obligations
- --------------------------------------------------------------------------------------------------------------
2003 $ 84 $ 19 $ 13 $ 5 $ - $ 121
2004 86 18 13 6 1 124
2005 86 19 12 7 1 125
2006 85 24 11 7 - 127
2007 85 24 13 6 - 128
- --------------------------------------------------------------------------------------------------------------
Total 2003 - 2007 426 104 62 31 2 625
Thereafter 606 148 39 172 - 965
Less: Imputed Interest (529) (120) (20) (77) - (746)
- --------------------------------------------------------------------------------------------------------------
Total $ 503 $ 132 $ 81 $ 126 $ 2 $ 844
==============================================================================================================
Contractual obligations of Millennium, UED, and UniSource Energy
stand-alone are not significant. UniSource Energy has contingent
obligations under various surety bonds that total approximately $0.5
million.
As discussed above, TEP has the full amount available under its $60
million Revolving Credit Facility. If TEP draws any amount under this
facility, such borrowing would become a contractual obligation of TEP at that
time. We have no other commercial commitments to report.
We have reviewed our contractual obligations and provide the following
additional information:
- TEP does not have any provisions in any of its debt or lease
agreements that would cause an event of default or cause amounts to
become due and payable in the event of a credit rating downgrade.
- None of our contracts or financing structures contains provisions or
acceleration clauses due to changes in our stock price.
- TEP's Credit Agreement contains pricing tied to a grid based on the
ratings of TEP's Credit Facilities. A change in TEP's credit rating can
cause an increase or decrease in the amount of interest and fees TEP
pays for these facilities.
- TEP's Credit Agreement contains certain financial and other
restrictive covenants, including interest coverage, leverage and net
worth tests. Failure to comply with these covenants would entitle the
lenders to accelerate the maturity of all amounts outstanding. At
December 31, 2002, TEP was in compliance with these covenants. See TEP
Bank Credit Agreement, above.
- TEP conducts its wholesale trading activities under the Western
Systems Power Pool Agreement (WSPP) which contains provisions whereby
TEP may be required to post margin collateral due to a change in credit
rating or changes in contract values. As of December 31, 2002, TEP has
not been required to post such collateral.
- MEG conducts its emissions and coal trading activities using certain
contracts which contain provisions whereby MEG may be required to post
margin collateral due to a change in contract values. As of December
31, 2002, MEG had posted $2 million in cash collateral to its trading
counterparties.
- MEG has a $5 million bank line of credit for the purpose of issuing
LOCs to counterparties to support its emission allowance and coal
marketing and trading activities. As of December 31, 2002, MEG had $2
million in outstanding LOCs. This facility expires in August 2004.
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain
subsidiaries, including TEP, enter into various agreements providing
financial or performance assurance to third parties on behalf of certain
subsidiaries. These agreements are entered into primarily to support or
enhance the creditworthiness otherwise attributed to a subsidiary on a stand-
alone basis, thereby facilitating the extension of sufficient credit to
accomplish the subsidiaries' intended commercial purposes. The most
significant of these guarantees supports up to approximately $3.5 million in
commodity-related payments for MEG at December 31, 2002. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheets.
In addition, UniSource Energy and its subsidiaries have indemnified the
purchasers of interests in certain investments from additional taxes due for
years prior to the sale. The terms of the indemnifications provide for no
limitation on potential future payments; however, we believe that we have
abided by all tax laws and paid all tax obligations. We have not made any
payments under the terms of these indemnifications to date.
We believe that the likelihood UniSource Energy or TEP would be required
to perform or otherwise incur any significant losses associated with any of
these guarantees is remote.
DIVIDENDS ON COMMON STOCK
UniSource Energy
----------------
On February 7, 2003, UniSource Energy declared a cash dividend of $0.15
per share on its Common Stock. The dividend, totaling approximately $5
million, is payable March 7, 2003 to shareholders of record at the close of
business February 21, 2003. During 2002 and 2001, UniSource Energy paid
equal quarterly dividends to its shareholders of $0.125 and $0.10 per share,
totaling $17 million and $13 million, respectively.
UniSource Energy's Board of Directors will review our dividend level on
a continuing basis, taking into consideration a number of factors including
our results of operations and financial condition, general economic and
competitive conditions and the cash flows from our subsidiary companies, TEP,
Millennium and UED.
TEP
---
TEP declared and paid dividends of $35 million in 2002, $50 million in
2001, and $30 million in 2000. UniSource Energy is the primary holder of
TEP's common stock.
TEP can pay dividends if it maintains compliance with the TEP Credit
Agreement and certain financial covenants, including a covenant that requires
TEP to maintain a minimum level of net worth. As of December 31, 2002, the
required minimum net worth was $286 million. TEP's actual net worth at
December 31, 2002 was $337 million. See TEP - Electric Utility, Financing
Activities, TEP Bank Credit Agreement, above. As of December 31, 2002, TEP
was in compliance with the terms of the Credit Agreement. Under the terms of
the Credit Agreement, dividends and certain investments in affiliates may not
exceed 65% of TEP's net income for the immediately preceding fiscal year, so
long as the Tranche B LOCs are outstanding.
The ACC Holding Company Order states that TEP may not pay dividends to
UniSource Energy in excess of 75% of its earnings until TEP's equity ratio
equals 37.5% of total capital (excluding capital lease obligations). As of
December 31, 2002, TEP's equity ratio on that basis was 23%.
In addition to these limitations, the Federal Power Act states that
dividends shall not be paid out of funds properly included in the capital
account. Although the terms of the Federal Power Act are unclear, we believe
that there is a reasonable basis to pay dividends from current year earnings.
Therefore, TEP declared its December 2002, 2001, and 2000 dividends from
2002, 2001, and 2000 earnings, respectively.
Millennium and UED
------------------
Millennium did not pay any dividends to UniSource Energy in 2002, 2001
or 2000. We cannot predict the amount or timing of future dividends from
Millennium. UED has not paid any dividends to UniSource Energy.
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
See Note 1 of Notes to Consolidated Financial Statements.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
- ------------------------------------------
This Annual Report on Form 10-K contains forward-looking statements as
defined by the Private Securities Litigation Reform Act of 1995. UniSource
Energy and TEP are including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by or for UniSource Energy or TEP in this Annual Report on Form 10-K.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events or performance and underlying assumptions
and other statements that are not statements of historical facts. Forward-lookingForward-
looking statements may be identified by the use of words such as
"anticipates," "estimates," "expects," "intends," "plans," "predicts,"
"projects," and similar expressions. From time to time, we may publish or
otherwise make available forward-looking statements of this nature. All such
forward-looking statements, whether written or oral, and whether made by or
on behalf of UniSource Energy or TEP, are expressly qualified by these
cautionary statements and any other cautionary statements which may accompany
the forward-looking statements. In addition, UniSource Energy and TEP
disclaim any obligation to update any forward-looking statements to reflect
events or circumstances after the date of this report.
Forward-looking statements involve risks and uncertainties, which could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements. We express our expectations, beliefs and
projections in good faith and believe them to have a reasonable basis.
However, we make no assurances that management's expectations, beliefs or
projections will be achieved or accomplished. We have identified the
following important factors that could cause actual results to differ
materially from those discussed in our forward-looking statements. These may
be in addition to other factors and matters discussed in other parts of this
report:
1. Effects of restructuring initiatives in the electric industry and
other energy-related industries.
2. Effects of competition in retail and wholesale energy markets.
3. Changes in economic conditions, demographic patterns and weather
conditions in TEP's retail service area.
4. Supply and demand conditions in wholesale energy markets, including
volatility in market prices and illiquidity in markets, which are
affected by a variety of factors. These factors include the
availability of generating capacity in the West,western U.S., including
hydroelectric resources, weather, natural gas prices, the extent of
utility restructuring in various states, transmission constraints,
environmental restrictions and cost of compliance, and FERC regulation of
wholesale energy markets.markets, and economic conditions in the western U.S.
5. The creditworthiness of the entities with whom UniSource Energy,
TEP, Millennium and their affiliates transact business.
6. Changes affecting TEP's cost of providing electrical service
including changes in fuel costs, generating unit operating
performance, scheduled and unscheduled plant outages, interest rates,
tax laws, environmental laws, and the general rate of inflation.
6.7. Changes in governmental policies and regulatory actions with respect
to financingsfinancing and rate structures.
7.8. Changes affecting the cost of competing energy alternatives,
including changes in available generating technologies and changes in
the cost of natural gas.
8.9. Changes in accounting principles or the application of such
principles to UniSource Energy or TEP.
9.10. Market conditions and technological changes affecting UniSource
Energy's unregulated businesses.
11. Regulatory conditions to the approval of the acquisition of
Citizens' Arizona electric and gas utility assets.
12. The level of rate relief granted with respect to Citizens' Arizona
electric utility and gas utility assets.
13. Unanticipated changes in future liabilities relating to employee
benefit plans due to changes in market values of its retirement plan
assets and health care costs.
14. The outcome of any ongoing litigation.
15. Ability to obtain financing through debt and/or equity issuance,
which can be affected by various factors, including interest rate
fluctuations and capital market conditions.
16. Whether the proposed Springerville Generating Station expansion
proceeds; the role of Tri-State, SRP, and other third parties in such
expansion; and the terms of the ownership, operating and power
purchase arrangements ultimately utilized.
ITEM 7A. - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------
See Item 7. - Management's Discussion and Analysis of Financial
Condition and Results of Operations, Factors Affecting Results of Operations,
Market Risks.
ITEM 8. - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
See Item 14,15, page 106,111, for a list of the Consolidated Financial
Statements that are included in the following pages. See Note 1816 of Notes to
Consolidated Financial Statements.
APPROVAL OF NON-AUDIT SERVICES
On February 6, 2002, the Audit Committee of the Board of Directors of
UniSource Energy pre-approved ongoing non-audit related services, for fees
not to exceed $600,000, to be performed by our independent auditor,
PricewaterhouseCoopers LLP (PwC), consisting of accounting and tax research
in connection with the financings of Springerville Units 3 and 4.
On August 1, 2002, the Audit Committee of the Board of Directors of
UniSource Energy pre-approved certain non-audit related services, for fees
not to exceed $30,000, to be performed by PwC, including rate case training
for certain of our employees.
On October 17, 2002, the Audit Committee of the Board of Directors of
UniSource Energy pre-approved non-audit related services, for fees not to
exceed $100,000, to be performed by PwC, consisting of performance of certain
tests of financial, statistical and rate-making data relating to the Arizona
gas and electric assets of Citizens.
On December 5, 2002, the Audit Committee of the Board of Directors of
UniSource Energy pre-approved PwC to perform audit related services of the
gas and electric asset balances and results of operations therefore for
Citizens Utilities, Inc., located in Arizona, for fees not to exceed
$250,000. This replaces the Audit Committee's previous authorization of
October 17, 2002 for non-audit related services, for fees not to exceed
$100,000. The audits cover periods prior to the proposed acquisition date of
such assets by UniSource Energy.
Report of Independent Accountants
To the Board of Directors and Stockholders of
UniSource Energy Corporation and to the
Board of Directors and StockholderStockholders of
Tucson Electric Power Company
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)15(a)(1) present fairly, in all material respects, the
financial position of UniSource Energy Corporation and its subsidiaries (the
Company) and Tucson Electric Power Company and its subsidiaries (TEP) at
December 31, 20012002 and 2000,2001, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 20012002
in conformity with accounting principles generally accepted in the United
States of America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 14
(a)15(a)(2) presents fairly,
in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These
financial statements and financial statement schedule are the responsibility
of the Company's and TEP's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based
on our audits. We conducted our audits of these statements in accordance
with auditing standards generally accepted in the United States of America,
which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated financial statements, the Company
and TEP changed their method of accounting for derivative instruments as of
January 1, 2001.
PricewaterhouseCoopers LLP
Los Angeles, California
February 1, 20026, 2003
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
2002 2001 2000 1999
- -----------------------------------------------------------------------------
-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $ 666,049 $ 670,117 $ 664,646
$ 629,900
Electric Wholesale Sales 761,255177,908 733,559 359,814
171,219
Net Unrealized LossGain (Loss) on TEP Forward
SalesContracts and PurchasesMEG Trading Activities 644 (1,347) - -
Other Revenues 11,621 14,683 9,209 13,709
- -----------------------------------------------------------------------------
Total Operating Revenues 1,444,708856,222 1,417,012 1,033,669 814,828
- -----------------------------------------------------------------------------
Operating Expenses
Fuel 209,712 258,761 239,939
194,205
Purchased Power 570,28364,504 542,587 207,596 92,144
Coal Contract Termination and
Amendment FeeFees 11,250 - 13,231 -
Capital Lease Expense - - 85,320
Amortization of Springerville
Unit 1 Allowance - - (29,098)
Other Operations and Maintenance 188,910 179,036 181,392 159,721
Depreciation and Amortization 127,923 120,346 114,038 92,740
Amortization of Transition Recovery
Asset 24,554 21,609 17,008 2,241
Taxes Other Than Income Taxes 45,508 46,213 50,137 48,473
- -----------------------------------------------------------------------------
Total Operating Expenses 1,196,248672,361 1,168,552 823,341 645,746
- -----------------------------------------------------------------------------
Operating Income 183,861 248,460 210,328 169,082
- -----------------------------------------------------------------------------
Other Income (Deductions)
Interest Income 20,654 14,600 13,532 9,606
Gain on the Sale of NewEnergy - - 34,651
Other Income (Deductions) 189 3,868 (468) (2,380)
- -----------------------------------------------------------------------------
Total Other Income (Deductions) 20,843 18,468 13,064 41,877
- -----------------------------------------------------------------------------
Interest Expense
Long-Term Debt 61,218 66,377 66,83665,620 68,678 75,076
Interest on Capital Leases 90,402 92,712 16,26787,801 90,559 92,869
Interest Imputed on Losses Recorded at
Present Value 1,166 820 198 29,159
Other Interest Expense, 6,139 7,059 10,995Net of Amounts
Capitalized (36) (1,478) (1,797)
- -----------------------------------------------------------------------------
Total Interest Expense 154,551 158,579 166,346 123,257
- -----------------------------------------------------------------------------
Income Before Income Taxes Extraordinary Item and
Cumulative Effect of Accounting Change 50,153 108,349 57,046
87,702
Income Taxes 16,878 47,474 15,155 31,192
- -----------------------------------------------------------------------------
Income Before Extraordinary Item and Cumulative Effect of
Accounting Change 33,275 60,875 41,891 56,510
Extraordinary Item - Net of Tax - - 22,597
Cumulative Effect of Accounting Change
- Net of Tax - 470 - -
- -----------------------------------------------------------------------------
Net Income $ 33,275 $ 61,345 $ 41,891 $ 79,107
=============================================================================
Average Shares of Common Stock
Outstanding (000) 33,39933,665 33,398 32,445 32,321
=============================================================================
Basic Earnings per Share
Income Before Extraordinary Item and
Cumulative Effect of
Accounting Change $0.99 $1.83 $1.29 $1.75
Extraordinary Item - Net of Tax - - $0.70
Cumulative Efect of Accounting Change
- Net of Tax $0.01 - -
Net Income $1.84 $1.29 $2.45
=============================================================================
Diluted Earnings per Share
Income Before Extraordinary Item and
Cumulative Effect of Accounting Change $1.79 $1.27 $1.74
Extraordinary Item - Net of Tax - - $0.69
Cumulative Effect of Accounting Change
- Net of Tax - $0.01 - -
Net Income $0.99 $1.84 $1.29
=============================================================================
Diluted Earnings per Share
Income Before Cumulative Effect of
Accounting Change $0.97 $1.79 $1.27
Cumulative Effect of Accounting Change
- Net of Tax - $0.01 -
Net Income $0.97 $1.80 $1.27
$2.43=============================================================================
Dividends Paid per Share $0.50 $0.40 $0.32
=============================================================================
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
2002 2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales $731,404 $ 731,379 $ 716,955 $ 680,141
Cash Receipts from Electric Wholesale Sales 248,305 760,258 301,281
171,628MEG Cash Receipts from Trading Activity 57,889 49 -
Interest Received 13,820 14,747 14,835
Income Tax Refunds Received 921 59 11,833
Performance Deposits 6,147 (8,629) -
Fuel Costs Paid (201,124) (262,283) (213,999) (183,093)
Purchased Power Costs Paid (135,320) (544,472) (196,137) (93,258)
Wages Paid, Net of Amounts Capitalized (75,479) (71,043) (61,862) (68,711)
Payment of Other Operations and
Maintenance Costs (126,623) (127,382) (96,722)
(96,998)MEG Cash Payments for Trading Activity (63,766) - -
Capital Lease Interest Paid (68,975) (79,745) (90,418)
(82,421)Taxes Paid, Net of Amounts Capitalized (106,550) (105,484) (101,263)
Interest Paid, Net of Amounts Capitalized (62,241) (64,814) (71,439) (74,881)
Taxes Paid, Net of Amounts Capitalized (105,484) (101,263) (97,843)
Interest Received 14,747 14,835 9,659
Income Tax Refunds Received 59 11,833 -
Income Taxes Paid (29,238) (38,951) (3,503)
(23,593)
Transfer of Tax Settlement to Escrow AccountCoal Contract Termination and Amendment
Fees Paid (26,649) - -
(22,403)
Emission Allowance Inventory Purchases - - (13,666)
Other 3,11010,442 11,690 5,473 8,667
- -------------------------------------------------------------------------------
Net Cash Flows - Operating Activities 172,963 215,379 215,034 113,228
- -------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (112,706) (121,622) (105,996) (92,808)
Purchase of Springerville Lease Debt
and Equity (134,989) (13,000) (27,633) (26,768)
Investments in and Loans to Equity Investees (23,592) (18,474) (18,552) (7,174)
Return of Nations Energy's Construction
Deposits 15,574 - -
Proceeds from the Sale of Millennium Energy
Businesses - 16,631 31,350
4,041Return of Nations Energy's Construction
Deposits - 15,574 -
Proceeds from the Sale of Real Estate - 6,580 -
-
Sale of Securities - - 27,516
Other 397 (2,536) 7,281 2,143
- -------------------------------------------------------------------------------
Net Cash Flows - Investing Activities (270,890) (116,847) (113,550) (93,050)
- -------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from IssuanceRepayment of Long-Term Debt - - 1,977
Payments to Retire Long-Term Debt(2,138) (1,871) (50,116) (1,725)
Proceeds from Borrowings under the Revolving
Credit Facility - - 25,000 -
Payments on Borrowings under the Revolving
Credit Facility - - (25,000)
Payment of Debt Issue Costs (5,410) - -
Payments to Retireon Capital Lease Obligations (19,842) (26,015) (39,019) (23,602)
Proceeds from the Exercise of Warrants - - 12,671 -
Common Stock Dividends Paid (16,806) (13,376) (10,349)
-
Other 4,897 7,880 3,045 3,293
- -------------------------------------------------------------------------------
Net Cash Flows - Financing Activities (39,299) (33,382) (83,768) (20,057)
- -------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash
Equivalents (137,226) 65,150 17,716 121
Cash and Cash Equivalents, Beginning of Year 228,154 163,004 145,288 145,167
- -------------------------------------------------------------------------------
Cash and Cash Equivalents, End of Year $ 90,928 $ 228,154 $ 163,004 $ 145,288
===============================================================================
See Note 17 for supplemental cash flow information.
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
2002 2001 2000
- -----------------------------------------------------------------------------
-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service $ 2,498,0462,598,884 $ 2,389,5872,498,046
Utility Plant Underunder Capital Leases 741,446747,556 741,446
Construction Work in Progress 59,926 70,992 94,789
- -----------------------------------------------------------------------------
Total Utility Plant 3,406,366 3,310,484 3,225,822
Less Accumulated Depreciation and Amortization (1,346,101) (1,270,089) (1,186,035)
Less Accumulated Depreciation of Capital
Lease Assets (391,915) (362,724) (333,497)
- -----------------------------------------------------------------------------
Total Utility Plant - Net 1,668,350 1,677,671 1,706,290
- -----------------------------------------------------------------------------
Investments and Other Property
Investments in Lease Debt and Equity 191,867 84,459
Other 123,238 98,288
- -----------------------------------------------------------------------------
Total Investments and Other Property 315,105 182,747 121,811
- -----------------------------------------------------------------------------
Current Assets
Cash and Cash Equivalents 90,928 228,154
163,004Trade Accounts Receivable - Net 76,635 119,646 115,540
Materials and Fuel Inventory 46,657 45,052
44,399Current Regulatory Assets 11,778 11,392
Deferred Income Taxes - Current 15,917 11,165
17,790Interest Receivable - Current 12,178 3,630
Other 30,891 19,47530,912 27,261
- -----------------------------------------------------------------------------
Total Current Assets 434,908 360,208285,005 446,300
- -----------------------------------------------------------------------------
Regulatory and Other Assets
Transition Recovery Asset 307,120 331,674 353,283
Income Taxes Recoverable Through Future Revenues 57,044 64,239 73,459
Other Regulatory Assets 10,504 9,072 7,690
Other Assets 47,606 35,014 48,643
- -----------------------------------------------------------------------------
Total Regulatory and Other Assets 422,274 439,999 483,075
- -----------------------------------------------------------------------------
Total Assets $ 2,735,3252,690,734 $ 2,671,3842,746,717
=============================================================================
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity $ 424,722438,229 $ 372,169424,722
Capital Lease Obligations 801,611 853,793 857,829
Long-Term Debt 1,128,963 802,804 1,132,395
- -----------------------------------------------------------------------------
Total Capitalization 2,368,803 2,081,319 2,362,393
- -----------------------------------------------------------------------------
Current Liabilities
Current Obligations Underunder Capital Leases 42,960 20,158 21,147
Current Maturities of Long-Term Debt 1,840 330,424 1,725
Accounts Payable 48,934 84,011 65,891
Interest Accrued 60,238 53,300 63,852
Taxes Accrued 25,904 26,81133,850 42,572
Accrued Employee Expenses 13,577 14,40513,644 14,240
Other 17,914 16,105 8,547
- -----------------------------------------------------------------------------
Total Current Liabilities 543,479 202,378219,380 560,810
- -----------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 43,507 51,03534,552 37,568
Other 67,999 67,020 55,578
- -----------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 110,527 106,613102,551 104,588
- -----------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
- -----------------------------------------------------------------------------
Total Capitalization and Other Liabilities $ 2,735,3252,690,734 $ 2,671,3842,746,717
=============================================================================
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
2002 2001 2000
- ----------------------------------------------------------------------------
COMMON STOCK EQUITY - Thousands-Thousands of Dollars -Dollars-
Common Stock--No Par Value $ 661,185 $ 660,123
$ 655,5392002 2001 2000
---------- ----------
Shares Authorized 75,000,000 75,000,000
Shares Outstanding 33,578,959 33,502,007 33,218,503
Accumulated Deficit (218,932) (235,401) (283,370)
Accumulated Other Comprehensive Income -(Loss) (4,024) -
- ----------------------------------------------------------------------------
Total Common Stock Equity 438,229 424,722 372,169
- ----------------------------------------------------------------------------
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized,
None Outstanding - -
- ----------------------------------------------------------------------------
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 503,237 492,838 476,409
Springerville Coal Handling Facilities 132,333 156,427 159,944
Springerville Common Facilities 126,277 131,744 141,097
Irvington Unit 4 81,268 90,831 99,241
Other Leases 1,456 2,111 2,285
- ----------------------------------------------------------------------------
Total Capital Lease Obligations 844,571 873,951 878,976
Less Current Maturities (42,960) (20,158) (21,147)
- ----------------------------------------------------------------------------
Total Long-Term Capital Lease Obligations 801,611 853,793 857,829
- ----------------------------------------------------------------------------
LONG-TERM DEBT
Interest
Issue Maturity Rate
- ----------------------------------------------------------------------------
First Mortgage Bonds
Corporate 2009 8.50% 27,365 27,754 27,900
Industrial Development
Revenue Bonds (IDBs) 2006 - 2008 6.10% to 7.50% 56,600 58,325 60,050
First Collateral Trust
Bonds 2008 7.50% 138,300 138,300
Second Mortgage Bonds
(IDBs)*IDBs* 2018 - 2022 Variable** 328,600 328,600
Unsecured IDBs 2020 - 2033 5.85% to 7.13% 579,270 579,270
Other Long-Term Debt 668 979 -
- ----------------------------------------------------------------------------
Total Stated Principal Amount 1,130,803 1,133,228 1,134,120
Less Current Maturities* (1,840) (330,424) (1,725)
- ----------------------------------------------------------------------------
Total Long-Term Debt 1,128,963 802,804 1,132,395
- ----------------------------------------------------------------------------
Total Capitalization $2,368,803 $2,081,319 $2,362,393
============================================================================
* Second Mortgage IDBs are backed by LOCs under TEP's Credit Agreement. TEP's
obligations under the Credit Agreement are collateralized with Second
Mortgage Bonds. TheIn November 2002, TEP entered into two new LOCs expire(Tranche A
and Tranche B) for $341 million to replace the LOCs provided under its then
existing credit agreement that would have expired on December 30, 2002.
If the LOCs are not extended or
replaced withThese new LOCs with a longer term or if the bonds are not otherwise
refinanced, the bonds would be redeemed.expire in 2006. Accordingly, these IDBs were classified as
short-term debt at December 31, 2001 and will be classified as long-term debt once a new LOC facility with a later expiration date is obtained.at
December 31, 2002.
** Weighted average interest rates on variable rate tax-exempt debt (IDBs)
ranged from 1.40%1.23% to 5.02%3.92% during 20012002 and 2000,2001, and the average interest
rate on such debt was 1.41% in 2002 and 2.67% in 20012001. The annual LOC fee
on TEP's previous LOC Facility was 1.25% in 2002 (until it was replaced in
November 2002) and 4.17% in 2000.
UniSource Energy also has stock options outstanding. See Note 13.2001. At December 31, 2002, the annual LOC fee for
Tranche A (including fronting fees) was 4.25% of the Tranche A commitment
and for Tranche B (including fronting fees) was 5.75% of the Tranche B
commitment.
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Accumulated
Common Accumulated Other Total
Shares Common Earnings Comprehensive Stockholders'
Outstanding* Stock (Deficit) Income (Loss) Equity
- -------------------------------------------------------------------------------
-Thousands of Dollars--In Thousands-
Balances at
December 31, 1998 $ 640,640 $(393,994)1999 32,349 $641,723 $(317,475) $ - $ 246,646
1999$324,248
2000 Net Income - 79,107 - 79,10741,891 - 41,891
Dividends Declared - (2,588) - (2,588)
107,567(7,786) - (7,786)
Shares Issued under
Stock Compensation
and
Purchase Plans 1,27775 1,123 - - 1,277
16,439 Net1,123
Shares Purchased by
Deferred Compensation
Trust Less
Distributions (194) - - (194)
- -------------------------------------------------------------------------------
Balances at December 31, 1999 641,723 (317,475) - 324,248
2000 Net Income - 41,891 - 41,891
Dividends Declared - (7,786) - (7,786)
75,466 Shares Issued Under
Stock Compensation and
Purchase Plans 1,123 - - 1,123
5,594 Net Shares Purchased by
Deferred Compensation Trust
Less Distributions(5) (75) - - (75)
799,540
Shares Issued for
Warrants and Stock
Options 800 12,768 - - 12,768
- -------------------------------------------------------------------------------
Balances at
December 31, 2000 33,219 655,539 (283,370) - 372,169
Comprehensive Income
(Loss):
2001 Net Income - - 61,345 - 61,345
Cumulative Effect of
Accounting Change
(net of $9,179,000
income tax benefit) - - - (13,827) (13,827)
Reversal of
Unrealized Loss
on Cash Flow
Hedges included
in Cumulative
Effect of
Accounting Change
(net of $9,179,000
income tax expense) - - - 13,827 13,827
Unrealized Loss on Cash
Flow Hedges (net of
$5,537,000 income tax
benefit) - - - (8,340) (8,340)
Reversal of
Unrealized Loss on
Cash Flow Hedges
(net of $5,537,000
income tax expense) - - - 8,340 8,340
------------
Total Comprehensive -------
Income 61,345
-------------------
Dividends Declared - - (13,376) - (13,376)
112,856
Shares Issued under
Stock Compensation
and
Purchase Plans 113 2,210 - - 2,210
7,129 Net
Shares Purchased by
Deferred Compensation
Trust Less
Distributions (7) (215) - - (215)
177,777
Shares Issued for
Stock Options 177 2,589 - - 2,589
- -------------------------------------------------------------------------------
Balances at
December 31, 2001 33,502 660,123 (235,401) - 424,722
Comprehensive Income:
2002 Net Income - - 33,275 - 33,275
Minimum Pension
Liability (net of
$2,639,000 income
tax benefit) - - - (4,024) (4,024)
Total Comprehensive -------
Income 29,251
-------
Dividends Declared - - (16,806) - (16,806)
Shares Issued under
Stock Compensation
Plans 9 80 - - 80
Shares Distributed
by Deferred
Compensation Trust 3 48 - - 48
Shares Issued for
Stock Options 65 934 - - 934
- -------------------------------------------------------------------------------
Balances at
December 31, 2002 33,579 $661,185 $(218,932) $ 660,123 $(235,401) $ - $ 424,722(4,024) $438,229
===============================================================================
* UniSource Energy has 75 million authorized shares of common stock.
We describe limitations on our ability to pay dividends in Note 9.
See Notes to Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
2002 2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $ 666,049 $ 670,117 $ 664,646
$ 629,900
Electric Wholesale Sales 761,255177,908 733,559 359,814 171,219
Net Unrealized LossGain (Loss) on Forward
Electric Sales and Purchases 533 (1,315) - -
Other Revenues 6,603 6,308 3,908 2,964
- -------------------------------------------------------------------------------
Total Operating Revenues 1,436,365851,093 1,408,669 1,028,368 804,083
- -------------------------------------------------------------------------------
Operating Expenses
Fuel 209,712 258,761 239,939
194,205
Purchased Power 570,28364,504 542,587 207,596 92,144
Coal Contract Termination and
Amendment FeeFees 11,250 - 13,231 -
Capital Lease Expense - - 85,320
Amortization of Springerville
Unit 1 Allowance - - (29,098)
Other Operations and Maintenance 163,616 158,118 162,322 142,915
Depreciation and Amortization 124,054 117,063 113,507 92,583
Amortization of Transition Recovery Asset 24,554 21,609 17,008 2,241
Taxes Other Than Income Taxes 44,228 45,047 49,445 47,789
- -------------------------------------------------------------------------------
Total Operating Expenses 1,170,881641,918 1,143,185 803,048 628,099
- -------------------------------------------------------------------------------
Operating Income 209,175 265,484 225,320 175,984
- -------------------------------------------------------------------------------
Other Income
Interest Income 20,094 11,910 8,550 7,935
Interest Income - Note Receivable from
UniSource Energy 9,329 9,330 9,329
9,937
Other Income 4,338 2,499 820 2,602
- -------------------------------------------------------------------------------
Total Other Income 33,761 23,739 18,699 20,474
- -------------------------------------------------------------------------------
Interest Expense
Long-Term Debt 61,218 66,377 66,83665,620 68,678 75,076
Interest on Capital Leases 90,348 92,658 16,24187,783 90,506 92,815
Interest Imputed on Losses Recorded at
Present Value 1,166 820 198 29,159
Other Interest Expense, 6,113 7,051 10,994Net of Amounts
Capitalized (720) (1,505) (1,805)
- -------------------------------------------------------------------------------
Total Interest Expense 153,849 158,499 166,284 123,230
- -------------------------------------------------------------------------------
Income Before Income Taxes Extraordinary
Item and Cumulative
Effect of Accounting Change 89,087 130,724 77,735
73,228
Income Taxes 35,350 55,910 26,566 22,350
- -------------------------------------------------------------------------------
Income Before Extraordinary Item and Cumulative Effect of
Accounting Change 53,737 74,814 51,169 50,878
Extraordinary Item - Net of Tax - - 22,597
Cumulative Effect of Accounting Change
- Net of Tax - 470 - -
- -------------------------------------------------------------------------------
Net Income $ 53,737 $ 75,284 $ 51,169 $ 73,475
===============================================================================
See Notes to Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
2002 2001 2000 1999
- ------------------------------------------------------------------------------
-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales $ 731,404 $ 731,379 $ 716,955 $ 680,141
Cash Receipts from Electric Wholesale Sales 248,305 760,258 301,281
171,628Interest Received 13,288 11,894 7,764
Interest Received from UniSource Energy - 9,330 9,329
Income Tax Refunds Received 921 - 11,831
Fuel Costs Paid (201,124) (262,283) (213,999) (183,093)
Purchased Power Costs Paid (135,320) (544,472) (196,137) (93,258)
Wages Paid, Net of Amounts Capitalized (60,871) (61,839) (54,469) (61,697)
Payment of Other Operations and
Maintenance Costs (105,844) (98,628) (82,750) (89,020)
Capital Lease Interest Paid (68,911) (79,663) (90,365)
(82,414)Taxes Paid, Net of Amounts Capitalized (101,866) (101,729) (100,400)
Interest Paid, Net of Amounts Capitalized (62,209) (64,830) (71,439) (74,862)
Taxes Paid, Net of Amounts Capitalized (101,729) (100,400) (97,416)
Interest Received 21,223 17,093 26,881
Income Tax Refunds Received - 11,831 -
Income Taxes Paid (29,109) (38,950) (3,503)
(22,156)
Transfer of Tax Settlement to Escrow AccountCoal Contract Termination and Amendment
Fees Paid (26,649) - -
(22,403)
Emission Allowance Inventory Purchases - - (13,666)
Other 7031,502 702 92 1,292
- ------------------------------------------------------------------------------
Net Cash Flows - Operating Activities 203,517 261,169 234,190 139,957
- ------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (103,307) (103,913) (98,063) (90,940)
Purchase of Springerville Lease Debt
and Equity (134,989) (15,167) (25,070)
(26,768)Purchase of North Loop Gas Turbine from UED (14,853) - -
Proceeds from the Sale of Real Estate - 6,580 -
-
InvestmentsInvestment in and Loans to Equity InvesteesMethod Entity - - (2,000)
-
Other 4,571 (3,394) 3,797 2,288
- ------------------------------------------------------------------------------
Net Cash Flows - Investing Activities (248,578) (115,894) (121,336) (115,420)
- ------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from IssuanceRepayments of Long-Term Debt - - 1,977
Payments to Retire Long-Term Debt(2,114) (1,871) (50,116) (1,725)
Proceeds from Borrowings under the Revolving
Credit Facility - - 25,000 -
Payments on Borrowings under the Revolving
Credit Facility - - (25,000)
Payment of Debt Issue Costs (5,410) - -
Dividends Paid to UniSource Energy (35,000) (50,000) (30,000)
Payments to Retireon Capital Lease Obligations (19,544) (25,875) (38,855)
(23,563)
Dividend Paid (50,000) (30,000) (34,000)
Other 3,227 3,439 6,427 2,940
- ------------------------------------------------------------------------------
Net Cash Flows - Financing Activities (58,841) (74,307) (112,544) (54,371)
- ------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and
Cash Equivalents (103,902) 70,968 310 (29,834)
Cash and Cash Equivalents, Beginning of Year 159,680 88,712 88,402 118,236
- ------------------------------------------------------------------------------
Cash and Cash Equivalents, End of Year $ 55,778 $ 159,680 $ 88,712 $ 88,402
==============================================================================
See Note 17 for supplemental cash flow information.
See Notes to Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
2002 2001
2000
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service $ 2,498,0462,598,884 $ 2,389,5872,498,046
Utility Plant Underunder Capital Leases 741,446747,556 741,446
Construction Work in Progress 59,926 70,992
94,789
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Utility Plant 3,406,366 3,310,484 3,225,822
Less Accumulated Depreciation and Amortization (1,346,101) (1,270,089) (1,186,035)
Less Accumulated Depreciation of Capital
Lease Assets (391,915) (362,724)
(333,497)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Utility Plant - Net 1,668,350 1,677,671
1,706,290
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Investments and Other Property
Investments in Lease Debt and Equity 191,867 84,459
Other 21,358 21,416
- -------------------------------------------------------------------------------
Total Investments and Other Property 213,225 105,875
92,334
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Note Receivable from UniSource Energy 70,13279,462 70,132
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and Cash Equivalents 55,778 159,680
88,712Trade Accounts Receivable 124,487 116,580- Net 67,724 113,224
Intercompany Accounts Receivable 14,851 11,263
Materials and Fuel Inventory 44,500 43,682
43,847Current Regulatory Assets 11,778 11,392
Deferred Income Taxes - Current 15,917 4,603
10,662Interest Receivable - Current 12,178 3,630
Other 7,814 6,5858,407 4,184
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 340,266 266,386231,133 351,658
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Regulatory and Other Assets
Transition Recovery Asset 307,120 331,674 353,283
Income Taxes Recoverable Through Future Revenues 57,044 64,239 73,459
Other Regulatory Assets 10,504 9,072 7,690
Other Assets 46,752 35,014
31,361
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Regulatory and Other Assets 421,420 439,999
465,793
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 2,633,9432,613,590 $ 2,600,935
============================================================================2,645,335
===============================================================================
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity $ 322,471337,463 $ 295,660322,471
Capital Lease Obligations 801,508 853,447 857,519
Long-Term Debt 1,128,410 801,924
1,132,395
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization 2,267,381 1,977,842
2,285,574
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current Obligations Underunder Capital Leases 42,872 19,971 21,031
Current Maturities of Long-Term Debt 1,725 330,325 1,725
Accounts Payable 89,193 73,95541,704 79,133
Intercompany Accounts Payable 12,478 10,060
Interest Accrued 60,238 53,300 63,852
Taxes Accrued 23,015 25,48535,772 39,826
Accrued Employee Expenses 13,078 14,15213,370 13,741
Other 7,543 6,531
5,671
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 535,413 205,871215,702 552,887
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 56,906 53,98067,490 50,824
Other 63,017 63,782
55,510
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 120,688 109,490130,507 114,606
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Other Liabilities $ 2,633,9432,613,590 $ 2,600,935
============================================================================2,645,335
===============================================================================
See Notes to Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
2002 2001 2000
- ---------------------------------------------------------------------------
COMMON STOCK EQUITY - Thousands-Thousands of Dollars -Dollars-
Common Stock--No Par Value $ 653,529 $ 653,250
$ 651,7232002 2001 2000
---------- ----------
Shares Authorized 75,000,000 75,000,000
Shares Outstanding* 32,139,555 32,139,554 32,139,434
Warrants Outstanding** - 918,325 918,445
Capital Stock Expense (6,357) (6,357)
Accumulated Deficit (305,685) (324,422) (349,706)
Accumulated Other Comprehensive Income -(Loss) (4,024) -
- ---------------------------------------------------------------------------
Total Common Stock Equity 337,463 322,471 295,660
- ---------------------------------------------------------------------------
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized,
None Outstanding - -
- ---------------------------------------------------------------------------
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 503,237 492,838 476,409
Springerville Coal Handling Facilities 132,333 156,427 159,944
Springerville Common Facilities 126,277 131,744 141,097
Irvington Unit 4 81,268 90,831 99,241
Other Leases 1,265 1,578 1,859
- ---------------------------------------------------------------------------
Total Capital Lease Obligations 844,380 873,418 878,550
Less Current Maturities (42,872) (19,971) (21,031)
- ---------------------------------------------------------------------------
Total Long-Term Capital Lease Obligations 801,508 853,447 857,519
- ---------------------------------------------------------------------------
LONG-TERM DEBT
Interest
Issue Maturity Rate
- ---------------------------------------------------------------------------
First Mortgage Bonds
Corporate 2009 8.50% 27,365 27,754 27,900
Industrial Development
Revenue Bonds (IDBs) 2006 - 2008 6.10% to 7.50% 56,600 58,325 60,050
First Collateral Trust
Bonds 2008 7.50% 138,300 138,300
Second Mortgage Bonds
(IDBs)*** 2018 - 2022 Variable**** 328,600 328,600
Unsecured IDBs 2020 - 2033 5.85% to 7.13% 579,270 579,270
- ---------------------------------------------------------------------------
Total Stated Principal Amount 1,130,135 1,132,249 1,134,120
Less Current Maturities*** (1,725) (330,325) (1,725)
- ---------------------------------------------------------------------------
Total Long-Term Debt 1,128,410 801,924 1,132,395
- ---------------------------------------------------------------------------
Total Capitalization $2,267,381 $1,977,842 $2,285,574
===========================================================================
* UniSource Energy is the holder of all but 120121 shares of TEP's outstanding
common stock.
** There arewere 4.6 million outstanding TEP warrants which entitlethat entitled the holder of five warrants
to purchase one share of TEP common stock for $16.00. See Note 15.They were
exercisable until December 15, 2002, when they expired.
*** Second Mortgage IDBs are backed by LOCs under TEP's Credit Agreement.
TEP's obligations under the Credit Agreement are collateralized with Second
Mortgage Bonds. TheIn November 2002, TEP entered into two new LOCs expire(Tranche A
and Tranche B) for $341 million to replace the LOCs provided under its then
existing credit agreement that would have expired on December 30, 2002.
If the LOCs are not extended or
replaced withThese new LOCs with a longer term or if the bonds are not otherwise
refinanced, the bonds would be redeemed.expire in 2006. Accordingly, these IDBs were classified as
short-term debt at December 31, 2001 and will be classified as long-term debt once a new LOC facility with a later expiration date is obtained.at
December 31, 2002.
**** Weighted average interest rates on variable rate tax-exempt debt (IDBs)
ranged from 1.40%1.23% to 5.02%3.92% during 20012002 and 2000,2001, and the average interest
rate on such debt was 1.41% in 2002 and 2.67% in 20012001. The annual LOC fee
on TEP's previous LOC Facility was 1.25% in 2002 (until it was replaced in
November 2002) and 4.17% in 2000.2001. At December 31, 2002, the annual LOC fee for
Tranche A (including fronting fees) was 4.25% of the Tranche A commitment
and for Tranche B (including fronting fees) was 5.75% of the Tranche B
commitment.
See Notes to Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Accumulated
Capital Accumulated Other Total
Common Stock Earnings Comprehensive Stockholders'
Stock Expense (Deficit) Income (Loss) Equity
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Balances at
December 31, 1998 $646,5681999 $647,366 $(6,357) $(410,350)$(370,875) $ - $229,861
1999 Net Income - - 73,475 - 73,475
Dividend Paid - - (34,000) - (34,000)
Capital Contribution
from UniSource Energy 720 - - - 720
Other 78 - - - 78
- -------------------------------------------------------------------------------
Balances at
December 31, 1999 647,366 (6,357) (370,875) - 270,134$270,134
2000 Net Income - - 51,169 - 51,169
Dividend Paid - - (30,000) - (30,000)
Capital Contribution
from UniSource Energy 4,140 - - - 4,140
Other 217 - - - 217
- -------------------------------------------------------------------------------
Balances at
December 31, 2000 651,723 (6,357) (349,706) - 295,660
Comprehensive Income
(Loss):
2001 Net Income - - 75,284 - 75,284
Cumulative Effect of
Accounting Change
(net of $9,179,000
income tax benefit) - - - (13,827) (13,827)
Reversal of
Unrealized Loss on
Cash Flow Hedges
included in
Cumulative Effect
Ofof Accounting
Change(netChange (net of
$9,179,000 income
tax expense) - - - 13,827 13,827
Unrealized Loss on
Cash Flow Hedges (net
of $5,537,000 income
tax benefit) - - - (8,340) (8,340)
Reversal of
Unrealized Loss on
Cash Flow Hedges
(net of $5,537,000
income tax expense) - - - 8,340 8,340
-----------
Total Comprehensive ---------
Income 75,284
--------------------
Dividend Paid - - (50,000) - (50,000)
Capital Contribution
from UniSource Energy 1,411 - - - 1,411
Other 116 - - - 116
- -------------------------------------------------------------------------------
Balances at
December 31, 2001 $653,250653,250 (6,357) (324,422) - 322,471
Comprehensive Income:
2002 Net Income - - 53,737 - 53,737
Minimum Pension
Liability (net of
$2,639,000 income
tax benefit) - - - (4,024) (4,024)
Total Comprehensive ---------
Income 49,713
---------
Dividend Paid - - (35,000) - (35,000)
Capital Contribution
from UniSource Energy 241 - - - 241
Other 38 - - - 38
- -------------------------------------------------------------------------------
Balances at
December 31, 2002 $653,529 $(6,357) $(324,422)$(305,685) $ - $322,471(4,024) $337,463
===============================================================================
We describe limitations on our ability to pay dividends in Note 9.
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ----------------------------------------------------------------------------
NATURE OF OPERATIONS
UniSource Energy Corporation (UniSource Energy) is an exempt holding
company under the Public Utility Holding Company Act of 1935. UniSource
Energy has no significant operations of its own, but holds the stock of
Tucson Electric Power Company (TEP), Millennium Energy Holdings, Inc.
(Millennium) and UniSource Energy Development Company (UED). TEP, a
regulated public utility incorporated in Arizona since 1963, is UniSource
Energy's largest operating subsidiary and represents substantially all of
UniSource Energy's assets. Millennium holds the energy-related businesses
described in Note 4 and UED's services are described in Note 5.
TEP generates, transmits and distributes electricity. TEP serves retail
customers in a 1,155 square mile area in Southern Arizona. TEP also sells
electricity to other utilities and power marketing entities primarily located
in the Western United States.western U. S. Approximately 60%58% of TEP's work force is subject to a
collective bargaining unit. The collective bargaining agreement in place at
December 31, 2001 terminatesterminated on January 6, 2003. New collective bargaining
agreements were ratified by union members in December 2002. The agreements
took effect on January 7, 2003, and extend through the end of 2005.
References to "we" and "our" are to UniSource Energy and its
subsidiaries, collectively. References to the "utility business" are to TEP.
BASIS OF PRESENTATION
On January 1, 1998, TEP and UniSource Energy exchanged all the
outstanding common stock of TEP on a share-for-share basis for the common
stock of UniSource Energy. Following the share exchange, in January 1998 TEP
transferred the stock of Millennium to UniSource Energy for a $95 million ten-
year promissory note. Approximately $25 million of this note represents a
gain to TEP. TEP has not recorded this gain. Instead, this gain will be
reflected as an increase in TEP's common stock equity when UniSource Energy
pays the principal portion of the note in 2008. In accordance with the
Arizona Corporation Commission (ACC) order authorizing the formation of the
holding company, the note bears interest at 9.78% payable every two years
beginning January 1, 2000. For the interest payment due January 1, 2002,
UniSource Energy paid TEP $9 million in each of 2001 and 2000
and $19 million in 1999 for the interest owed under this note.2000. UniSource
Energy expects to make the next payment, of approximately $18 million, by the
January 1, 2004 due date.
UniSource Energy, TEP and TEPMillennium use the following two methods to report
investments in their subsidiaries or other companies:
- Consolidation: When we ownUniSource Energy, TEP or Millennium owns a majority
of the voting stock of a subsidiary we combineand has control over the subsidiary,
the accounts of the subsidiary are combined with ourthe accounts of the
parent and
eliminate intercompany balances and transactions.transactions are eliminated.
- The Equity Method: We use theThe equity method is used to report corporate joint
ventures, partnerships, and affiliated companies when we holdUniSource Energy,
TEP or Millennium holds a 20% to 50% voting interest or we havehas the ability
to exercise significant influence over the operating and financial
policies of the investee company. Under the equity method, weUniSource
Energy, TEP and Millennium report:
- OurTheir interest in the equity of an entity as an investment on ourtheir
balance sheet; and
- OurTheir percentage share of the net income (loss) from the entity as
Other Income in ourtheir income statements. For investments where
we provideUniSource Energy, TEP or Millennium is committed to providing all of
the financing, wethey recognize 100% of the losses.losses (see Note 4).
- The Cost Method: When UniSource Energy, TEP or Millennium does not own
enough shares to exercise significant influence over an investee company,
they use the cost method to report these investments. Typically the cost
method is used for investments of less than 20% of the voting interest in
an investee company. Under the cost method UniSource Energy, TEP and
Millennium report:
- Their interest in the equity of an entity as an investment on their
balance sheet; and
- Income based on dividend distributions from the investee company as
Other Income in their income statements; and
- Loss when impairment of the value of the investment becomes evident as
Other Income in their income statements.
USE OF ACCOUNTING ESTIMATES
Management makes estimates and assumptions when preparing financial
statements under Generally Accepted Accounting Principlesaccounting principles generally accepted in the United
States of America (GAAP). These estimates and assumptions affect:
- A portion of the reported amounts of assets and liabilities at the dates
of the financial statements;
- Our disclosures regarding contingent assets and liabilities at the dates
of the financial statements; and
- A portion of the reported revenues and expenses during the financial
statement reporting periods.
Because these estimates involve judgments, the actual amounts may differ
from the estimates.
REGULATION
The ACC and the Federal Energy Regulatory Commission (FERC) regulate
portions of TEP's utility accounting practices and electricityelectric rates. The ACC
has authority over certain rates charged to retail customers, the issuance of
securities, and transactions with affiliated parties. The FERC regulates
TEP's rates for wholesale power sales and transmission services. TEP
generally uses the same accounting policies and practices used by unregulated
companies for financial reporting under GAAP. However, sometimes these
principles, such as the Financial Accounting Standards Board's (FASB)
Statement of Financial Accounting Standards No. 71, Accounting for the
Effects of Certain Types of Regulation (FAS 71), require special accounting
treatment for regulated companies to show the effect of regulation. These
effects are described in Note 2.
TEP UTILITY PLANT
We report TEP'sTEP reports its utility plant on ourits balance sheets at its original
cost. Utility plant includes:
- Material and labor costs,
- Contractor costs,
- Construction overhead costs (where applicable), and
- An Allowance for Funds Used During Construction (AFUDC) or capitalized
interest.interest during construction.
AFUDC reflects the cost of financing construction for transmission and
distribution projects with borrowed funds and equity funds. In 2002, 2001
and 2000, TEP imputed the cost of capital on construction expenditures at an
average of 8.40%, 8.46% and 7.64%, respectively, to reflect the cost of using
borrowed and equity funds to finance construction. The component of AFUDC
attributable to borrowed funds is included as a reduction of Other Interest
Expense on the income statement.statement and totaled $1 million in each of 2002, 2001
and 2000. The equity component is included in Other Income. InIncome and totaled $1
million in each of 2002, 2001 2000 and 1999, we
imputed the cost of capital on construction expenditures at an average of
8.46%, 7.64% and 7.04%, respectively, to reflect the cost of using borrowed and
equity funds to finance construction.
On November 1, 1999, after we stopped applying FAS 71 to our generation
operations, we began applying Statement of Financial Accounting Standard No.
34, Capitalization of Interest Cost. This statement replaces the previous
AFUDC calculation for generation-related construction projects and provides
guidance on calculating the costs during construction of debt funds used to
finance these projects.2000.
The capitalized interest during construction on ourTEP's generation-related
construction projects is included as a reduction of Other Interest Expense on
the income statement.statement and totaled $1 million in each of 2002 and 2001 and less
than $0.5 million in 2000. The average capitalized interest during
construction rate applied to generation-related construction expenditures was
4.26%, 4.93% and 5.58% in 2002, 2001 and 2000, respectively.
Depreciation
We compute------------
TEP computes depreciation for owned utility plant on a straight-line
basis at rates based on the economic lives of the assets. See Note 6. These
depreciation rates are approved by the ACC and averagedfor all plant except deregulated
generation assets. The average depreciation rates for TEP's utility plant
were 4.01%, 3.88%, and 3.85% in 2002, 2001 and 3.68% in 2001, 2000, and 1999, respectively. The
economicdepreciable lives for generation plant are based on remaining lives. Changes
made to the depreciable lives of TEP's generation plant are discussed in Note
6. The economicdepreciable lives for transmission plant, distribution plant, general
plant and intangible plant are based on average lives. The rates also
reflect estimated removal costs, net of estimated salvage value. The costs
of planned major maintenance activities are accounted forrecorded as the costs are
actually incurred and are not accrued in advance of the planned maintenance.
Planned major maintenance activities include the scheduled overhauls at ourTEP's
generation plants. Minor replacements and repairs are expensed as incurred.
Retirements of utility plant, together with removal costs less salvage, are
charged to accumulated depreciation. TEP's amortization of capitalized
computer software costs was $6 million in 2002, $6 million in 2001 and $5
million in 2000.
Computer Software Costs
-----------------------
TEP capitalizes all costs incurred to purchase computer software and
amortizes those costs over the estimated economic life of the product.
Capitalized computer software costs would be immediately charged to expense
if TEP determines that the software in no longer useful.
TEP Utility Plant under Capital Leases
--------------------------------------
TEP financed the following generation assets with capital leases:
- Springerville Common Facilities,
- Springerville Unit 1,
- Springerville Coal Handling Facilities, and
- Irvington Unit 4.
The following table shows the amount of lease expense incurred for TEP's
generation-related capital leases. We describe the lease terms in Capital
Lease Obligations in Note 7.
Years Ended December 31,
2002 2001 2000
---------------------------------------------------------------
-Millions of Dollars-
Lease Expense:
Interest Expense on Capital
Leases $ 88 $ 90 $ 93
Depreciation - Included in:
Operating Expenses - Fuel 4 4 4
Operating Expenses -
Depreciation and Amortization 25 25 25
---------------------------------------------------------------
Total Lease Expense $117 $119 $122
===============================================================
MILLENNIUM AND UED PROPERTIES AND EQUIPMENT
Millennium and UED's properties and equipment are included, net of
accumulated depreciation, in UniSource Energy's balance sheets in the
Investments and Other PropertyProperty-Other line item. Properties and equipment are
stated at original cost and are depreciated using the straight-line method
over the estimated useful lives of the assets. Maintenance, repairs and
minor renewals are charged to expense as incurred, while major renewals and
betterments are capitalized. Millennium capitalizes all costs incurred to
purchase computer software and amortizes those costs over the estimated
economic life of the product. Millennium's unamortized computer software
costs were $2 million as of December 31, 2002 and December 31, 2001.
Millennium's amortization of capitalized computer software costs was less
than $0.5 million in each of 2002, 2001 and 2000. Capitalized computer
software costs would be immediately charged to expense if Millennium
determines that the software is no longer useful.
Interest is capitalized in connection with the construction of major
equipment at Global Solar Energy, Inc. (Global Solar). The capitalized
interest is recorded as part of the asset to which it relates and is
depreciated over the asset's estimated useful life.
UED capitalizes project development costs because UED believes it is
probable that the project will be completed and we expectUED expects to recover the
costs of the project. These costs include dedicated employee salaries,
professional services and other third party costs. Capitalized project costs
would be immediately charged to expense if we determineUED determines that the project is
impaired.
DEBT
TEP UTILITY PLANT UNDER CAPITAL LEASES
TEP financed the following generation assets with leases:
- Springerville Common Facilities,
- Springerville Unit 1,
- Springerville Coal Handling Facilities, and
- Irvington Unit 4.
Under GAAP, these leases qualify as capital leases. However, for ACC rate-
making purposes, these leases have been treated as operating leases with
recovery as if rent payments were made in equal amounts annually during the
lease term. We recorded capital lease expense (interest and depreciation) on a
basis which reflected the rate-making treatment for periods prior to November
1, 1999, the date our generation operations became deregulated. We deferred
the differences between GAAP capital lease accounting used by unregulated
companies and the ACC rate-making method used by us prior to November 1, 1999.
See Income Statement Impact of Applying FAS 71 in Note 2. We describe the
lease terms in Capital Lease Obligations in Note 7.
The following table shows the amount of lease expense incurred for TEP's
generation-related capital leases:
Years Ended December 31,
2001 2000 1999
-----------------------------------------------------------------------
-Millions of Dollars-
Lease Expense:
Interest $ 90 $ 93 $ 94
Depreciation 29 29 22
-----------------------------------------------------------------------
Total Lease Expense $119 $122 $116
=======================================================================
Lease Expense Included In:
Operating Expenses - Fuel $ 4 $ 4 $ 10
Operating Expenses - Capital Lease
Expense - - 85
Operating Expenses - Depreciation and
Amortization 25 25 5
Interest Expense on Capital Leases 90 93 16
-----------------------------------------------------------------------
Total Lease Expense $119 $122 $116
========================================================================
LONG-TERM DEBT
We deferdefers all costs related to the issuance of long-term debt. These costs
include underwriters' commissions, discounts or premiums, and other costs
such as legal, accounting and regulatory fees and printing costs. We
amortizeTEP
amortizes these costs over the life of the debt.
Prior to November 1, 1999, gains and losses on debt that we retired
before maturity were amortized overusing the remaining original life ofstraight-line
method, which approximates the debt toeffective interest expense. Effective November 1, 1999, we recognizemethod.
TEP recognizes gains and losses on reacquired debt associated with the
generation portion of TEP's operations as incurred. We reclassified any remaining generation-related unamortized
gainsTEP defers and losses on reacquired debt at November 1, 1999, which had been
included in Other Regulatory Assets in our balance sheets, to the Transition
Recovery Asset. See Note 2. We continue to defer and amortizeamortizes
the gains and losses on reacquired debt associated with TEP's regulated
operations to interest income or interest expense over the remaining life of
the original debt.
ELECTRIC UTILITY OPERATING REVENUES
We recordTEP records electric utility operating revenues when we deliverTEP delivers
electricity to customers. Operating revenues include unbilled revenues which
are earned (service has been provided) but not billed by the end of an
accounting period.
We recordTEP records an expense and reducereduces accounts receivable by an Allowance
for Doubtful Accounts for revenue amounts that we estimateTEP estimates will become
uncollectible. The Allowance for Doubtful Accounts was $9 million and $10
million at
December 31, 20012002 and 2000, respectively.2001. See Note 11 for further discussion of TEP's
wholesale accounts receivable and allowances.
REVENUE FROM LONG-TERM RESEARCH AND DEVELOPMENT CONTRACTS
UniSource Energy's income statements have included Global Solar's long-
term contract revenue in Other Operating Revenues since Global Solar was
consolidated on June 1, 2000. Global Solar recognized long-term contract
revenue of $2$1.1 million in 2002, $1.7 million in 2001 $4and $3.6 million in
2000 and $4 million in 1999.2000. Global Solar recognized total annual research and development expense
of $7$7.2 million in 2002, $8.6 million in 2001, and 2000 and $5$7.7 million in 1999.2000.
These expenses include both costs associated with revenue producing contracts
and internal development costs. Global Solar derives much of its revenue
from funding received under research and development contracts with various
U.S. governmental agencies. Revenues on these contracts are recognized as
follows:
- Cost Reimbursement Contracts - Revenue is recognized as costs are
incurred;
- Cost Plus Fixed Fee Contracts - Revenues are recognized using the
percentage of completion method of accounting by relating contract costs
incurred to date to total contract costs; and
- Fixed Fee Contracts - Revenues are recognized when applicable milestones
are met.
Contract costs include direct material, direct labor and overhead costs.
FUEL COSTS
Fuel inventory, primarily coal, is recorded at weighted average cost.
TEP uses full absorption costing. Under full absorption costing, all
handling and procurement costs
incurred in the production process are included in the cost of the inventory.
Examples of these costs are direct material, direct labor and overhead costs.
TEP has long-term contracts for the purchase and transportation of coal with
expiration dates from 2004 through 2017. The contracts require TEP to pay a
take-or-pay fee if certain minimum quantities of coal are not purchased or
transported. TEP expenses such fees as they are incurred. See Fuel Purchase
and Transportation Commitments in Note 10, below. Fuel costs include coal
mine reclamation expenses as they are charged to TEP on an ongoing basis.
INCOME TAXES
We are required by GAAP to report some of our assets and liabilities
differently for our financial statements than we do for income tax purposes.
The tax effects of differences in these items are reported as deferred income
tax assets or liabilities in our balance sheets. We measure these tax assets
and liabilities using income tax rates that are currently in effect.
Investment Tax Credits (ITC) are accounted for as a reduction of income tax
expense in the year in which the credit arises.
We allocate income taxes to the subsidiaries based on their taxable
income and deductions used in the consolidated tax return.
EMISSION ALLOWANCES
Emission Allowances arewere issued to qualifying utilities by the
Environmental Protection Agency (EPA) based on past operational history, and
each allowance permits emission of one ton of sulfur dioxide (SO2).(SO(2)) in its
vintage year or a subsequent year. These allowances canhave no book value for
accounting purposes but may be bought or sold. Prior to November 1, 1999, based on
expected future regulatory treatment,sold if TEP recorded Emission Allowance
purchases in a noncurrent inventory account included in Investments and Other
Property on the balance sheets. Emission Allowance inventory was recorded at
weighted average cost. Gains on sales of Emission Allowances were deferred as
an Emission Allowance Gain Regulatory Liability in the balance sheets. At
November 1, 1999, the Emission Allowance inventory account and the Emission
Allowance Gain Regulatory Liability were written off and the result was
included in Extraordinary Income in the income statements. See Note 2.
Subsequent to November 1, 1999, TEP's Emission Allowances have a zero book
value. In 2001 and 2000, we utilized a portion of TEP's Emission Allowances
to comply with environmental regulations.does not need them for operations.
TEP also may purchase additional allowances if needed. See Note 10. In
2002, TEP sold 4,000 allowances that were in excess of those required for
compliance to Millennium Environmental Group, Inc. (MEG) at their fair market
value of $0.5 million. This intercompany sale was eliminated in
consolidation. MEG subsequently sold these allowances to a third party.
STOCK-BASED COMPENSATION
At December 31, 2002, UniSource Energy has two stock-based compensation
plans, which are described in Note 13. We account for those plans under the
recognition and measurement principles of APB Opinion No. 25, Accounting for
Stock Issued to Employees (APB 25), and related interpretations. No stock-
based employee compensation cost is reflected in net income for stock
options, as all options granted under those plans had an exercise price equal
to the market value of the underlying common stock on the date of grant. The
following table illustrates the effect on UniSource Energy's net income and
earnings per share and TEP's net income if we had applied the fair value
recognition provisions of Statement of Financial Accounting Standards No.
123, Accounting for Stock-Based Compensation (FAS 123), to stock-based
employee compensation:
UniSource Energy:
- -----------------
Years Ended December 31,
2002 2001 2000
-----------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
Net Income - As Reported $ 33,275 $ 61,345 $ 41,891
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards, net of related tax
effects (1,271) (1,021) (794)
-----------------------------------------------------------------
Pro Forma Net Income $ 32,004 $ 60,324 $ 41,097
=================================================================
Earnings per Share:
Basic - As Reported $ 0.99 $ 1.84 $ 1.29
Basic - Pro Forma $ 0.95 $ 1.81 $ 1.27
Diluted - As Reported $ 0.97 $ 1.80 $ 1.27
Diluted - Pro Forma $ 0.93 $ 1.77 $ 1.25
-----------------------------------------------------------------
TEP:
- ----
Years Ended December 31,
2002 2001 2000
-----------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
Net Income - As Reported $ 53,737 $ 75,284 $ 51,169
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards, net of related tax
effects (1,271) (1,021) (794)
-----------------------------------------------------------------
Pro Forma Net Income $ 52,466 $ 74,263 $ 50,375
=================================================================
NEW ACCOUNTING STANDARDS
During 2001, the Financial Accounting Standards Board (FASB)The FASB recently issued the following Statements of Financial
Accounting Standards (FAS):
- FAS 141, Business Combinations, which addresses the accounting and reporting for business combinations. FAS 141 requires that all business
combinations initiated after June 30, 2001 be accounted for using one method,
the purchase method. The adoption of FAS 141 did not have a significant
impact on our financial statements.
- FAS 142, Goodwill and Other Intangible Assets, which addresses how
intangible assets that are acquired individually or with a group of other
assets (but not those acquired in a business combination) should be accounted
for in financial statements upon their acquisition. FAS 142 also addresses
how goodwill and other intangible assets should be accounted for after they
have been initially recognized in the financial statements. We are required
to comply with FAS 142 beginning January 1, 2002. The adoption of FAS 142 did
not have a significant impact on our financial statements.FASB Interpretations (FIN):
- FAS 143, Accounting for Asset Retirement Obligations, whichissued by the FASB
in June 2001, requires entities to record the fair value of a liability
for a legal obligation to retire an asset retirement
obligation in the period in which itthe
liability is incurred. A legal obligation is a liability that a party is
required to settle as a result of an existing or enacted law, statue,
ordinance or contract. When the liability is initially recorded, the
entity should capitalize a cost by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accretedadjusted to its
present value by recognizing accretion expense as an operating expense in
the income statement each period, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount
or incurs a gain or loss if the actual costs differ from the recorded
amount.
Prior to adopting FAS 143, costs for final removal of all owned
generation facilities were accrued as an additional component of
depreciation expense. Under FAS 143, only the costs to remove an asset
with legally binding retirement obligations will be accrued over time
through accretion of the asset retirement obligation and depreciation of
the capitalized asset retirement cost.
TEP will adopt FAS 143 on January 1, 2003, as required. TEP has
identified legal obligations to retire generation plant assets specified
in land leases for its jointly-owned Navajo and Four Corners generating
stations. The land on which the Navajo and Four Corners generating
stations reside is leased from the Navajo Nation. The provisions of the
leases require the lessees to remove the facilities upon settlement.request of the
Navajo Nation at the expiration of the leases. TEP also has certain
environmental obligations at the San Juan generating station. TEP has
estimated that its share of the cost to remove the Navajo and Four
Corners facilities and settle the San Juan environmental obligations is
approximately $38 million at the date of retirement. No other legal
obligations to retire generation plant assets were identified.
Millennium and UED have no asset retirement obligations.
TEP has various Transmission and Distribution lines that operate under
various land leases and rights of way that contain end dates and
restorative clauses. TEP operates its Transmission and Distribution
lines as if they will be operated in perpetuity and would continue to
be used or sold without land remediation. As a result, TEP will not
recognize the costs of final removal of the Transmission and
Distribution lines in the financial statements.
Upon adoption of FAS 143 on January 1, 2003, TEP expects to record an
asset retirement obligation of $38 million at its net present value of
$1.1 million, increase depreciable assets by $0.1 million for asset
retirement costs, reverse $112.8 million of costs previously accrued for
final removal from accumulated depreciation, reverse previously recorded
deferred tax assets by $44.2 million and recognize the cumulative effect
of accounting change as a gain of $111.7 million ($67.5 million net of
tax). TEP expects that adopting FAS 143 will result in a reduction to
depreciation expense charged throughout the year as well. For 2003, this
amount is approximately $6 million.
Amounts recorded under FAS 143 are subject to various assumptions and
determinations, such as determining whether a legal obligation exists to
remove assets, estimating the fair value of the costs of removal,
estimating when final removal will occur, and the credit-adjusted
risk-free interest rates to be utilized on discounting future liabilities.
Changes that may arise over time with regard to these assumptions and
determinations will change amounts recorded in the future as expense for
asset retirement obligations.
If TEP in fact retires any asset at the end of its useful life, without
a legal obligation to do so, it will record retirement costs at that time
as incurred or accrued. TEP does not believe that the adoption of FAS
143 will result in any change in retail rates since all matters relating
to the rate-making treatment of TEP's generating assets have been
determined pursuant to the Settlement Agreement.
- FAS 146, Accounting for Costs Associated with Exit or Disposal
Activities, issued in July 2002, requires entities to record a liability
for costs related to exit or disposal activities when the costs are
incurred. Previous accounting guidance required the liability to be
recorded at the date of commitment to an exit or disposal plan. We are
required to comply with FAS 143146 beginning January 1, 2003, which will
affect any restructuring activities after that date. Although unknown at
this time, the timing of expense recognition in our financial statements
for future restructuring activities could differ significantly.
- FAS 148, Accounting for Stock-Based Compensation - Transition and
Disclosure - an amendment of FAS 123, issued in December 2002, provides
alternative methods of transition for a voluntary change to the fair value
based method of accounting for stock-based employee compensation. In
addition, FAS 148 requires prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
compensation and the effect of the method used on reported results.
Although we are required to comply with interim disclosure requirements of
FAS 148 beginning January 1, 2003, we have elected to continue to apply the
recognition and measurement provisions of APB 25. Therefore, we do not
expect the adoption of FAS 148 to have a significant effect on our
financial statements. The annual disclosure requirements of FAS 148 are
included in Stock-Based Compensation in Note 1, above.
- FIN 45, Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others, issued November
2002, requires disclosures to be made by a guarantor in its interim
and annual financial statements about its obligations under certain
guarantees that it has issued. FIN 45 also clarifies that a guarantor is
required to recognize, at the inception of a guarantee, a liability for the
fair value of the obligation undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions of FIN 45 are
applicable on a prospective basis to guarantees issued or modified
beginning January 1, 2003. The disclosure requirements of FIN 45 are
immediately effective. See Guarantees and Indemnities in Note 10, below.
- FIN 46, Consolidation of Variable Interest Entities, issued January
2003, expands upon existing guidance that addresses when a company should
include in its financial statements the assets and liabilities of another
entity. The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means
other than through voting rights ("variable interest entities") and to
determine when and which business enterprise should consolidate the
variable interest entity (the "primary beneficiary"). FIN 46 requires
that both the primary beneficiary and all other enterprises with a
significant variable interest make additional disclosures. The
transitional disclosure requirements of FIN 46 are effective immediately.
The effective date of the consolidation requirements of FIN 46 depends on
the date the variable interest entity was created. FIN 46 is effective
for all variable interest entities created after January 31, 2003. For
variable interest entities created before February 1, 2003, the provisions
of FIN 46 are to be applied to a variable interest entity for interim
reporting periods beginning after June 30, 2003. We are currently in the
process of evaluating the impact of FAS 143FIN 46 on our financial statements.
- FAS 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, which provides guidance on the financial accountingUniSource Energy and reporting for
the impairment of long-lived assets and for long-lived assets to be disposed
of. FAS 144 supersedes the current authoritative literature for the
impairment of long-lived assets and for the disposal of a segment of a
business. We are required to comply with FAS 144 beginning January 1, 2002.
The adoption of FAS 144 did not have a significant impact on ourTEP's
financial statements.
RECLASSIFICATIONS
We consolidated Income Taxes into a single line item, which is presented
below Income Before Income Taxes, Extraordinary ItemUniSource Energy and Cumulative Effect of
Accounting Change. Income Taxes were previously included in Operating Expenses
and Other Income (Deductions). We have reclassified prior year income
statements to conform to this presentation. WeTEP have made otherminor reclassifications to the prior
year financial statements for comparative purposes. See Note 17. These
reclassifications had no effect on net income.
NOTE 2. REGULATORY MATTERS
- --------------------------
TEP generally uses the same accounting policies and practices used by
unregulated companies for financial reporting under GAAP. However, sometimes
these principles, such as FAS 71, require special accounting treatment for
regulated companies to show the effect of regulation. For example, in
setting TEP's retail rates, the ACC may not allow TEP to currently charge its
customers to recover certain expenses, but instead requires that these
expenses be charged to customers in the future. In this situation, FAS 71
requires that TEP defer these items and show them as regulatory assets on the
balance sheet until TEP is allowed to charge its customers. TEP then
amortizes these items as expense to the income statement as those charges are
recovered from customers. Similarly, certain revenue items may be deferred
as regulatory liabilities, which are also eventually amortized to the income
statement as rates to customers are reduced.
The conditions a regulated company must satisfy to apply the accounting
policies and practices of FAS 71 include:
- an independent regulator sets rates;
- the regulator sets the rates to recover specific costs of delivering
service; and
- the service territory lacks competitive pressures to reduce rates below
the rates set by the regulator.
TEP applied FAS 71 to the generation, transmission and distribution
portions of its business prior to the November 1999 ACC approvalApproval of the Settlement Agreement (see below). Included in the regulatory assets and
liabilities at December 31, 1998 was the Springerville Unit 1 Allowance for
$171 million. This allowance represented the portion of Springerville Unit 1
non-fuel expenses that the ACC did not allowcaused TEP to recover through retail
rates. The allowance, a contra-asset account, increased by interest expense
which was shown as Interest Imputed on Losses Recorded at Present Valuediscontinue
regulatory accounting under FAS 71 for its generation operations in the
Interest Expense section in the income statementsNovember
1999. TEP continues to report its transmission and decreased by the
Amortization of Springerville Unit 1 Allowance, which was a contra-expense
included in Operating Expenses.
At November 1, 1999, the unamortized balance of the Springerville Unit 1
Allowance reduced the Springerville Unit 1 capital lease asset amount. This
offset reduced the amount of post-FAS 71 Springerville Unit 1 lease
depreciation expense that will be recognized in the income statements and
eliminated any further interest and amortization expense related to the
Springerville Unit 1 Allowance.distribution operations
under FAS 71.
NOVEMBER 1999 ACC APPROVAL OF SETTLEMENT AGREEMENT
The Settlement Agreement
------------------------
In November 1999, the ACC approved a Settlement Agreement between TEP
and certain customer groups relating to recovery of TEP's transition costs
and standard retail rates. The major provisions of the Settlement Agreement,
as approved, were:
- Consumer choice: Consumer choice for energy supply began in January 2000
and by January 1, 2001 consumer choice was available to all customers.
- Rate freeze: In accordance with the Rate Settlement approved by the ACC
in 1998, TEP decreased rates to retail customers by 1.1% on July 1, 1998,
1% on July 1, 1999 and 1% on July 1, 2000. These reductions applied to all
retail customers except for certain customers that have negotiated non-
standard rates. The Settlement Agreement provides that, after these
reductions, TEP's retail rates will be frozen until December 31, 2008,
except under certain circumstances. TEP expects to recover the costs of
transmission and distribution under regulated unbundled rates both during
and after the rate freeze.
- Recovery of transition costs: TEP's frozen rates include Fixed and Floating
Competition Transition Charge (CTC) components designated for the recovery
of transition costs, including generation-related regulatory assets and a
portion of TEP's generation plant assets. Retail rates will decrease by
the Fixed CTC amount after TEP has recovered $450 million or on December
31, 2008, whichever occurs first. The Floating CTC equals the amount of the
frozen retail rate less the price of retail electric service. The price of
retail electric service includes TEP's transmission and distribution charge
and a market energy component based on a market index for electric energy.
Because TEP's total retail rate will be frozen, the Floating CTC is
expected to allow TEP to recoup the balance of transition recovery assets
not otherwise recovered through the Fixed CTC. The Floating CTC will end
no later than December 31, 2008.
- General rate case: TEP will beis required to file by June 1, 2004 a general
rate case, including an updated cost-of-service study. Any rate change
resulting from this rate case would be effective no sooner than June 1,
2005 and would not result in a net rate increase.
The Settlement Agreement requires TEP to transfer its generation and
other competitive assets to a wholly-owned subsidiary by December 31, 2002.
Also under the Settlement Agreement, TEP, as a utility distribution company
(UDC), would acquire energy in the wholesale market for its retail customer
energy requirements. The Settlement Agreement also requires that by December
31, 2002 the UDC must acquire at least 50% of its requirements through a
competitive bidding process, while the remainder may be purchased under
contracts with TEP's generation subsidiary or other energy suppliers. The
amounts the UDC acquires through competitive bids may be purchased under
bilateral contracts or spot market purchases with third parties, or
potentially with TEP's generation subsidiary. Under the ACC's electric
competition rules, TEP will be required to provide energy to any distribution
customer who does not choose another energy service provider. TEP's
generation subsidiary will sell energy into the wholesale market. On January
28, 2002, we filed with the ACC a request for an extension to meet the
requirements of the Settlement Agreement until the latter of December 31, 2003
or six months after the ACC has issued a final order in the current docket
pertaining to electric restructuring issues.
Extraordinary Item
Effective November 1, 1999, we stopped applying FAS 71 to our generation
operations and we recognized $23 million in extraordinary income, net of tax,
primarily as a result of recognition of deferred investment tax credits. In
accordance with previous actions of the ACC, TEP had deferred recognition of
the benefit of approximately $31 million in investment tax credits. These
benefits were recognized as part of the discontinuation of FAS 71 as we no
longer had a regulatory deferral requirement. This gain was partially offset
by approximately $14 million in generation-related costs for which TEP did not
receive regulatory recovery as part of its Transition Recovery Asset. These
costs included approximately $11 million of generation-related property taxes
and approximately $3 million of net deferred losses related to the sale of
Emission Allowances. We recorded a net tax benefit of $6 million related to
the write-off of these costs.
Income Statement Changes Resulting from Deregulation of Generation
Operations
As a result of the deregulation of our generation operations, many costs
in the UniSource Energy and TEP income statements are reflected in different
line items in 2001 and 2000 than they were in 1999. The primary differences
are:
- In 2001 and 2000, amortization of our capital lease assets and interest
related to Capital Leases are reflected in Depreciation and Amortization and
Interest on Capital Leases, respectively. Through October 1999, these
expenses were included as Capital Lease Expense.
- Amortization of Springerville Unit 1 Allowance and the related Interest
Imputed on Losses Recorded at Present Value are no longer presented in 2001
and 2000. In November 1999, the unamortized balance of the Springerville Unit
1 Allowance reduced the Springerville Unit 1 capital lease amount.
- Amortization of Transition Recovery Asset
appears as an expense
beginning in November 1999.
- Amortization of Investment Tax Credit (ITC) no longer contributes to
Income Tax Expense in 2001 and 2000. All ITC was recognized in November 1999.
Transition Recovery Asset-------------------------
The Transition Recovery Asset consists of generation-related regulatory
assets and a portion of TEP's generation plant asset costs. The Totaltotal
Transition Costs Being Recovered through the Fixed CTC, which includes the
Transition Recovery Asset as well as generation-related plant in service and
excess capacity deferral costs which are not included in the Transition
Recovery Asset (see table below), were amortized as follows:
Years Ended December 31,
2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------------------------
-Millions of Dollars-
Amortization of Transition Costs Being
Recovered Through the Fixed CTC
Transition Costs Being Recovered Through
Fixed CTC, beginning of year $ 419 $ 448$386 $419 $448
Amortization of Transition Recovery Asset
recorded on the income statement (25) (21) (17)
Generation-Related Plant Asset Amortization (3) (3) (3)
Excess Capacity Deferral Amortization
(offAmortization(off
balance sheet) (9) (9) - -------------------------------------------------------------------------------
Remaining(9)
-----------------------------------------------------------------------
Transition Recovery Asset to beCosts Being Recovered Through
the Fixed CTC, end of year $ 386 $ 419
===============================================================================$349 $386 $419
=======================================================================
The portion of the Transition Recovery Asset that is recorded on the
balance sheet was amortized as follows:
Years Ended December 31,
2002 2001 2000
-----------------------------------------------------------------------
-Millions of Dollars-
Amortization of Transition Recovery Asset
Recorded on the Balance Sheet
Transition Recovery Asset recorded on the
balance sheet, beginning of year $ 353 $ 370$332 $353 $370
Amortization of Transition Recovery Asset
recorded on the income statement (25) (21) (17)
- ------------------------------------------------------------------------------------------------------------------------------------------------------
Remaining Transition Recovery Asset on
the balance sheet, end of year $ 332 $ 353
===============================================================================$307 $332 $353
=======================================================================
The Generation-Related Plant Assets areremaining Transition Recovery Costs Being Recovered Through the
Fixed CTC differs from the Transitions Recovery Asset recorded on the balance
sheet as follows:
December 31,
2002 2001
---------------------------------------------------------------
-Millions of Dollars-
Remaining Transition Recovery Costs to
be Recovered Through the Fixed CTC,
end of year $349 $386
Unamortized balance of generation-related
costs included in Plant in Service on
the balance sheet. The unamortized balance of such generation-related costs
totaled $36 million at December 31, 2001. Thesheet (33) (36)
Excess Capacity Deferrals are
not reflected on our balance sheet and relaterelating to
operating and capital costs associated
with Springerville Unit 2, capacity which were previously expensed
when incurred. Prior to discontinuation of application of FAS 71, these costs
were amortized as
an off-balance sheet regulatory asset. The unamortizedasset (9) (18)
---------------------------------------------------------------
Remaining Transition Recovery Asset on
the balance sheet, end of the off-balance sheet excess capacity deferral totaled $18 million
at December 31, 2001.year $307 $332
===============================================================
The remaining Transition Recovery Asset balance will be amortized as
costs are recovered through rates until TEP has recovered $450 million of
transition costs or until December 31, 2008, whichever comesoccurs first.
OTHER REGULATORY ASSETS AT DECEMBER 31, 2002 AND 2001
AND 2000
The balances ofIn addition to the Transition Recovery Asset related to generation
assets, the following regulatory assets atare being recovered through TEP's
transmission and distribution business:
December 31,
2002 2001
-------------------------------------------------------------
-Millions of Dollars-
Other Regulatory Assets Related to
Transmission and 2000 are noted
in the table below.Distribution
Income Taxes Recoverable Through
Future Revenues $ 57 $ 64
Current Regulatory Assets 12 11
Other Regulatory Assets 11 9
-------------------------------------------------------------
Total Regulatory Assets $ 80 $ 84
=============================================================
There are no remaining regulatory liabilities recorded on the balance
sheets at December 31, 20012002 and 2000. All of the remaining
regulatory assets relate to TEP's distribution and transmission business.
December 31,
2001 2000
---------------------------------------------------------------------
-Millions of Dollars-
Regulatory Assets
Transition Recovery Asset $ 332 $ 353
Income Taxes Recoverable Through
Future Revenues 64 73
Other Regulatory Assets 9 8
---------------------------------------------------------------------
Total Regulatory Assets $ 405 $ 434
=====================================================================2001.
INCOME STATEMENT IMPACT OF APPLYING FAS 71
The amortization of the regulatory assets discussed in the previous
sections of this note have had the following effect on ourUniSource Energy and
TEP's income statements:
Years Ended December 31,
2002 2001 2000
1999
-------------------------------------------------------------------------------------------------------------------------------------------
-Millions of Dollars-
Operating Expenses
Fuel $ - $ - $ 4
Amortization of Springerville Unit 1 Allowance - - (29)
Depreciation and Amortization - - 5
Amortization of Transition
Recovery Asset $ 25 $ 21 $ 17 2
Interest Expense
Long-Term Debt 1 1 2 3
Interest Imputed on Losses Recorded at Present Value - - 29
Income Taxes 7 5 5
7
-------------------------------------------------------------------------------------------------------------------------------------------
If TEP had not applied FAS 71 in these years, the above amounts would
have been reflected in the income statements in prior periods. The
above
table does not include capital lease expense. Capital lease expense would
have been recognized at different annual amounts if TEP had not applied FAS 71
although the total would be the same over the life of the leases. Lease
expense included on our income statements amounted to $116 million in 1999.
If we had not applied FAS 71, the Springerville Unit 1 Allowance would have
been offset against the Springerville Unit 1 capital lease asset and the
depreciation would have been calculated on a straight-line method. Our lease
expense would have been $124 million in 1999 if we had not applied FAS 71.
The reclassification of ourTEP's generation-related regulatory assets to the
Transition Recovery Asset shortened the amortization period for these assets
to nine years.
FUTURE IMPLICATIONS OF CEASING TO APPLY FAS 71 TO OURTEP'S REGULATED BUSINESS
We continueTEP continues to apply FAS 71 forto the distribution and transmission
portions of TEP'sits business, ourits regulated operations. We periodically assessoperations, and assesses whether weit
can continue to apply FAS 71.71 to these operations. If weTEP stopped applying
FAS 71 to TEP'sits remaining regulated operations, weit would write off the related
balances of TEP'sits regulatory assets as a charge in ouran expense on its income statement.
Based on the balances of TEP's regulatory assets at December 31, 2001,2002, if weTEP
had stopped applying FAS 71 to TEP'sits remaining regulated operations, weit would
have recorded an extraordinary loss, after-tax, of approximately $245$233
million. While regulatory orders and market conditions may affect ourTEP's cash
flows, ourits cash flows would not be affected if weit stopped applying FAS 71
unless a regulatory order limited ourits ability to recover the cost of that
regulatory asset.
RECENT DEVELOPMENTS IN THE ARIZONA REGULATORY ENVIRONMENT
In February 2002, the ACC consolidated several pending matters related
to retail electric competition in order to make a comprehensive reexamination
of the Rules. InOn September 10, 2002, the ACC issued an order that eliminated
the requirement that TEP transfer its generating assets to a letter dated January 14, 2002,subsidiary. At
the same time, the ACC Chairman William A. Mundell
suggestedordered the following possible outcomesparties, including TEP, to develop a
competitive bidding process and reduced the proceedings:
- Implementationamount of power to be acquired in
the competitive bidding process to only that portion not supplied by TEP's
existing resources.
On February 27, 2003, the ACC issued an order that defines the process,
for the period 2003 through 2006, by which TEP will be required to obtain its
capacity and energy requirements beyond what is supplied by TEP's existing
resources, which represents approximately 0.5% of its retail load in the
first year and increases over the period. This order further requires TEP to
bid out short-term energy purchases that it estimates it will make in the
2003 to 2006 period; however, it does not require TEP to purchase any power
that it deems to be uneconomical, unreasonable or unreliable. TEP expects to
issue requests for proposals in March 2003 and complete the selection process
by June 1, 2003.
As part of its reexamination of the Rules, accordingthe ACC had planned to
address the existing schedule,
- Delayedrequirement for Arizona electric utilities to participate in the
Arizona Independent Scheduling Administrator (AISA) organization. The Rules
originally required the formation and implementation of the Rules to provide an opportunity to
consider the extent to which Rule modification and variance is in the public
interest, including changing the direction to retail electric competition, or
- Step back from electric restructuring until the Commission is convinced
that there exists a viable competitive wholesale electric market to support
retail electric competition in Arizona.
To begin the proceedings,AISA; however,
the ACC sentopened a list of questions relateddocket in July 2001 to retail competition to Arizona electric utilities, requesting responses by
February 25, 2002. The Chairman further stated that an Open Meeting, with
opportunity for public comment, mayrevisit this obligation. This issue
is pending and will be set. We are uncertain whataddressed separately from the outcome
of this proceeding will be.issues identified above.
NOTE 3. ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND
HEDGING ACTIVITIES
- ---------------------------------------------------------------------
In 1998,---------------------------------------------------------------------------
On January 1, 2001, TEP recorded a $0.5 million after-tax gain in its
income statement for the FASB issuedcumulative effect of adopting Statement of Financial
Accounting Standards No. 133, (FAS 133), Accounting for Derivative Instruments and
Hedging Activities.
A derivative financial instrument or other contract derives its value from
another investment or designated benchmark.
There are two types of gains and losses related to contracts:
- An unrealized gain or loss is the difference between the market price
of the commodity at any time before the contract is settled and the specified
contract price. The market prices used to determine fair value forActivities (FAS 133). TEP enters into forward contracts are estimated based on various factors including broker quotes,
exchange prices, over the counter prices and time value.
- A realized gain or loss is the difference between the specified
contract price and the actual cost of the commodity that was purchased or sold
at the settlement date.
FAS 133 requires us to recognize derivative instruments on the balance
sheet as either assets or liabilities measured at fair value and to record the
related unrealized gains and losses throughout the contract period until
settlement. Because of the complexity of derivatives, the FASB established a
Derivatives Implementation Group (DIG). During 2001, the DIG issued new
guidance which changed the contracts that qualified as derivatives under FAS
133.
INITIAL ADOPTION
When we adopted FAS 133 on January 1, 2001, we examined all of our
contracts and determined that some of the forward contracts that we used to
buy and sell wholesale power were considered to be derivatives based on the
accounting guidance at that time.
TEP has the following types of wholesale energy activity:
(1) Sales of firm capacity and energy under long-term contracts for
periods of more than one year.
(2) Under forward contracts, TEP commits to purchase
or sell a specified amount of capacity or energy at a specified price over a
given period of time, typically for one month, three months, or one year,
within established limits to take advantage of favorable market
opportunities. (3) Short-term economy energy sales inSome of these forward contracts are considered to be
derivatives, which TEP marks to market under FAS 133 by recording unrealized
gains and losses and adjusting the daily or hourly markets at
fluctuating spotrelated assets and liabilities on a
monthly basis to reflect the market prices and other non-firm energy sales.
(4) Salesat the end of transmission service.
Based on our interpretationthe month. However,
the majority of FAS 133 and other guidance, we classified
our contracts as follows:
Contract Type Normal Cash
Purchases Flow Trading
and Sales Hedge Activity
- -------------------------------------------------------------------------------
Coal purchase contracts, supplies and
equipment purchase contracts, debt
agreements and all other non-wholesale
energy contracts X
- -------------------------------------------------------------------------------
Wholesale Energy Contracts:
- --------------------------
- Long-Term Contracts X
- -------------------------------------------------------------------------------
- Forward Contracts
- -------------------
- Off-peak X
- -------------------------------------------------------------------------------
- On-peak* forward purchase contracts to
meet our retail and firm commitments X
- -------------------------------------------------------------------------------
- On-peak* forward sales contracts of our
excess system capacity X
- -------------------------------------------------------------------------------
- All otherTEP's forward contracts X
- -------------------------------------------------------------------------------
- Short-Term Sales X
- -------------------------------------------------------------------------------
- Transmission Sales X
- -------------------------------------------------------------------------------
* On-peak purchases and sales occur daily from 6 a.m. until 10 p.m., Monday
through Saturday.
The accounting treatment for the various classifications are as follows:
- Normal Purchases and Sales: The contracts that qualify asconsidered normal purchases and
sales are excluded from the requirements of FAS 133. The
realized gains and losses on these contracts are reflected in the income
statement at the contract settlement date.
- Cash Flow Hedge: The unrealized gains and losses related to these
forward contracts are included in Other Comprehensive Income, a component of
stockholders' equity. As the forward contracts are settled, the realized
gains and losses are recorded on the income statement as a component of
operating revenues and the unrealized gains and losses are reversed from Other
Comprehensive Income.
- Trading Activity: The unrealized gains and losses related to these
forward contracts are reflected in the income statement as a component of
operating revenues. As the forward contracts are settled, the realized gains
or losses are recorded and the unrealized gains and losses are reversed.
We recorded the cumulative effects of adoptingunder FAS 133 as of January 1,
2001, as follows. The financial statements for periods priorand, therefore, are not required to 2001 do not
reflectbe marked to market.
TEP manages the requirements of FAS 133, as we recorded realized gains and losses
at the contract settlement date.
- Income Statement: after-tax unrealized gain of $470,000.
- Balance Sheet:
- Other Comprehensive Income, a component of stockholders' equity:
after-tax unrealized loss of $14 million, and
- Forward Sale and Purchase Contracts Liability of $22 million.
NEW ACTIVITY DURING 2001
In May 2001, we entered into two swap agreements to hedge our risk of fluctuations incounterparty default by performing financial credit
reviews, setting limits monitoring exposures, requiring collateral when
needed, and using a standardized agreement which allows for the market pricenetting of
gas relatedcurrent period exposures to approximatelyand from a third of
our anticipated gas purchases from June through October 2001. These swaps
were considered derivatives and were designated as cash flow hedges.
Beginning November 2001, Millennium Environmental Group, Inc. (MEG),single counterparty.
MEG, a wholly-owned subsidiary of Millennium, began operations in
November 2001 and enteredenters into swap agreements, options and forward contracts
relating to SO2 Emission Allowances. Theseemission allowances and coal. MEG also marks its trading
contracts to market under FAS 133 by recording unrealized gains and losses
and adjusting the related assets and liabilities on a monthly basis to
reflect the market prices at the end of the month.
The market prices used to determine fair value for TEP's and MEG's
derivative instruments are estimated based on various factors including
broker quotes, exchange prices, over the counter prices and time value.
In June 2002, new guidance was issued that requires all realized and
unrealized gains and losses on energy-related trading contracts to be shown
net in the income statement whether or not physically settled. This guidance
is effective for financial statements issued after July 15, 2002, and
requires financial statements for all comparative periods to be reclassified
to conform to the new presentation. MEG adopted this guidance on July 1,
2002 for its trading activity and reclassified its net realized gains and
losses from Other Revenue into a single line in Operating Revenue. The
impact of MEG adopting this guidance was immaterial to the financial
statements. This guidance does not apply to TEP because TEP's forward
contracts are not "energy-related trading contracts" as defined by the
guidance.
TEP's activity in derivative forward contracts and MEG's trading
activity are now reported as follows:
- TEP's unrealized gain/loss on forward sales and purchase contracts is a
component of Operating Revenues;
- TEP's realized gain/loss on forward sales contracts is a component of
Electric Wholesale Revenues;
- TEP's realized gain/loss on forward purchase contracts is a component of
Purchased Power; and
- MEG's unrealized and realized gain/loss on trading activities are
components of Operating Revenues.
During the year ended December 31, 2002, MEG physically settled the
purchase of 394,000 Emission Allowances and the sale of 416,000 Emission
Allowances under its trading contracts.
The net pre-tax gains (losses) were as follows:
Years Ended
December 31,
2002 2001
-------------------------------------------------------------
-Millions of Dollars-
TEP's derivative forward contracts $ 0.5 $ (0.5)
MEG's trading activities 0.1 (0.1)
-------------------------------------------------------------
UniSource Energy $ 0.6 $ (0.6)
=============================================================
At December 31, 2002, TEP had no open forward contracts that are
considered to bederivatives. At December 31, 2002, the fair value of MEG's
trading activities. Inassets totaled $10.5 million, which is reported in Other Current
Assets, and the fair value of MEG's trading liabilities totaled $10.3
million, which is reported in Other Current Liabilities. At December 31,
2001, wethe fair value of MEG's trading assets was $8.7 million, which is
reported in Other Current Assets, and the fair value of TEP's derivative
liabilities and MEG's trading liabilities totaled $9.3 million, which is
reported in Other Current Liabilities.
TEP treated certain forward sale and purchase contracts as cash flow
hedges when it adopted FAS 133 and recorded a
pre-taxan unrealized gain/loss of less than $0.1 million related
to MEG activities.
NEW ACCOUNTING GUIDANCE DURINGthese hedges in Other Comprehensive Income. However, during 2001, In June 2001,new
guidance was issued by the DIG issued guidanceFASB which provided that certain forward power
purchase or salessale agreements, including capacity contracts, could be excluded
from the requirements of FAS 133. WeTEP implemented this new guidance on a prospective basis, beginning July 1, 2001. As a result, wein 2001
and determined that the items designated as cash flow hedge items (certain forward contracts but not the gas swap
agreements)hedges upon adoption
could be excluded from the FAS 133 requirements. We did not
reverse the unrealized gains (losses) related to the cash flow hedges in June.
Instead, because all the contracts were settled by December 31, 2001,Therefore, as thethese
contracts settled we:
-in 2001, TEP reversed the unrealized gain (loss)gain/loss included in
Other Comprehensive Income;Income and
- recorded the realized gain (loss)gain/loss in the income
statement. OnAs of December 19,31, 2002 and December 31, 2001, the FASB approved revisions to clarify the
qualifying criteria outlinedTEP had no cash
flow hedges and, therefore, its balance in FAS 133 Implementation Issue No. C15 (Issue
C15), Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-
Type Contracts and Forward Contracts in Electricity. The revised guidance
will go into effect on April 1, 2002, on a prospective basis. We are
currently in the process of evaluating the impact, if any, of the revisions to
Issue C15 on our financial statements.
To date, the DIG has issued more than 100 interpretations to provide
guidance in applying FAS 133. As the DIG or the FASB continues to issue
interpretations, we may change the conclusions that we have reached and, as a
result, the accounting treatment and financial statement impact could change
in the future.Accumulated Other Comprehensive
Income was zero.
NOTE 4. MILLENNIUM ENERGY BUSINESSES
- -------------------------------------
See Note 5 for selected financial data of Millennium.
At December 31, 2002, Millennium recognized 100% of the losses of the
following: Global Solar Energy, Inc. (Global Solar), MicroSat Systems, Inc.
(MicroSat), ITN Energy Systems, Inc. (ITN), POWERTRUSION International, Inc.
(Powertrusion), and TruePricing, Inc. (TruePricing). At December 31, 2001,
Millennium recognized 100% of the losses of the following: Global Solar,
Infinite Power Solutions, Inc. (IPS), MicroSat and ITN. At December 31,
2000, Millennium recognized 100% of the losses from Global Solar and IPS.
Millennium recognizes 100% of an investment's losses when it, as sole
provider of funds, bears all of the financial risk. In addition, when one of
these investments becomes profitable, Millennium will recognize 100% of net
income to the extent Millennium's recognized losses are greater than
Millennium's ownership percentage of such losses.
ENERGY TECHNOLOGY INVESTMENTS
We refer to Global Solar, IPS, MicroSat and ITN collectively as
Millennium's Energy Technology Investments. In addition to the above,
Millennium owns 67%recognized substantially all of IPS's losses in 2002. In December
2002, IPS received a cash equity contribution from Dow Corning Enterprises,
Inc. (Dow Corning). This investment permits Millennium to recognize only its
ratable share of losses from the following entitiesinvestment going forward.
Millennium's total investment (capital contributions and their financial
statements are consolidated into the Millennium and UniSourceloans) in its
Energy financial
statements. A privately held company owns the remaining 33%.Technology Investments totaled $18.5 million during 2002.
- Global Solar is primarily a developer and manufacturer of flexible thin-filmthin-
film photovoltaic cells. Global Solar began limited production of
photovoltaic cells in 1999. Target markets for its products include
military, space and commercial applications. Prior to June 1, 2000,In 2002, Millennium owned 50%increased
its ownership of Global Solar from 67% to 87%. In addition, Millennium
converted $27.4 million of debt and reported Global Solar's results of operations using the equity method. By the
end of 1999, all of the other owner's equity contributions had been written
down to zero for financial reporting purposes. As a result, minorityaccumulated interest is not reflected in the financial statements and Millennium records 100% of
Global Solar's losses for accounting purposes. Whendue from Global
Solar generates
net income,to an equity contribution. Millennium will recognize 100%accounts for the Global Solar
investment under the consolidation method. At December 31, 2002, there
remained $4.7 million of net incomeunfunded commitments from Millennium to the extent
Millennium's recognized losses are greater than Millennium's ownership
percentageGlobal
Solar, of such losses.which $3 million was drawn through March 5, 2003.
- Infinite Power Solutions, Inc.IPS, established in 2000, is a developer of thin-film batteriesbatteries. In
2002, Millennium increased its ownership in IPS from 67% to 77.5%. In
2002, Millennium converted $9.8 million of debt and was established in 2000. The other owner contributed certain assets and
proprietary and intellectual property relatingaccumulated interest
due from IPS to thin-film battery
technology.an equity contribution. In 2001 and 2000,addition, Millennium provided
$0.2$1 million and $15of equipment to IPS in exchange for equity. In December 2002,
Dow Corning provided a corresponding $1 million respectively,cash equity contribution.
IPS received an additional $1 million equity contribution from Dow Corning
on March 4, 2003. Millennium had committed an additional $1.5 million in
equityfuture funding to these entities. In 2001, 2000IPS. Millennium contributed $1 million of its future
funding commitment in January 2003. Millennium accounts for the IPS
investment under the consolidation method. Depending on warrant exercise
and 1999,additional funding from Dow Corning, Millennium provided net debt funding to these entitiesanticipates its
ownership of approximately $20
million, $2 millionIPS will be between 59% and $4 million, respectively.
During 2001, Millennium and a privately held company formed and began to
provide funding to MicroSat Systems, Inc. and ITN Energy Systems, Inc. Even
though Millennium applies the equity method of accounting (see Basis of
Presentation in Note 1) to these entities, as the sole provider of funds,
Millennium recognizes 100% of their losses.72%.
- MicroSat Systems, Inc. (MicroSat) is a space systems company formed in 2001 to develop and
commercialize small-scale satellites. Millennium currently owns 49% and provided $10 million in, but
has agreed to reduce its ownership to 35%. Millennium accounts for the
MicroSat investment under the equity method. Millennium currently has no
further funding during 2001. The other owner
contributed development contracts and proprietary technologies.commitments to MicroSat.
- ITN Energy Systems, Inc. (ITN) was formed in 2001 to provide research and development and other
services to affiliates, the Governmentgovernment agencies and other third parties. In
2002, Millennium currentlyprovided $1 million in equity funding. Currently
Millennium owns 49%, but has agreed to reduce its ownership to 9%. Because
Millennium contributed $3is the primary funder of ITN's operations, it will continue to
account for ITN under the equity method. At December 31, 2002, Millennium
had $0.8 million of
equity and $1.6 million of debtin open funding commitments to ITN, during 2001. The other owner
contributed contractsprimarily relating to
the establishment of a new solid oxide fuel cell subsidiary called Ascent
Power Systems.
Global Solar and intellectual property.IPS have each agreed to provide ITN $1 million in
research and development contracting through 2004. Global Solar, MicroSat
and ITN have certain government contracts that require them to contribute to
the research and development effort under cost share arrangements. Global
Solar, MicroSat and ITN's share of costs are expensed as incurred or
capitalized in accordance with the terms of the contracts. Global Solar,
had no remaining cost share commitment under these
contracts at December 31, 2001. MicroSat had approximately $8 million and ITN had approximately $2 million ofthe following approximate remaining cost share
commitments under these
contracts atat:
December 31,
2001.
We are2002 2001 2000
---------------------------------------------------
-Millions of Dollars-
Global Solar $ 2.6 $ - $ 1.0
MicroSat 6.2 7.7 -
ITN 0.9 2.2 -
---------------------------------------------------
Total $ 9.7 $ 9.9 $ 1.0
===================================================
Millennium is currently evaluating and renegotiating ourfinalizing its ownership and future debt
commitments for each of the Energy Technology Investments in order to help
ensure that these investments conform to Millennium's business plans.
Therefore, Millennium's ownership share is subject to change in 2003.
Millennium expects to fund the remaining balance under its current
commitments, approximately $14between $7 million and $15 million to its various
Energy Technology Investments in 2002. We2003. Millennium may commit to provide
additional funding to these investments. A significant portion of the
funding under these agreements will be used for research and development
purposes and administrative costs. As funds are expended for these purposes,
we recognizeMillennium recognizes expense.
INTERNATIONAL POWER PROJECTS - NATIONS ENERGY CORPORATIONOTHER MILLENNIUM INVESTMENTS AND COMMITMENTS
Millennium has a $15 million capital commitment to Haddington Energy
Partners II LP, a limited partnership that funds energy related investments.
As of December 31, 2002, Millennium had funded $6.6 million of this
commitment and owns approximately 31% of this entity. The remaining $8.4
million is expected to be funded within the next two to three years. A
member of the UniSource Energy Board of Directors has an investment in the
limited partnership and is a managing director of the general partner of the
limited partnership. Millennium accounts for this investment under the
equity method.
Millennium has a $6 million capital commitment to a venture capital fund
that focuses on information technology, microelectronics and biotechnology
investments. During 2002, this venture capital fund merged with another fund
that focuses on similar investments in Arizona, Southern California, New
Mexico, Colorado and Utah. As a result, Millennium owns 14.8% of the merged
venture. Millennium uses the cost method to account for this investment.
Before the merger, Millennium accounted for this investment under the equity
method. Another member of the UniSource Energy Board of Directors is a
general partner of the company that manages the fund. At December 31, 2002,
Millennium had funded approximately $1 million of the $6 million commitment.
Millennium does not currently expect to provide funding to this investment in
2003.
On July 15, 2002, Millennium invested $20 million in a company created
to develop up to 800 megawatts (MW) of coal-fired generation in the Sabinas
region of Coahuila, Mexico. Millennium received a 50% share of
Carboelectrica Sabinas, S. de R.L. de C.V., a Mexican limited liability
company (Sabinas). The other 50% of Sabinas is owned by Altos Hornos de
Mexico, S.A. de C.V. (AHMSA) and certain of its affiliates. Sabinas also
owns 19.5% of Minerales de Monclova, S.A. de C.V., (Mimosa) an owner of coal
and associated gas reserves and a supplier of metallurgical coal to the steel
industry and thermal coal to the Mexican electricity commission. Since 1999,
both AHMSA and Mimosa are parties to a suspension of payments procedure,
under applicable Mexican law, which is the equivalent of a U.S. Chapter 11
proceeding. Under certain circumstances, Millennium has the right to sell (a
put option) its interest in Sabinas to an AHMSA affiliate for $20 million
plus an accrued service fee. These circumstances include failure of Sabinas
to reach financial closing on the generation project within three years.
Millennium's put option is secured by collateral with a value currently in
excess of $20 million. UniSource Energy's Chairman, President and Chief
Executive Officer is a member of the board of directors of AHMSA. In
December 2002, Millennium received a return of capital of $0.5 million,
bringing Millennium's investment to approximately $19.5 million at December
31, 2002. In addition, in the first quarter of 2003, Millennium received a
second $0.5 million also representing a return of capital. Millennium
accounts for the Sabinas investment under the equity method, however, Sabinas
accounts for the Mimosa investment under the cost method.
Millennium owns a controlling 50.5% interest in Powertrusion, a
manufacturer of lightweight utility poles. During the third quarter of 2002,
Millennium provided an additional $2 million of funding to maintain its
controlling interest. Millennium accounts for the Powertrusion investment
under the consolidation method. In addition, during the third quarter of 2002
Millennium began recognizing 100% of Powertrusion's losses, as it became the
sole funder of Powertrusion's operations.
On April 1, 2002, Millennium invested an additional $2 million in
TruePricing, a start-up company established to market energy related
products, bringing Millennium's total investment to $3.1 million at December
31, 2002. Following this additional investment, Millennium began recognizing
100% of TruePricing's losses. Millennium accounts for the TruePricing
investment under the equity method. In February 2003, Millennium committed
to fund up to an additional $1.2 million in equity contributions to
TruePricing, of which $0.4 million was funded on March 5, 2003.
Nations Energy is a wholly-owned subsidiary of Millennium.Millennium, accounted for
under the consolidation method. Through its subsidiaries, Nations Energy has
a 40% equity interest in a 43 MW power plant near Panama City, Panama. No
impairment was recorded in 2002, however, Nations Energy recorded decreases
in the market value of its Panama investment of $0.5 million in 2001 and $3
million per year in 2000
and 1999.2000. In 2000, Nations Energy recognized a $3 million deferred
tax benefit related to the decreased value. Nations Energy intends to sell
its interest in this project, which has a book value of less than $1 million
at December 31, 2001.2002.
NATIONS ENERGY CONTINGENCY
In September 2001, Nations Energy recorded an after-tax gain of $5.6 million from
the sale ofsold its 26% equity interest in a
power project located in Curacao, Netherland Antilles.Antilles to a subsidiary of
Mirant Corporation (Mirant). Nations Energy received $5 million in cash
proceeds the
return of cash construction deposits and recorded an $8$11 million note receivable from the sale. The cash proceeds and the return of construction
deposits are reflected as Investing Activities in UniSource Energy's 2001 cash
flow statement. The note receivable is secured by guarantees from the
purchaser's parent. The note receivable was
recorded at its net present value of $8 million, with the discount being
amortized to interest income over the five-year life of the note. Millennium
utilizes an 8% discount rate, established on the date this note was
initiated. The note is included in Investments and paymentsOther Property - Other on
UniSource Energy's consolidated balance sheet. The note is guaranteed by
Mirant Americas, Inc., a subsidiary of Mirant. Payments on the note
receivable are expected as follows: $2 million in July 2004, $4 million in
July 2005, and $5 million in July 2006.
In 2000, Nations Energy recorded a pre-tax gainlate 2002, the major rating agencies downgraded the ratings of approximately $3
million from the saleMirant
and certain of its minority interest in a power project located in
the Czech Republic. Nations received $20 million in cash proceeds from the
sale, which is reflected as an Investing Activity in UniSource Energy's 2000subsidiaries citing Mirant's significantly lower operating
cash flow statement.
OTHER MILLENNIUM INVESTMENTS AND COMMITMENTS
In July 2000, Millennium made a $15 million capital commitmentrelative to a
limited partnership which will fund energy related investments.its debt burden coupled with the likelihood that future
operating cash flow levels may weaken further. Their ratings are now below
investment grade. As of December 31, 2001, Millennium2002, Nations Energy's receivable from
Mirant is approximately $9 million. We cannot predict what effect the
downgrade of Mirant will have on its ability to make its required payments to
Nations Energy when due, beginning in July 2004. Nations Energy has funded approximately $6 million under this
commitment, $4 million of which was funded in 2001. The remaining $9 million
is expectednot
recorded an allowance for doubtful accounts and we will continue to be invested within three years. The limited partnership's
results of operation are recognized underevaluate
whether any further ratings events or actions by or to Mirant will impact the
equity method based on our
ownership percentage. A membercollectibility of the UniSource Energy Board of Directors has
a minor investment in the project. An affiliate of such board member serves
as the general partner.
In November 2000, Millennium made a $5 million capital commitment to a
venture capital fund that will focus on information technology, optics and
biotechnology primarily within the retail service territory of TEP. The
fund's results of operation are recognized under the equity method based on
our percent ownership. A member of the UniSource Energy Board of Directors
owns the company that manages the fund. As of December 31, 2001, Millennium
had funded approximately $1 million under this commitment. Millennium expects
to fund approximately $1 million under this agreement in 2002.
In November 2001, Millennium contributed $5 million in equity and $4
million in debt financing to MEG. MEG was established to manage and trade
Emission Allowances, coal and other financial instruments. Millennium's
contributions provided the working capital necessary to facilitate entry into
these markets.
In August 2001, Millennium invested $3 million for a 50.5% controlling
interest in Powertrusion International, Inc. (Powertrusion), a manufacturer of
lightweight utility poles. Millennium consolidated Powertrusion's balance
sheet and results of operations as of the investment date. Maintaining
control of Powertrusion will depend upon many factors, including providing an
additional $2 million in contingent consideration by August 2002.
Contribution of any additional investment will be solely determined by
Millennium. Minority shareholder interests in Powertrusion represent 49.5% of
the outstanding common shares and 100% of the outstanding cumulative preferred
shares in the company.
In July 1999, MEH Corporation sold its 50% ownership in NewEnergy, Inc.
(NewEnergy) to the AES Corporation for approximately $50 million in
consideration, resulting in a pre-tax gain from the sale of approximately $35
million. As part of the transaction, NewEnergy issued two promissory notes
totaling $22.8 million. One of the promissory notes in the principal amount
of $11.4 million was paid on July 24, 2000 and the remaining promissory note
for $11.4 million was paid on July 23, 2001.receivable.
NOTE 5. SEGMENT AND RELATED INFORMATIONBUSINESS SEGMENTS
- ------------------------------------------------------------------
Based on the way we organize our operations and evaluate performance,
beginning in 2001, we
have three reportable business segments:
(1) TEP, an electric utility business, is UniSource Energy's principal
business segment.largest
subsidiary.
(2) Millennium holds interests in unregulated energy businesses (see
Note 4).
(3) UED, established in 2001, engages inis responsible for developing generating resources
and otherthe expansion
project development activities.at the Springerville Generating Station. Prior to September
2002, UED ownsowned a 20 MW gas turbine, underwhich it leased to TEP. In
September 2002, UED sold the turbine to TEP for its net book value of
$15 million.
Significant reconciling adjustments consist of the elimination of
intercompany activity and balances. Millennium recorded revenue from
transactions with TEP of $14 million, $13 million and $3 million in 2002,
2001 and 2000, respectively. TEP's related expense is reported in Other
Operations and Maintenance expense on its income statement. Millennium's
revenue and TEP's related expense are eliminated in UniSource Energy
consolidation. Other significant reconciling adjustments include the
elimination of the intercompany note between UniSource Energy and TEP, as
well as the related interest income and expense; and the elimination of UED's
rental income and TEP's rental expense from UED's turbine lease to TEP. It is also responsible for developing Springerville Units 3 and
4 for the expansionTEP prior
to UED's sale of the Springerville Generating Station.turbine to TEP in September 2002.
As discussed in Note 1, we record our percentage share of the earnings
of affiliated companies when we hold a 20% to 50% voting interest, except for
investments where we provide all of the financing, in which case we recognize
100% of the losses. See Note 4. Our portion of the net income (loss) of the
entities in which TEP and Millennium own a 20-50% interest or have the
ability to exercise significant influence is shown below in Net Loss from
Equity Method Entities.
Significant reconciling adjustments consist of the elimination of
intercompany activity and balances, including:
- the elimination of intercompany sales between business segments;
- the elimination of the intercompany note between UniSource Energy and
TEP, as well as the related interest income and expense; and
- the elimination of UED's rental income and TEP's rental expense from
UED's turbine lease to TEP.
We disclose selected financial data for our business segments in the
following tables:
Segments ----------------------
UniSource
--------------------- Reconciling Energy
20012002 TEP Millennium UED Adjustments Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Millions of Dollars-
Income Statement
- ----------------
Operating Revenues
- External $1,436 $ 9851 $ 5 $ - $ - $1,445$ 856
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues
- Intersegment - 14 3 (17) -
- -----------------------------------------------------------------------------
Depreciation and
Amortization 124 4 - - 128
- -----------------------------------------------------------------------------
Amortization of Transition
Recovery Asset 25 - - - 25
- -----------------------------------------------------------------------------
Interest Income 29 1 - (9) 21
- -----------------------------------------------------------------------------
Net Loss from
Equity Method Entities (1) (3) - - (4)
- -----------------------------------------------------------------------------
Interest Expense 154 1 - - 155
- -----------------------------------------------------------------------------
Income Tax (Benefit)
Expense 35 (15) 1 (4) 17
- -----------------------------------------------------------------------------
Net Income (Loss) 54 (16) 1 (6) 33
- -----------------------------------------------------------------------------
Cash Flow Statement
- -------------------
Capital Expenditures (103) (10) - - (113)
- -----------------------------------------------------------------------------
Purchase of North Loop Gas
Turbine from UED (15) - 15 - -
- -----------------------------------------------------------------------------
Investments in and Loans
to Equity Method Entities - (24) - - (24)
- -----------------------------------------------------------------------------
Balance Sheet
- -------------
Total Assets 2,614 151 38 (112) 2,691
- -----------------------------------------------------------------------------
Investment in Equity
Method Entities 6 35 - - 41
- -----------------------------------------------------------------------------
2001
- -----------------------------------------------------------------------------
Income Statement
- ----------------
Operating Revenues
- External $1,409 $ 8 $ - $ - $1,417
- -----------------------------------------------------------------------------
Operating Revenues
- Intersegment - 13 2 (15) -
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Depreciation and
Amortization 117 3 - - 120
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Amortization of Transition
Recovery Asset 22 - - - 22
- -----------------------------------------------------------------------------
Interest Income 21 3 - (9) 15
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Loss from
Equity Method Entities (1) (10) - - (11)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Interest Expense 159 - - - 159
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Income Tax (Benefit)
Expense 56 (5) - (4) 47
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) 75 (9) 1 (6) 61
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Cash Flow Statement
- -------------------
Capital Expenditures (104) (17) (1) - (122)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Investments in and Loans
to Equity Method InvesteesEntities - (18) - - (18)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -------------
Total Assets 2,6342,645 176 27 (102) 2,735(101) 2,747
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Investment in Equity
Method Entities 7 14 - - 21
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
2000
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Income Statement
- ----------------
Operating Revenues
- External $1,028 $ 6 $ - $ - $1,034
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues
- Intersegment - 3 - (3) -
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Depreciation and
Amortization 114 - - - 114
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Amortization of Transition
Recovery Asset 17 - - - 17
- -----------------------------------------------------------------------------
Interest Income 18 4 - (8) 14
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Loss from
Equity Method Entities (2) (2) - - (4)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Interest Expense 166 - - - 166
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Income Tax (Benefit)
Expense 27 (8) - (4) 15
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) 51 (4) - (5) 42
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Cash Flow Statement
- -------------------
Capital Expenditures (98) (8) - - (106)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Investments in and Loans
to Equity Method InvesteesEntities (2) (17) - - (19)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -------------
Total Assets 2,601 167 - (97) 2,671
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Investment in Equity
Method Entities 9 6 - - 15
- -------------------------------------------------------------------------------
1999
- -------------------------------------------------------------------------------
Income Statement
- ----------------
Operating Revenues
- External $ 804 $ 11 $ - $ - $ 815
- -------------------------------------------------------------------------------
Operating Revenues
- Intersegment - - - - -
- -------------------------------------------------------------------------------
Depreciation and Amortization 93 - - - 93
- -------------------------------------------------------------------------------
Interest Income 18 1 - (9) 10
- -------------------------------------------------------------------------------
Gain on the Sale of NewEnergy - 35 - - 35
- -------------------------------------------------------------------------------
Net Loss from
Equity Method Entities - (4) - - (4)
- -------------------------------------------------------------------------------
Interest Expense 123 - - - 123
- -------------------------------------------------------------------------------
Income Tax (Benefit) Expense 22 12 - (3) 31
- -------------------------------------------------------------------------------
Extraordinary Income - Net
of Tax 23 - - - 23
- -------------------------------------------------------------------------------
Net Income (Loss) 73 11 - (5) 79
- -------------------------------------------------------------------------------
Cash Flow Statement
- -------------------
Capital Expenditures (91) (2) - - (93)
- -------------------------------------------------------------------------------
Investments in and Loans to
Equity Method Investees - (7) - - (7)
- -------------------------------------------------------------------------------
Balance Sheet
- -------------
Total Assets 2,601 100 - (45) 2,656
- -------------------------------------------------------------------------------
Investment in Equity Method
Entities 9 24 - - 33
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
NOTE 6. TEP'S UTILITY PLANT AND JOINTLY-OWNED FACILITIES
- ---------------------------------------------------------
UTILITY PLANT
The following table shows TEP's Utility Plant in Service by major class:
December 31,
2002 2001
2000
------------------------------------------------------------------------------------------------------------------------------------------
-Millions of Dollars-
Plant in Service:
Generation Plant $ 1,1331,166 $ 1,0821,133
Transmission Plant 515 508 502
Distribution Plant 741 692 643
General Plant 130 120 118
Intangible Plant 4446 44
Electric Plant Held for Future Use 1 1
------------------------------------------------------------------------------------------------------------------------------------------
Total Plant in Service $ 2,599 $ 2,498
$ 2,390
==========================================================================================================================================
Utility Plant Underunder Capital Leases $ 741747 $ 741
==========================================================================================================================================
Intangible Plant primarily represents computer software costs. TEP's
unamortized computer software costs were $28 million and $30 million as of
December 31, 2002 and 2001, respectively.
All Utility Plant Underunder Capital Leases is used in TEP's generation
operations.
The depreciable lives currently used by TEP are as follows:
Major Class of Utility Plant in Service: Depreciable Lives:
----------------------------------------------------------------
Generation Plant 23-60 years
Transmission Plant 10-50 years
Distribution Plant 24-60 years
General Plant 5-45 years
Intangible Plant 3-10 years
In the second quarter of 2002, TEP increased its estimates of useful
lives from 40 years to 60 years for its Irvington Generating Station gas-
fired generating units and from 25 years to 40 years for its internal
combustion turbines. These changes in estimates decreased depreciation
expense by approximately $3 million for the year ended December 31, 2002.
TEP continues to evaluate the depreciable lives of its other generating
stations.
See TEP Utility Plant and TEP Utility Plant Under Capital Leases
in Note 1 and TEP Capital Lease Obligations in
Note 7.
JOINTLY-OWNED FACILITIES
At December 31, 2001,2002, TEP's interests in generating stations and
transmission systems that are jointly-owned with other utilities were as
follows:
Percent Plant Construction
Owned by Inin Work Inin Accumulated
TEP Service* Progress Depreciation
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Millions of Dollars-
San Juan Units 1 and 2 50.0% $ 289 $ 69 $ 226228
Navajo Station Units 1,2 and 3 7.5 124 1 66125 2 72
Four Corners Units 4 and 5 7.0 79 1 692 73
Transmission Facilities 7.5 to 95.0 224225 - 145152
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ 716718 $ 813 $ 506
===============================================================================
* Included525
=============================================================================
*Included in Utility Plant shown above.
TEP has financed or provided funds for the above facilities and TEP's
share of their operating expenses is reflected in the income statements. See
Note 10 for commitments related to ourTEP's jointly-owned facilities.
NOTE 7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
- -------------------------------------------------------------------------------------------------
TEP LONG-TERM DEBT
LONG-TERM DEBT MATURES MORE THAN ONE YEAR FROM THE DATE OF THE FINANCIAL
STATEMENTS. WE SUMMARIZE OUR LONG-TERM DEBT IN THE STATEMENTS OF
CAPITALIZATION.
Bond Issuance and Redemption
During 2001,Long-term debt matures more than one year from the date of the financial
statements. We summarize our long-term debt in the statements of
capitalization.
TEP made the required sinking fund payments of $2 million on its First
Mortgage IDBs in each of 2002 and 2001. TEP redeemed $0.2$0.4 million of its
8.5% First Mortgage Bonds.Bonds in 2002 and $0.2 million in 2001. TEP did not
issue any new bonds in 2002 or 2001.
During 2000, TEP repaid as scheduled $47 million of its 12.22% Series
First Mortgage Bonds which matured on June 1. In addition,Bonds. Also during 2000, TEP redeemed $2 million of its 7.5%
First Collateral Trust Bonds at a discount and made required sinking fund
payments on First Mortgage Bonds of $2 million.
During 1999, TEP did not issue any new bonds or redeem existing bonds,
other than required sinking fund payments of $2 million on First Mortgage
Bonds.
TEP OTHER LONG-TERM DEBT AND AGREEMENTS
FIRST AND SECOND MORTGAGEFirst and Second Mortgage
-------------------------
TEP's first and second mortgage indentures are collateralized by a $956
million lien on TEP's utility plant, with the exception of Springerville Unit
2. San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title
to Springerville Unit 2. Utility Plant under Capital Leases is not subject
to such liens or available to TEP creditors, other than the lessors.
BANK CREDIT AGREEMENTBank Credit Agreement
---------------------
In November 2002, TEP hasentered into a new $401 million Credit Agreement
to replace the credit facilities provided under its then existing $441
million Credit Agreement whichthat would have expired December 30, 2002. The new
agreement provides a $100$60 million Revolving Credit Facility and a $341 milliontwo Letter of
Credit Facility (LOC).
These credit facilities mature on December 30, 2002(Tranche A and are collateralized by
$441 million of Second Mortgage Bonds. The Credit Agreement contains certain
financial covenants, including cash coverage, leverage and net worth tests.
As of December 31, 2001, TEP was in compliance with these covenants.Tranche B; collectively, LOC) totaling $341
million. The Revolving Credit Facility, can be used to provide liquidity for
general corporate purposes.
At December 31, 2001 and 2000, TEP had no outstanding borrowings under this
facility. When we borrow under the Revolving Credit Facility, the variable
interest ratepurposes, is a 364-day facility that we pay is dependent, in part,expires on the credit rating on TEP's
senior collateralized debt. We pay an annual commitment fee on the unused
portion of the Revolving Credit Facility. This fee is also dependent on TEP's
credit ratings. At December 31, 2001, the commitment fee equaled 0.25% per
year.November
13, 2003. The $341 million LOC Facility secures the payment of principal and interest on $329
million of tax-exempt variable rate bonds (IDBs). Tranche A provides $135
million and expires in January 2006; Tranche B provides $206 million and
expires in November 2006. The amountnew facilities are collateralized by $401
million of Second Mortgage Bonds.
The new Credit Agreement contains a number of restrictive covenants that
are similar to TEP's previous credit agreement, including restrictions on
additional indebtedness, liens, sale of assets or mergers and sale-
leasebacks. The new Credit Agreement, like the prior agreement, also
contains several financial covenants including net worth, cash coverage and
leverage tests. As of December 31, 2002, TEP was in compliance with these
financial covenants.
At December 31, 2002 and 2001, TEP had no outstanding borrowings under
these facilities. When TEP borrows under the Revolving Credit Facility, the
borrowing costs are at a variable interest rate consisting of a spread over
LIBOR or an alternate base rate. The spread is based upon a pricing grid
tied to TEP's credit ratings. Also, TEP pays an annual commitment fee on the
unused portion of the Revolving Credit Facility and a fee on the LOC
Facility dependsfacilities. The chart below shows the per annum rates and fees in effect on
TEP's credit ratings. AtCredit Facilities as of December 31, 2001,2002, based on its credit ratings,
as well as the commitment fee equaled 1.25% per year.possible range of rates and fees if TEP's credit ratings were
to change:
Current Rate/ Range of
Fee Rates/Fees
-------------- ------------
Revolving Credit Facility
-Commitment Fee 0.35% 0.25% to 0.40%
-Borrowing Rate (spread over LIBOR) 4.00% 3.50% to 4.25%
Tranche A LOCs (including LOC
Fronting Fee) 4.25% 3.75% to 4.50%
Tranche B LOCs (including LOC
Fronting Fee) 5.75% 5.75%
The LOCs expire
on December 30, 2002. If$329 million in aggregate principal amount of tax-exempt variable
rate debt that is supported by the LOCs are not extended or replaced with new LOCs
with a longer term or if the bonds are not otherwise refinanced, the bonds
would be redeemed. Accordingly, these IDBs werewas classified as short-term debt at
December 31, 2001 and will bebecause the previous letter of credit facility matured on
December 30, 2002. When the new LOCs were issued in November 2002, TEP
classified the bonds as long-term debt once abecause the new LOC
facility with a later expiration date is obtained.LOCs mature in 2006.
TEP CAPITAL LEASE OBLIGATIONS
The terms of TEP's capital leases are as follows:
- The Irvington Lease has an initial term to January 2011 and provides for
renewal periods of two or more years through 2020.
- The Springerville Common Facilities Leases have an initial term to June
2017 for one lease and July 2020 for the other two leases, subject to
optional renewal periods of two or more years through 2025.
- The Springerville Unit 1 Leases have an initial term to January 2015 and
provide for renewal periods of three or more years through 2030.
- The Springerville Coal Handling Facilities Leases have an initial term
to April 2015 and provide for one renewal period of six years, then
additional renewal periods of five or more years through 2035.
Springerville Lease Debt and Equity
-----------------------------------
TEP purchased a 13% ownership interest in the Springerville Coal
Handling Facilities Leases for $13 million in December 2001 and all $96
million of the debt related to these capital leases in January 2002. In
March 2002, TEP terminated the lease related to its equity interest and
cancelled the associated debt. As a result of the lease termination, TEP
recorded a $21 million reduction to the capital lease obligation, a $27
million reduction of its investment, and a $6 million increase in the capital
lease asset, which represents the residual value of TEP's interest in the
leased asset and is carried at cost. At December 31, 2002 and December 31,
2001, TEP held $84 million and $13 million, respectively, of Springerville
Coal Handling Facilities lease debt and equity.
In addition, TEP purchased $36 million of Springerville Unit 1 lease
debt in 2002. At December 31, 2002 and December 31, 2001, TEP held $108
million and $71 million, respectively, of Springerville Unit 1 lease debt.
TEP recognizes interest income on these investments. TEP's purchases of
lease debt and equity are reflected in investing activities on TEP's cash
flow statements.
TEP MATURITIES AND SINKING FUND REQUIREMENTS
TEP's long-term debt, including sinking funds, and lease obligations
mature on the following dates:
Scheduled
IDBs ScheduledLong-Term Capital
Supported by Long-Term Capital
Expiring Debt Lease
LOCs Retirements Obligations Total
------------------------------------------------------------------------
-Millions of Dollars-
20022003 $ 329- $ 2 $ 90121 $ 421
2003 - 2 123 125
2004 - 2 125 127124 126
2005 - 2 125 127
2006 -329 21 127 148477
2007 - 1 128 129
------------------------------------------------------------------------
Total 20022003 - 20062007 329 29 590 94828 625 982
Thereafter - 775 1,125 1,900773 965 1,738
Less: Imputed Interest - - (842) (842)(746) (746)
------------------------------------------------------------------------
Total $ 329 $ 804801 $ 873 $2,006844 $1,974
========================================================================
In addition to the capital lease obligations above, weTEP must ensure $70
million of notes underlying the Springerville Common Facilities Leases are
refinanced by June 30, 2003 to avoid a special event of loss under the lease.
This special event of loss would require usTEP to repurchase the property leased
under the Springerville Common Facilities Leases at the higher of the
stipulated loss value of $125 million or the fair market value of the
facilities. Upon such purchase, the lease would be terminated.
InMEG LINE OF CREDIT
MEG has a $5 million bank line of credit for the purpose of issuing
letters of credit to counterparties to support its emission allowance and
coal trading activities. as of December 2001, TEP purchased a 13% ownership interest31, 2002, MEG had $2 million in
the
Springerville Coal Handling Facilities Leases for $13 million. In a related
transaction,outstanding LOCS. this facility expires in January 2002, TEP purchased all $96 million of the capital
lease debt related to these leases. In the first quarter of 2002, TEP will
cancel that portion of the leases related to its equity interest, as it holds
both the ownership interest and the debt.
In December 1999, TEP refinanced $70 million of notes underlying the
Springerville Common Facilities Leases to avoid a special event of loss under
the lease. As a result of refinancing at a higher interest rate, we recorded
an additional $26 million of capital lease obligations and capital lease
assets.August 2004.
NOTE 8. FAIR VALUE OF UNISOURCE ENERGYTEP'S FINANCIAL INSTRUMENTS
- ----------------------------------------------------------------------------------------------------------------
The carrying values and fair valuevalues of TEP and Millennium'sTEP's financial instruments are
as follows:
December 31,
2002 2001
2000
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Millions of Dollars-
Millennium
AssetsAssets:
Springerville Lease Debt
Securities (Included in
Investments and Other Property) $ -192 $ -196 $ 271 $ 2
TEP
Assets
Springerville Lease
Debt Securities (Included in
Investments and Other Property) 71 74 69 76
Springerville Lease Ownership
Interest (Included in
Investments and Other Property) - - 13 13
- -
LiabilitiesLiabilities:
First Mortgage Bonds - Fixed Rate:
Corporate 27 28 28 28 29
Industrial Development Revenue
Bonds (IDBs) 57 57 58 59 60 60
First Collateral Trust Bonds 138 140 138 138 137
Second Mortgage Bonds - IDBs
(Variable Rate) 329 329 329 329
Unsecured IDBs - Fixed Rate 579 569 579 534
579 533
- -------------------------------------------------------------------------------
In 2000, Millennium purchased $27 million-----------------------------------------------------------------------------
See Note 7 for a description of TEP's 2002 investment in Springerville
Lease Debt
Securities. In 2001 and 2000 Millennium sold Springerville Lease Debt
Securities with a carrying value of $2 million and $25 million, respectively,
to TEP at cost.Debt. TEP intends to hold the $192 million investment in Springerville
Lease Debt Securities to maturity ($4253 million matures through January 1,
2009, $84 million matures through July 1, 2011, and $29$55 million matures
through January 1, 2013). These Springerville Lease Debt Securities
areThis investment is stated at amortized cost, which
means the purchase cost has been adjusted for the amortization of the premium
and discount to maturity. We baseTEP bases the fair value of this investment on
quoted market prices for the same or similar debt. In 2001, TEP purchased, for $13 million, a 13 percent ownership
interest in the Springerville Coal Handling Facilities Lease. TEP's purchases
of Springerville Lease Debt and Equity are reflected in investing activities
on TEP's 2001 and 2000 cash flow statements.
TEP considers the principal amounts of variable rate debt outstanding to
be reasonable estimates of their fair value. WeTEP determined the fair value
of TEP'sits fixed rate obligations including the Corporate First Mortgage Bonds,
the First Mortgage Bonds-IDBs, First Collateral Trust Bonds and the Unsecured
IDBs by calculating the present value of the cash flows of each fixed rate
obligation. WeTEP used a rate consistent with market yields generally
available as of December 20012002 for 20012002 amounts and December 20002001 for 20002001
amounts for bonds with similar characteristics with respect to credit rating,
time-to-
maturity,time-to-maturity, and the tax status of the bond coupon for federal income
tax purposes. The use of different market assumptions and/or estimation
methodologies may yield different estimated fair value amounts.
The carrying amounts of our current assets and liabilities approximate
fair value.
NOTE 9. STOCKHOLDERS' EQUITY
- -----------------------------
DIVIDEND LIMITATIONS
- -----------------------------
UNISOURCE ENERGYUniSource Energy
----------------
In February 2002,2003, UniSource Energy declared a quarterly dividend to the
shareholders of $0.125$0.15 per share of UniSource Energy Common Stock. The
dividend, totaling approximately $4.0$5 million, will be paid on March 8, 20027, 2003 to
common shareholders of record as of February 21, 2002.2003. In 2002, UniSource
Energy paid quarterly dividends to the shareholders of $0.125 per share, for
a total of $0.50 per share, or $17 million, for the year. During 2001,
UniSource Energy paid quarterly dividends to the shareholders of $0.10 per
share, totaling approximately $13 million andfor a total of $0.40 per share, or $13 million, for the year. During
2000, UniSource Energy paid quarterly dividends to the shareholders of $0.08
per share, totaling $10 million andfor a total of $0.32 per share, or $10 million, for the year. UniSource
Energy did not pay dividends in 1999.
Our ability to pay cash dividends on common stock outstanding depends,
in part, upon cash flows from our subsidiaries,subsidiaries: TEP, Millennium and UED.
TEP
---
TEP paid dividends of $35 million in 2002, $50 million in 2001, and $30
million in 2000, and $34
million in 1999.2000. UniSource Energy is the primary holder of TEP's common
stock. TEP met the following requirements before paying these dividends:
- Bank Credit Agreement
During 2000 through 2002, TEP's bank Credit Agreement allowsallowed TEP to pay
dividends as long as TEP maintainsmaintained compliance with the agreement and meetsmet its
financial covenants. TEP's new Credit Agreement as of November 2002 applies
those same restrictions as well as restricting TEP's dividends to 65% of
TEP's consolidated net income for the immediately preceding fiscal year, as
long as the Tranche B LOCs are outstanding.
- ACC Holding Company Order
The ACC Holding Company Order does not allow TEP to pay dividends in
excess of 75% of its annual earnings until TEP's equity ratio equals 37.5% of
total capitalization, excluding capital lease obligations.
- Federal Power Act
This Act states that dividends shall not be paid out of funds properly
included in capital accounts. TEP's 2002, 2001 2000 and 19992000 dividends were paid
from current year earnings.
MILLENNIUM ANDMillennium and UED
------------------
Millennium did not pay any dividends to UniSource Energy in 2002, 2001
or 2000.
In August 1999, Millennium paid a dividend of $10 million to UniSource Energy. UED has not paid any dividends to UniSource Energy. Millennium and
UED have no dividend restrictions.
NOTE 10. COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
TEP COMMITMENTS
Fuel Purchase and Transportation Commitments
TEP has several long-term contracts for the purchase and transportation
of coal with expiration dates from 2004 through 2017. The total amount paid
under these contracts depends on the number of tons of coal purchased and
transported. All of these contracts (i) include a price adjustment clause
that will affect the future cost of coal and (ii) require TEP to pay a take-or-
pay charge if certain minimum quantities of coal are not purchased. Our
present fuel requirements are in excess of the take-or-pay minimums. However,
sometimes TEP purchases coal from other suppliers, resulting in take-or-pay
minimum charges, but a lower overall cost of fuel. We made payments under
these contracts of $173 million in 2001, $157 million in 2000, and $152
million in 1999.
TEP entered into a Gas Procurement Agreement with Southwest Gas
Corporation effective June 1, 2001 with a primary term of five years. The
contract provides for a minimum volume obligation during the first two years
of 10 million MMBtus annually. We made payments under this contract of $28
million in 2001.WARRANTS
UniSource Energy
----------------
At December 31, 2001, we estimate our future minimum payments under these
contracts to be:
Total Contractual
Obligations
------------------------------------------
-Millions of Dollars-
2002 $ 90
2003 85
2004 82
2005 78
2006 77
------------------------------------------
Total 2002 - 2006 412
Thereafter 389
------------------------------------------
Total $ 801
==========================================
San Juan Coal Contract Amendment
In September 2000, to reduce fuel costs over the next 17 years, TEP
entered into an agreement to amend the San Juan Generating Station's coal
supply contract, replacing two surface mining operations with one underground
operation. To amend the contract, TEP is required to make a $15 million
payment in 2003. In September 2000, as a result of this scheduled payment,
TEP recorded a pre-tax $13 million Coal Contract Amendment Fee expense and a
non-current liability which equals the present value of the $15 million
payment. TEP will recognize interest expense, included in the Interest
Imputed on Losses Recorded at Present Value line item on the income
statements, and increase its liability until the payment is made in January
2003. On a net present value basis, TEP expects the fuel savings to
significantly exceed the $15 million payment that will be made in 2003.
Operating Leases
TEP has entered into operating leases, primarily for office facilities
and computer equipment, with varying terms, provisions, and expiration dates.
TEP's estimated future minimum payments under non-cancelable operating leases
at December 31, 2001 are as follows:
Operating
Leases
------------------------------------------
-Millions of Dollars-
2002 $ 2
2003 2
2004 1
2005 1
2006 1
------------------------------------------
Total 2002 - 2006 7
Thereafter 3
------------------------------------------
Total $ 10
==========================================
These future payments exclude TEP's lease of the 20MW gas turbine from
UED, as such rental expense is eliminated in UniSource Energy consolidation as
an inter-company transaction.
Environmental Regulation
The 1990 Federal Clean Air Act Amendments require reductions of SO2 and
nitrogen oxide (NOx) emissions in two phases, more complex facility permits
and other requirements. TEP is subject only to Phase II of the SO2 and NOx
emission reductions which was effective January 1, 2000. All of TEP's
generating facilities (except existing internal combustion turbines) are
affected. TEP spent approximately $2 million in 2001 and approximately $1
million annually in 2000 and 1999 and expects to spend approximately $2
million annually in 2002 and 2003 to comply with these requirements.
In 1993, TEP's generating units affected by Phase II were allocated SO2
Emission Allowances based on past operational history. Beginning in the year
2000, Phase II generating units were required to hold Emission Allowances
equal to the level of emissions in the compliance year or pay penalties and
offset excess emissions in future years. TEP had sufficient Emission
Allowances to comply with the Phase II SO2 regulations for compliance year
2001. However, due to increased energy output, TEP may have to purchase
additional Emission Allowances for future compliance years. Based on current
estimates of additional required Emission Allowances and market prices, TEP
believes that purchases of Emission Allowances will not have a material effect
on TEP.
The EPA has issued a determination that coal and oil fired electric
utility steam generating units must control their mercury emissions. Final
regulations are expected to be issued in 2004. TEP may incur additional costs
to comply with recent and future changes in federal and state environmental
laws, regulations and permit requirements at existing electric generating
facilities. Compliance with these changes may result in a reduction in
operating efficiency.
MILLENNIUM COMMITMENTS
See Note 4 for a description of Millennium's commitments.
UED COMMITMENTS
UED and Salt River Project Agricultural Improvement and Power District
(SRP) entered into a Joint Development Agreement in October 2001, to develop
two 400 MW coal-fired units at TEP's existing Springerville Station. UED and
SRP each committed $12.5 million for a total project development funding of
$25 million for professional services and other third party costs. If the
project does not proceed, the capitalized project development costs will be
immediately expensed. At December 31, 2001, capitalized project development
costs were approximately $7 million. In addition, under certain limited
circumstances associated with withdrawal from the project, UED would be
obligated to reimburse SRP for zero, 50% or 100% of SRP's previously paid
funding amounts, depending on the withdrawal circumstances.
TEP CONTINGENCIES
Springerville Generating Station Complaint
On November 13, 2001, the Grand Canyon Trust, an environmental activist
group, filed a complaint in U.S. District Court against TEP for alleged
violations of the Clean Air Act at the Springerville Generating Station. The
complaint alleges that more stringent emission standards should apply to Units
1 and 2 and that new permits and the installation of additional facilities
meeting Best Available Control Technology standards are required for the
continued operation of Units 1 and 2 in accordance with applicable law. TEP
believes the claims are without merit and will vigorously contest these
claims.
RESOLUTION OF TEP CONTINGENCIES
Income Tax Assessments
In 2000 the IRS issued an income tax assessment for the 1994, 1995 and
1996 tax years. After reviewing the impact of these items on our accrued tax
liabilities, we reversed $1 million of the deferred tax valuation allowance in
2000. See Note 12. The audit for the 1994, 1995 and 1996 period was settled
in 2001 resulting in no other adjustments to our financial statements.
In February 1998, the IRS issued an income tax assessment for the 1992
and 1993 tax years. The IRS challenged our treatment of various items
relating to a 1992 financial restructuring, including the amount of net
operating loss (NOL) and ITC generated before December 1991 that may be used
to reduce taxes in future periods. In 2000, we settled the 1992 and 1993
audits. After reviewing the impact of these items on our accrued tax
liabilities, we reversed $7 million of the deferred tax valuation allowance in
2000. See Note 12.
ACC Order on the Sierrita Contract
In September 2000, TEP reversed a $3 million reserve, resulting in $3
million of revenue, related to a dispute between TEP and Cyprus Sierrita
Corporation (now known as Phelps Dodge Sierrita, Inc.) (Sierrita) over the
proper method of calculating energy costs that TEP charged to Sierrita under
an ACC-approved contract. Sierrita dismissed its appeals to the Court of
Appeals after TEP and Sierrita entered into an amendment to their contract,
which was subsequently approved by the ACC.
Arizona Sales Tax Assessments
From 1990 to 1999 TEP contested certain sales tax assessments received
from the Arizona Department of Revenue (ADOR). The sales tax assessments
related to gross income recognized by a former TEP subsidiary from November
1985 through May 1999, as well as a component of rents that we paid on our
capital leases from August 1988 to June 1997.
In August 1999, a settlement was reached with the ADOR to settle these
issues for $48 million. The settlement agreement became effective in November
1999 when the lessors and their trustees agreed to the settlement. TEP
previously paid $25 million of the settlement amount in order to file an
appeal in the Arizona courts. Under the terms of the agreement, the remaining
$22 million was deposited into an escrow account and the funds were released
to the ADOR in five equal installments during 1999 and 2000. The settlement
did not result in additional sales tax expense because we had previously
recorded an expense for the settlement amount.
NOTE 11. WHOLESALE ACCOUNTS RECEIVABLE AND ALLOWANCES
- ------------------------------------------------------
As a participant in the western U.S. wholesale power markets, TEP is
directly and indirectly impacted by issues surrounding these markets and
market participants. During 2000 and 2001, these markets experienced
unprecedented price volatility, bankruptcies and payment defaults by several
of their largest participants, and increased attention and intervention by
regulatory agencies concerned with the outcomes of deregulation of the
electric power industry.
In early 2001, California's two largest utilities, Southern California
Edison Company (SCE) and Pacific Gas and Electric Company (PG&E), defaulted on
payment obligations owed to various energy sellers, including the California
Power Exchange (CPX) and the California Independent System Operator (CISO).
The CPX and the CISO defaulted on their payment obligations to market
participants including TEP. PG&E and the CPX filed for protection under
Chapter 11 of the U.S. Bankruptcy Code. SCE has remained out of bankruptcy
but in a weakened financial condition. SCE has publicly disclosed that on
March 1, 2002, SCE obtained financing and made payments so that they have no
material undisputed obligations that are past due or in default. These
payments included a payment to the CPX. However, TEP did not correspondingly
receive a payment from the CPX.
In October 2001, the CPX participant creditors' committee in the CPX
bankruptcy filed a proposed settlement with the FERC that would (i) return the
collateral of each CPX participant, (ii) establish a reserve for CPX costs and
expenses that would be paid for by PG&E and SCE according to a 67.5% and 32.5%
split, respectively, (iii) return CPX chargeback payments to participants, and
(iv) divide the remaining cash and future assets among the participants based
on the net amounts owed to the CPX by both parties. PG&E and SCE filed with
the FERC their objections to such settlement on the basis that the proposed
settlement was biased and could subject the two companies to duplicate claims.
During the third quarter of 2001, PG&E filed a plan of reorganization
which provides for payment of all creditors on or around January 1, 2003. The
plan requires various approvals and numerous parties have expressed opposition
to the plan. In the fourth quarter of 2001, the California Public Utilities
Commission (CPUC) approved a plan to allow SCE to obtain financing to pay all
of its creditors by the end of the first quarter of 2002.
Although TEP did not make sales directly to either SCE or PG&E in 2001 or
2000, it did sell approximately $7 million of power to the CPX and the CISO in
the first quarter of 2001 and $58 million in 2000. TEP recorded $7 million of
expense in the first quarter of 2001 and $9 million in the fourth quarter of
2000 to reserve for uncollectible amounts related to these sales. The $16
million aggregate allowance reflected a 100% reserve on all amounts unpaid at
March 31, 2001. Due to the recent (a) stabilization of the power markets, (b)
rate increases achieved by PG&E and SCE, (c) settlements made by California
utilities with various power providers, (d) the CPUC's approval of SCE's
financing to pay its creditors, and (e) data in filings of FERC refund
hearings, TEP believes that it is probable that it will collect at least 50%
of the outstanding receivables from the CPX and the CISO. As a result, in the
fourth quarter of 2001 we reversed $8 million of the $16 million reserve.
Beginning in January 2001, the California Department of Water Resources
(CDWR) was authorized to make energy purchases on behalf of California
customers. TEP sold $16 million of power to the CDWR in 2001, all of which
has been paid according to terms.
Also during 2000, the FERC established certain soft caps on prices for
power sold at the CPX. The caps did not have a significant impact on sales to
the CPX during the first three quarters of 2000. However, during the fourth
quarter of 2000 and the first quarter of 2001, prices for power in the day-
ahead and real-time markets frequently exceeded the caps established by FERC.
During March 2001, the FERC issued two orders requiring certain generators
that sold power to California in January and February 2001 to either refund
amounts over specified market prices or provide further data to defend their
transactions. TEP was not named in either of these orders.
In June 2001, a FERC administrative law judge (ALJ) facilitated a
voluntary settlement between the state of California and numerous power
generators. California claims it was overcharged up to $9 billion for
wholesale power purchases since May 2000 and is seeking a refund for "unlawful
profits." "Unlawful profits" has not been defined. Representatives from over
100 parties and participants in the western power market, including the state
of California and power generators, negotiated for two weeks but failed to
reach an agreement. In July 2001, based on the ALJ's recommendations, the
FERC ordered hearings to determine refunds/offsets applicable to wholesale
sales into the CISO's spot markets for the period from October 2, 2000 to June
20, 2001. The order established the methodology that will be used to
calculate the amount of refunds. This methodology will likely result in
refunds substantially lower than the $9 billion claimed by California.
We are not able to predict the length and outcome of the FERC hearings
and the outcome of any subsequent lawsuits and appeals that might be filed.
As a participant in the June 2001 refund proceedings, TEP will be subject to
any final refund orders. TEP does not expect its refund liability, if any, to
have a significant impact on the financial statements.
On December 2, 2001, Enron Corporation and certain of its affiliates
(Enron) filed for protection under Chapter 11 of the U.S. Bankruptcy Code. At
December 31, 2001, TEP's net receivable from Enron was $0.8 million for sales
made to Enron in November and December 2001. We reserved $0.4 million in
December 2001, as we believe it is probable that we will collect 50% of this
net receivable.
There are several other outstanding legal issues, complaints, and
lawsuits concerning the California energy crisis related to the FERC,
wholesale power suppliers, SCE, PG&E, the CPX and the CISO, and concerning
Enron. We cannot predict the outcome of these issues or lawsuits. We
believe, however, that we are adequately reserved for our transactions with
the CPX, the CISO and Enron. Accounts receivable from Electric Wholesale
Sales, net of allowances, totaled $70 million at December 31, 2001 and $64
million at December 31, 2000. These amounts are included in Accounts
Receivable on the balance sheet. All balances, except as described above for
the CPX, the CISO and Enron, have been collected in full as of the date of
this filing.
NOTE 12. INCOME TAXES
- ----------------------
Deferred tax assets (liabilities) consist of the following:
UniSource Energy TEP
------------------ -----------------
December 31, December 31,
2001 2000 2001 2000
- -------------------------------------------------------------------------------
-Millions of Dollars-
Gross Deferred Income Tax Liabilities
Electric Plant - Net $(398) $(412) $(398) $(412)
Income Taxes Recoverable Through
Future Revenues Regulatory Asset (25) (29) (25) (29)
Transition Recovery Asset (131) (141) (131) (141)
Other (59) (53) (25) (26)
- -------------------------------------------------------------------------------
Gross Deferred Income Tax
Liability (613) (635) (579) (608)
- -------------------------------------------------------------------------------
Gross Deferred Income Tax Assets
Capital Lease Obligations 346 351 346 351
Net Operating Loss Carryforwards 46 98 34 91
Investment Tax Credit Carryforwards 11 20 11 20
Alternative Minimum Tax 83 46 69 33
Other 112 104 84 87
- -------------------------------------------------------------------------------
Gross Deferred Income Tax Asset 598 619 544 582
Deferred Tax Assets Valuation
Allowance (17) (17) (17) (17)
- -------------------------------------------------------------------------------
Net Deferred Income Tax
Liability $ (32) $ (33) $ (52) $ (43)
===============================================================================
The net deferred income tax liability is included in the balance sheets
in the following accounts:
UniSource Energy TEP
------------------ -----------------
December 31, December 31,
2001 2000 2001 2000
- -------------------------------------------------------------------------------
-Millions of Dollars-
Deferred Income Taxes-Current $ 11 $ 18 $ 5 $ 11
Deferred Income Taxes-Noncurrent (43) (51) (57) (54)
- -------------------------------------------------------------------------------
Net Deferred Income Tax Liability $ (32) $ (33) $ (52) $ (43)
===============================================================================
We record a Deferred Tax Assets Valuation Allowance for the amount of
Deferred Tax Assets that we do not believe we can use to reduce income taxes
on a future tax return. In 2001, there was no change in the Deferred Tax
Assets Valuation Allowance. In 2000, the Deferred Tax Assets Valuation
Allowance decreased $8 million due primarily to the improved likelihood of
favorable resolution of tax items. In 1999, the Deferred Tax Assets Valuation
Allowance decreased $32 million due primarily to recognized ITC Carryforward
included in Extraordinary Income and a reversal of a tax reserve.
Income tax expense (benefit) included in the income statements consists
of the following:
UniSource Energy TEP
-------------------- ---------------------
Years Ended December 31,
2001 2000 1999 2001 2000 1999
- -------------------------------------------------------------------------------
-Millions of Dollars-
Current Tax Expense - State $ 11 $ 4 $ 3 $ 11 $ 6 $ 4
- -------------------------------------------------------------------------------
Deferred Tax Expense
Federal 40 20 34 47 29 27
State (4) (1) 5 (2) - 2
- -------------------------------------------------------------------------------
Total 36 19 39 45 29 29
- -------------------------------------------------------------------------------
Reduction in Valuation
Allowance - Benefit - (8) (9) - (8) (9)
Investment Tax Credit
Amortization - - (2) - - (2)
- -------------------------------------------------------------------------------
Total Federal and State Income
Tax Expense Before Extraordinary
Item and Cumulative Effect of
Accounting Change 47 15 31 56 27 22
- -------------------------------------------------------------------------------
Extraordinary Income
Deferred Tax Benefit
Federal - - (5) - - (5)
State - - (1) - - (1)
Reduction in Valuation
Allowance - ITC
Carryforward Benefit - - (23) - - (23)
Benefit from Recognition of
Deferred ITC - - (8) - - (8)
- -------------------------------------------------------------------------------
Total Benefit Included in
Extraordinary Income - - (37) - - (37)
- -------------------------------------------------------------------------------
Total Federal and State Income
Tax Expense (Benefit)
Including Extraordinary
Income and Cumulative Effect of
Accounting Change $ 47 $ 15 $ (6) $ 56 $ 27 $(15)
===============================================================================
The differences between the income tax expense and the amount obtained by
multiplying pre-tax income by the U.S. statutory federal income tax rate of
35% are as follows:
UniSource Energy TEP
-------------------- ---------------------
Years Ended December 31,
2001 2000 1999 2001 2000 1999
- -------------------------------------------------------------------------------
-Millions of Dollars-
Federal Income Tax Expense
at Statutory Rate $ 38 $ 20 $ 31 $ 46 $ 27 $ 25
State Income Tax Expense,
Net of Federal Deduction 5 3 4 6 4 3
Depreciation Differences
(Flow Through Basis) 5 5 5 5 5 5
Investment Tax Credit
Amortization - - (2) - - (2)
Reduction in Valuation
Allowance - Benefit - (8) (9) - (8) (9)
Foreign Operations of
Millennium Energy
Businesses (1) (3) 3 - - -
Other - (2) (1) (1) (1) -
- -------------------------------------------------------------------------------
Total Federal and State Income
Tax Expense Before
Extraordinary Item and
Cumulative Effect of
Accounting Change $ 47 $ 15 $ 31 $ 56 $ 27 $ 22
===============================================================================
At December 31, 2001, UniSource Energy and TEP had, for federal income
tax purposes:
- $142 million of NOL carryforwards expiring in 2006 through 2009;
- $11 million of unused ITC expiring in 2003 through 2005; and
- $83 million of Alternative Minimum Tax credit which will carry forward
to future years.
Due to the financial restructuring, a change in TEP's ownership occurred
for tax purposes in December 1991. This change limits our use of the NOL and
ITC generated before 1992 under the tax code. At December 31, 2001, we had
approximately $136 million of NOL and $11 million of ITC subject to the pre-
1992 limitation and $6 million of NOL not subject to the limitation. Because
of the valuation allowance amounts recorded, we do not expect these annual
limitations to have a material adverse impact on the financial statements.
NOTE 13. EMPLOYEE BENEFITS PLANS
- ---------------------------------
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
TEP maintains noncontributory, defined benefit pension plans for all
regular employees. Benefits are based on years of service and the employee's
average compensation. TEP makes annual contributions to the plans sufficient
to meet the minimum funding requirements set forth by the Employee Retirement
Income Security Act of 1974, plus such additional tax deductible amounts as
may be advisable. TEP provides supplemental retirement benefits to employees
whose benefits are limited by IRS benefit or compensation limitations.
TEP also provides health care and life insurance benefits for retirees.
All regular employees may become eligible for these benefits if they reach
retirement age while working for TEP. The ACC allows TEP to recover through
rates postretirement costs only as benefit payments are made to or on behalf
of retirees. The postretirement benefits are currently funded entirely on a
pay-as-you-go basis. Under current accounting guidance, TEP cannot record a
regulatory asset for the excess of expense calculated per Statement of
Financial Accounting Standards No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions, over actual benefit payments.
We amended our other postretirement benefit plan as of June 1, 2001,
eliminating post-65 medical benefits for salaried employees retiring after
January 1, 2002 and capping Medicare supplement payments for salaried retirees
under age 65. This amendment required us to recalculate benefits related to
participants' past service. We are amortizing the change in the benefit cost
from this plan amendment on a straight-line basis over 10 years.
The actuarial present values of the pension benefit obligations were
measured at December 1 in 2001 and October 1 in 2000. The measurement date
for our other postretirement benefit plan was December 1 in 2001 and December
31 in 2000. We changed the measurement dates to be the same and this change
had no effect on 2001 expense. The change in benefit obligation and plan
assets and reconciliation of the funded status are as follows:
Other Postretirement
Pension Benefits Benefits
---------------- --------------------
2001 2000 2001 2000
- -------------------------------------------------------------------------------
-Millions of Dollars-
Change in Benefit Obligation
Benefit Obligation at
Beginning of Year $ 102 $ 89 $ 64 $ 34
Actuarial (Gain) Loss 9 - 1 27
Interest Cost 8 7 4 3
Service Cost 4 4 2 2
Benefits Paid (6) (5) (2) (2)
Plan Change - 7 (10) -
-------------------------------------------
Benefit Obligation at
End of Year 117 102 59 64
-------------------------------------------
Change in Plan Assets
Fair Value of Plan Assets
at Beginning of Year 137 112 - -
Actual Return on Plan Assets (13) 27 - -
Benefits Paid (6) (5) (2) (2)
Employer Contributions 2 3 2 2
-------------------------------------------
Fair Value of Plan Assets
at End of Year 120 137 - -
-------------------------------------------
Reconciliation of Funded Status
to Balance Sheet
Funded Status (Difference
between Benefit Obligation
and Fair Value of Plan Assets) 3 35 (59) (64)
Unrecognized Net (Gain) Loss (1) (37) 26 27
Unrecognized Prior Service Cost 16 18 - -
Unrecognized Transition (Asset)
Obligation - - - 10
----------------------------------------------
Net Amount Recognized in
the Balance Sheets $ 18 $ 16 $ (33) $ (27)
==============================================
Amounts Recognized in the
Balance Sheets Consist of:
Prepaid Pension Costs Included
in Other Assets $ 21 $ 18 $ - $ -
Accrued Benefit Liability
Included in Other Liabilities (3) (2) (33) (27)
----------------------------------------------
Net Amount Recognized $ 18 $ 16 $ (33) $ (27)
==============================================
Benefit Obligation and Fair Value of Plan Assets
for Plans with Benefit Obligations in Excess of
Plan Assets:
Benefit Obligation at
End of Year $ 61 $ 6 $ 59 $ 64
Fair Value of Plan
Assets at End of Year $ 51 $ - $ - $ -
- -------------------------------------------------------------------------------
We recorded a transition asset or obligation when we adopted accounting
standards requiring recognition of pension and other postretirement benefit
obligations and costs in the financial statements. The transition asset or
obligation equaled the difference between the fair value of plan assets and
the accumulated benefit obligation. We amortized the transition asset on the
pension plans over a 15-year period ending December 31, 2001. The transition
obligation on the postretirement benefit plan was being amortized over 20
years. The change in the benefit cost from the 2001 plan amendment eliminated
the remaining transition obligation.
The components of net periodic benefit costs are as follows:
Pension Benefits Years Ended December 31,
2001 2000 1999
- -------------------------------------------------------------------------------
-Millions of Dollars-
Components of Net Pension Cost
Service Cost of Benefits Earned During Period $ 4 $ 4 $ 5
Interest Cost on Projected Pension
Benefit Obligation 7 7 7
Expected Return on Plan Assets (12) (11) (9)
Amortization of Unrecognized Prior Service Cost 2 2 1
Recognized Actuarial (Gain) Loss (2) (1) 1
Transition Asset Recognition - - -
- -------------------------------------------------------------------------------
Net Periodic Pension Cost (Benefit) $ (1) $ 1 $ 5
===============================================================================
Actuarial Assumptions: 2001 2000 1999
- -------------------------------------------------------------------------------
Discount Rate - Funding Status 7.3% 7.8% 7.8%
Average Compensation Increase 4.0 4.0 4.0
Expected Long-Term Rate of Return on Plan Assets 9.0 9.0 9.0
- -------------------------------------------------------------------------------
Other Postretirement Benefits Years Ended December 31,
2001 2000 1999
- -------------------------------------------------------------------------------
-Millions of Dollars-
Components of Net Postretirement Benefit Cost
Service Cost of Benefits Earned During Period $ 2 $ 1 $ 1
Interest Cost on Projected Benefit Obligation 4 3 2
Amortization of Unrecognized Transition
Obligation - 1 1
Recognized Actuarial Loss 2 1 -
- -------------------------------------------------------------------------------
Net Periodic Postretirement Benefit Cost $ 8 $ 6 $ 4
===============================================================================
The accumulated postretirement benefit obligation was determined using a
discount rate of 7.25% for 2001 and 7.5% for 2000. Assumed health care cost
trend rates have a significant effect on the amounts reported for health care
plans. The health care cost trend rates were assumed to be 8.5% for 2002,
8.0% in 2003, 7.5% in 2004, then gradually declining to 5.0% in 2009 and
thereafter. A one-percentage-point change in assumed health care cost trend
rates would have the following effects on the December 31, 2001 amounts:
One-Percentage- One-Percentage-
Point Increase Point Decrease
- -------------------------------------------------------------------------------
-Millions of Dollars-
Effect on Total of Service and Interest
Cost Components $ 1 $ (1)
Effect on Postretirement Benefit
Obligation $ 7 $ (6)
- -------------------------------------------------------------------------------
DEFINED CONTRIBUTION PLANS
All regular employees may contribute a percentage of their pre-tax
compensation, subject to certain limitations, in TEP's voluntary, defined
contribution 401(k) plans. TEP contributes cash to the account of each
participant based on each participant's contributions not exceeding 4.5% of
the participant's compensation. Participants direct the investment of
contributions to certain funds in their account. TEP incurred approximately
$3 million in expense related to these plans in each of 2001 and 2000, and $2
million in 1999.
STOCK OPTION PLANS
On May 20, 1994, the Shareholders approved two stock option plans, the
1994 Outside Director Stock Option Plan (1994 Directors' Plan) and the 1994
Omnibus Stock and Incentive Plan (1994 Omnibus Plan).
The 1994 Directors' Plan provided for the annual grant of 1,200 non-
qualified stock options to each eligible director at an exercise price equal
to the market price of the common stock at the grant date, beginning January
3, 1995. These options vest over three years, become exercisable in one-third
increments on each anniversary date of the grant and expire on the tenth
anniversary. In December 1998, the Board of Directors approved an increase in
the annual grant of non-qualified stock options to 2,000 beginning January
1999.
The 1994 Omnibus Plan allows the Compensation Committee, a committee of
non-employee directors, to grant the following types of awards to each
eligible employee: stock options; stock appreciation rights; restricted stock;
stock units; performance units; performance shares; and dividend equivalents.
The total number of shares of UniSource Energy Common Stock that may be
awarded under the Omnibus Plan cannot exceed 4.1 million.
The Compensation Committee granted stock options to key employees during
2001, 2000, and 1999 and to most employees in 1999. These stock options were
granted at exercise prices equal to the market price of the common stock at
the grant date. These options vest over three years, become exercisable in
one-third increments on each anniversary date of the grant and expire on the
tenth anniversary.
A summary of the activity of the 1994 Directors' Plan and 1994 Omnibus
Plan is as follows:
2001 2000 1999
- -------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
- -------------------------------------------------------------------------------
Options Outstanding,
Beginning of Year 1,918,077 $14.36 1,390,033 $14.01 888,459 $15.37
Granted 410,000 $17.96 601,000 $15.14 626,243 $12.31
Exercised (177,602) $14.56 (7,749) $12.88 - $ -
Forfeited (75,241) $14.60 (65,207) $14.10 (124,669) $15.18
---------- ---------- ----------
Options Outstanding,
End of Year 2,075,234 $15.05 1,918,077 $14.36 1,390,033 $14.01
========== ========== ==========
Options Exercisable,
End of Year 1,081,162 $14.38 856,656 $14.67 610,095 $15.35
Option Price Range of Options Outstanding at December 31, 2001: $11.00
to $18.84
Weighted Average Remaining Contractual Life at December 31, 2001: 7.24
- -------------------------------------------------------------------------------
We apply Accounting Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees, in accounting for our stock option plans. Accordingly,
we have not recognized any compensation cost for the plans. We have also
adopted the disclosure-only provisions of Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based Compensation (FAS 123). Had our
compensation costs for the stock option plans been determined based on the
fair value at the grant date for awards in 2001, 2000 and 1999 consistent with
the provisions of FAS 123, net income and net income per average share would
have been reduced to the pro forma amounts indicated below:
Years Ended December 31,
2001 2000 1999
-------------------------------
-Thousands of Dollars-
(except per share data)
Net Income - As Reported $61,345 $41,891 $79,107
Pro Forma $60,324 $41,097 $78,621
Basic Earnings Per Share - As Reported $1.84 $1.29 $2.45
Pro Forma $1.81 $1.27 $2.43
Diluted Earnings Per Share - As Reported $1.80 $1.27 $2.43
Pro Forma $1.77 $1.25 $2.41
The fair value of each stock option grant is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions:
2001 2000 1999
-------------------------------
Expected life (years) 5 5 5
Interest rate 4.70% 6.10% 5.65%
Volatility 23.93% 23.04% 22.91%
Dividend yield 2.08% 2.14% 0.69%
NOTE 14. UNISOURCE ENERGY EARNINGS PER SHARE (EPS)
- ---------------------------------------------------
Basic EPS is computed by dividing net income by the weighted average
number of common shares outstanding during the period. Diluted EPS assumes
that proceeds from the hypothetical exercise of stock options and other stock-
based awards are used to repurchase outstanding shares of stock at the average
fair market price during the reporting period. The following table shows the
amounts used in computing earnings per share and the effects of potential
dilutive common stock on the weighted average number of shares.
Years Ended December 31,
2001 2000 1999
-----------------------------------------------------------------------
-Thousands of Dollars-
Basic Earnings Per Share: (except per share data)
Numerator:
Income Before Extraordinary Item
and Cumulative Effect of Accounting
Change $60,875 $41,891 $56,510
Extraordinary Item - - 22,597
Cumulative Effect of Accounting Change 470 - -
-----------------------------------------------------------------------
Net Income 61,345 41,891 79,107
=======================================================================
Denominator:
Average Shares of Common Stock
Outstanding 33,399 32,445 32,321
=======================================================================
Basic Earnings Per Share:
Before Extraordinary Item and
Cumulative Effect of Accounting
Change $1.83 $1.29 $1.75
Extraordinary Item - - 0.70
Cumulative Effect of Accounting Change 0.01 - -
-----------------------------------------------------------------------
Net Income $1.84 $1.29 $2.45
=======================================================================
Diluted Earnings Per Share:
Numerator:
Income Before Extraordinary Item
and Cumulative Effect of Accounting
Change $60,875 $41,891 $56,510
Extraordinary Item - - 22,597
Cumulative Effect of Accounting Change 470 - -
-----------------------------------------------------------------------
Net Income $61,345 $41,891 $79,107
=======================================================================
Denominator:
Average Shares of Common Stock
Outstanding 33,399 32,445 32,321
Effect of Dilutive Securities:
Warrants 143 - -
Options and Stock Issuable Under
Employee Benefit Plans 625 434 257
-----------------------------------------------------------------------
Total Shares 34,167 32,879 32,578
=======================================================================
Diluted Earnings Per Share:
Before Extraordinary Item and
Cumulative Effect of Accounting
Change $1.79 $1.27 $1.74
Extraordinary Item - - 0.69
Cumulative Effect of Accounting Change 0.01 - -
-----------------------------------------------------------------------
Net Income $1.80 $1.27 $2.43
=======================================================================
Options to purchase an average of 120,000 shares of common stock at
$16.69 to $18.84 per share were outstanding during the year 2001 but were not
included in the computation of diluted EPS because the options' exercise price
was greater than the average market price of the common stock.
At December 31, 2001, UniSource Energy had no outstanding warrants. There
were 4.6 million warrants outstanding that were exercisable into TEP common
stock. See Note 15. However, the dilutive effect is the same as it would be
if the warrants were exercisable into UniSource Energy Common Stock.
NOTE 15. WARRANTS
- ------------------
UNISOURCE ENERGY
At December 31, 2001, UniSource Energy had no outstanding
warrants. In December 2000, 791,966 UniSource Energy Warrants, that were
scheduled to expire on December 15, 2000, were exercised resulting in a $13
million increase in common stock equity. The remaining 700,445 warrants
expired. The
exercised warrants allowed the holder to purchase one share of UniSource
Energy Common Stock for $16.00. As a result, 791,966 shares of stock were
issued.expired unexercised.
TEP
---
At December 31, 2001, 4.6 million of2002, TEP Warrants, which expire onhad no outstanding warrants. On December 15,
2002, were outstanding. The4.6 million TEP Warrants entitle the holder of
five warrants to purchase one share of TEP common stock for $16.00. If all
TEP Warrants were exercised, approximately 900,000 additional shares of TEP
common stock would be issued. The TEP common stock that would be issued upon
the exercise of TEP Warrants cannot be converted into UniSource Energy Common
Stock.expired unexercised. UniSource Energy is the
primary holder of the common stock of TEP and TEP common stock is not
publicly traded.
NOTE 16. UNISOURCE ENERGY SHAREHOLDER RIGHTS PLAN
- --------------------------------------------------
In March 1999, UniSource Energy adopted a Shareholder Rights Plan. As
of April 1, 1999, each Common Stock shareholder receives one Right for each
share held. Each Right initially allows shareholders to purchase UniSource
Energy's Series X Preferred Stock at a specified purchase price. However,
the Rights are exercisable only if a person or group (the "acquirer")
acquires or commences a tender offer to acquire 15% or more of UniSource
Energy Common Stock. Each Right would entitle the holder (except the
acquirer) to purchase a number of shares of UniSource Energy Common or
Preferred Stock (or, in the case of a merger of UniSource Energy into another
person or group, common stock of the acquiring person) having a fair market
value equal to twice the specified purchase price. At any time until any
person or group has acquired 15% or more of the Common Stock, UniSource
Energy may redeem the Rights at a redemption price of $0.001 per Right. The
Rights trade automatically with the Common Stock when it is bought and sold.
The Rights expire on March 31, 2009.
UNISOURCE ENERGY POTENTIAL COMMON STOCK ISSUE
On February 21, 2003, we filed a "shelf" registration statement on Form
S-3 to issue up to 4 million shares of UniSource Energy Common Stock.
NOTE 10. COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
TEP COMMITMENTS
Fuel Purchase and Transportation Commitments
--------------------------------------------
TEP has several long-term contracts for the purchase and transportation
of coal with expiration dates from 2004 through 2017. The total amount paid
under these contracts depends on the number of tons of coal purchased and
transported. All of these contracts (i) include a price adjustment clause
that will affect the future cost of coal and (ii) require TEP to pay a take-
or-pay charge if certain minimum quantities of coal are not purchased and/or
transported. TEP's present fuel requirements are in excess of the take-or-
pay minimums. However, sometimes TEP has purchased coal from other suppliers,
resulting in take-or-pay minimum charges, but a lower overall cost of fuel.
TEP made payments under these contracts of $161 million in 2002, $173 million
in 2001, and $157 million in 2000.
TEP entered into a Gas Procurement Agreement with Southwest Gas
Corporation effective June 1, 2001 with a primary term of five years. The
contract provides for a minimum volume obligation during the first two years
of 10 million MMBtus annually. TEP made payments under this contract of $33
million in 2002 and $28 million in 2001.
At December 31, 2002, TEP estimates its future minimum payments under
these contracts to be:
Total Contractual
Obligations
--------------------------------------
-Millions of Dollars-
2003 $ 81
2004 78
2005 75
2006 72
2007 72
--------------------------------------
Total 2003 - 2007 378
Thereafter 278
--------------------------------------
Total $ 656
======================================
Irvington Coal Contract Termination
-----------------------------------
In the third quarter of 2002, TEP terminated a coal supply agreement for
the Irvington Generating Station. As a result, TEP recorded a pre-tax charge
of $11.3 million and made an $11.3 million payment in the third quarter of
2002. The additional expense was mitigated by TEP not being required to make
a take-or-pay penalty payment of approximately $3.5 million for the year 2002
and subsequent years.
San Juan Coal Contract Amendment
--------------------------------
In September 2000, to reduce fuel costs over the next 17 years, TEP
terminated the San Juan Generating Station's coal supply contract and entered
into a new coal supply contract, replacing two surface mining operations with
one underground operation. To terminate the contract, TEP was required to
make a $15 million payment in January 2003. In September 2000, as a result
of this scheduled payment, TEP recorded a pre-tax $13 million Coal Contract
Amendment Fee expense and a non-current liability which equaled the present
value of the $15 million payment. TEP recognized interest expense, included
in the Interest Imputed on Losses Recorded at Present Value line item on the
income statements, and increased its liability until the payment was made in
December 2002. On a net present value basis, TEP expects the fuel savings to
significantly exceed the $15 million payment over the original term of the
contract.
Operating Leases
----------------
TEP and Millennium have entered into operating leases, primarily for
office facilities and computer equipment, with varying terms, provisions, and
expiration dates. UniSource Energy's consolidated operating lease expense
was $3 million for each of 2002, 2001 and 2000. TEP's operating lease
expense was $2 million for each of 2002, 2001 and 2000. UniSource Energy and
TEP's estimated future minimum payments under non-cancelable operating leases
at December 31, 2002 are as follows:
UniSource
Energy
Consolidated TEP
-------------------------------------------
-Millions of Dollars-
2003 $ 3 $ 2
2004 2 1
2005 1 1
2006 1 1
2007 1 1
-------------------------------------------
Total 2003 - 2007 8 6
Thereafter 3 3
-------------------------------------------
Total $ 11 $ 9
===========================================
Environmental Regulation
------------------------
The 1990 Federal Clean Air Act Amendments require reductions of SO2
and nitrogen oxide (NOx) emissions in two phases, more complex facility
permits and other requirements. TEP is subject only to Phase II of the SO2
and NOx emission reductions which was effective January 1, 2000. All of
TEP's generating facilities (except existing internal combustion turbines)
are affected. TEP spent approximately $2.5 million in 2002, approximately $2
million in 2001 and approximately $1 million in 2000 and expects to spend
approximately $2 million annually in 2003 and 2004 to comply with these
requirements.
In 1993, TEP's generating units affected by Phase II were allocated
SO2 Emission Allowances based on past operational history. Beginning in
the year 2000, Phase II generating units were required to hold Emission
Allowances equal to the level of emissions in the compliance year or pay
penalties and offset excess emissions in future years. TEP had sufficient
Emission Allowances to comply with the Phase II SO2 regulations for
compliance year 2002. However, due to increased energy output, TEP may have
to purchase additional Emission Allowances for future compliance years.
Based on current estimates of additional required Emission Allowances and
market prices, TEP believes that purchases of Emission Allowances will not
have a material effect on TEP.
The EPA has issued a determination that coal and oil-fired electric
utility steam generating units must control their mercury emissions. Final
regulations are expected to be issued in 2004. TEP may incur additional
costs to comply with recent and future changes in federal and state
environmental laws, regulations and permit requirements at existing electric
generating facilities. Compliance with these changes may result in a
reduction in operating efficiency.
MILLENNIUM COMMITMENTS AND CONTINGENCY
See Note 4 for a description of Millennium's commitments and
contingency.
UED COMMITMENTS
UED and Salt River Project Agricultural Improvement and Power District
(SRP) entered into a Joint Development Agreement in October 2001 to develop
two 400 MW coal-fired units at TEP's existing Springerville Station. As a
result of recent developments, UED and SRP are modifying the Joint
Development Agreement to provide for the purchase by SRP of a specified
amount of power from Unit 3 and an option for SRP to own Unit 4. UED and SRP
each committed project development funding for professional services and
other third party costs. As of December 31, 2002, SRP met its funding
commitment for the project. Tri-State Generation and Transmission
Association, Inc. (Tri-State) has agreed to purchase the remaining power from
Unit 3. Tri-State and UED signed a Development Cost Agreement in January
2003 to each share 50% of the remaining development costs of Unit 3 effective
from November 6, 2002 until financial closing. At December 31, 2002,
capitalized project development costs on UED's balance sheet were
approximately $22.4 million. Management believes it is probable that UED
will proceed with this project. If the project does not proceed, the
capitalized project development costs will be immediately expensed.
TEP CONTINGENCIES
Springerville Generating Station Complaint
------------------------------------------
Environmental activist groups have expressed concerns regarding the
construction of any new units at the Springerville Station. In January 2003,
environmental activist groups appealed an ACC Order affirming the ACC's
approval of the expansion at Springerville Station to the Superior Court of
the State of Arizona. Additionally, in November 2001, the Grand Canyon Trust
(GCT), an environmental activist group filed a complaint in U.S. District Court
against TEP for alleged violations of the Clean Air Act at the Springerville
Generating Station. The complaint alleged that more stringent emission
standards should apply to Units 1 and 2 and that new permits and the
installation of additional facilities meeting Best Available Control Technology
standards are required for the continued operation of Units 1 and 2 in
accordance with applicable law. TEP believes the claims by the GCT are without
merit and will vigorously contest them.
In 2002, the U.S. District Court granted TEP's motion for
summary judgment on one of the primary issues in the case: whether TEP
commenced construction within 18 months and/or by March 19, 1979, after the
original 1977 air permit covering Units 1 and 2 was issued. The Court found
that TEP had commenced construction of the Springerville Generating Station in
the time periods required by the original permits. There were two remaining
allegations: that (a) TEP discontinued construction for a period
of 18 months or longer and did not complete construction in a reasonable
period of time, and (b) TEP did not commence construction, for purposes of
New Source Performance Standard applicability, by September 18, 1978.
On March 4, 2003, the U.S. District Court determined that the GCT had not
commenced the case on a timely basis and dismissed the case.
Litigation Related to San Juan Coal Company
-------------------------------------------
On July 30, 2002, Dugan Production Corp. (Dugan) filed a lawsuit against
the San Juan Coal Company, the coal supplier to the San Juan Generating
Station (San Juan). TEP owns 50% of San Juan Units 1 and 2, which equates to
19.8% of San Juan in total. The San Juan Coal Company, through leases with
the federal government and the State of New Mexico, owns coal interests with
respect to an underground mine. Dugan, through leases with the federal
government, the State of New Mexico and certain private parties, claims to
own certain oil and gas interests in portions of the land used for the
underground mine. Dugan alleges that San Juan Coal Company's underground
coal mining operations have or will interfere with Dugan's gas production and
will result in the dissipation of natural gas that it otherwise would be
entitled to recover. Dugan seeks a declaration by the court that the rights
under its leases are senior and superior to the rights of the San Juan Coal
Company and seeks to enjoin the underground mining of coal from a portion of
the land used for the underground mine as described above. Dugan also seeks
monetary damages.
The San Juan Coal Company has informed Public Service Company of New
Mexico (PNM) that it intends to strongly dispute the litigation. TEP cannot
predict the ultimate outcome of this litigation, or whether it will adversely
affect the amount of coal available or cost of coal to San Juan. TEP does not
expect resolution of this litigation to be material to TEP as a 19.8% owner
of San Juan.
Litigation Related to San Juan Generating Station
-------------------------------------------------
On May 16, 2002, the Grand Canyon Trust and the Sierra Club filed a
citizen lawsuit under the Clean Air Act in federal district court in New
Mexico against PNM as operator of San Juan. The lawsuit, which alleges two
violations of the Clean Air Act and related regulations and permits, seeks
penalties as well as injunctive and declaratory relief and is presently
scheduled for trial in June 2003. Based on its investigation to date, PNM
has stated that it firmly believes that the allegations are without merit,
and vigorously disputes the allegations. Only one of those allegations
relates to a unit in which TEP owns an interest. While we are unable to
predict the ultimate outcome of the lawsuit, we do not believe the outcome
will be material to TEP.
Environmental Reclamation
-------------------------
TEP pays on-going reclamation costs at each of its remote generating
stations, and it is reasonably possible that we may have to pay a portion of
final reclamation costs as the coal companies from which the remote
generating stations purchase coal undertake final reclamation of their mines.
As amounts become known and probable, we will record a liability for final
reclamation.
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain
subsidiaries, including TEP, enter into various agreements providing
financial or performance assurance to third parties on behalf of certain
subsidiaries. These agreements are entered into primarily to support or
enhance the creditworthiness otherwise attributed to a subsidiary on a stand-
alone basis, thereby facilitating the extension of sufficient credit to
accomplish the subsidiaries' intended commercial purposes. The most
significant of these guarantees supports up to approximately $3.5 million in
commodity-related payments for MEG at December 31, 2002. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheets.
In addition, UniSource Energy and its subsidiaries have indemnified the
purchasers of interests in certain investments from additional taxes due for
years prior to the sale. The terms of the indemnifications provide for no
limitation on potential future payments; however, we believe that we have
abided by all tax laws and paid all tax obligations. We have not made any
payments under the terms of these indemnifications to date.
We believe that the likelihood UniSource Energy or TEP would be required
to perform or otherwise incur any significant losses associated with any of
these guarantees is remote.
RESOLUTION OF TEP CONTINGENCIES
Income Tax Assessments
----------------------
In 2002, the IRS audit for 1997-2000 was settled, and after reviewing
the impact of the audit findings as well as the effect of tax positions
established in relation to future tax years, TEP reversed $1 million of the
deferred tax valuation allowance. See Note 12.
In 2000, the IRS issued an income tax assessment for the 1994, 1995 and
1996 tax years. After reviewing the impact of these items on TEP's accrued
tax liabilities, TEP reversed $1 million of the deferred tax valuation
allowance in 2000. See Note 12. The audit for such period was settled in
2001, and after reviewing the impact of the final assessment on TEP's accrued
tax liabilities and the potential for assessments related to later tax years,
no further adjustments to the deferred tax valuation allowance were deemed
necessary in 2001.
In February 1998, the IRS issued an income tax assessment for the 1992
and 1993 tax years. The IRS challenged TEP's treatment of various items
relating to a 1992 financial restructuring, including the amount of net
operating loss (NOL) and investment tax credit (ITC) generated before
December 1991 that may be used to reduce taxes in future periods. In 2000,
TEP settled the 1992 and 1993 audits. After reviewing the impact of these
items on its accrued tax liabilities, TEP reversed $7 million of the deferred
tax valuation allowance in 2000. See Note 12.
ACC Order on the Sierrita Contract
----------------------------------
In September 2000, TEP reversed a $3 million reserve, resulting in $3
million of revenue, related to a dispute between TEP and Cyprus Sierrita
Corporation (now known as Phelps Dodge Sierrita, Inc.) (Sierrita) over the
proper method of calculating energy costs that TEP charged to Sierrita under
an ACC-approved contract. Sierrita dismissed its appeals to the Court of
Appeals after TEP and Sierrita entered into an amendment to their contract,
which was subsequently approved by the ACC.
NOTE 11. Wholesale Accounts Receivable and Allowances
- ------------------------------------------------------
At December 31, 2002 and December 31, 2001, TEP's Accounts Receivable on
the balance sheet is net of an $8.4 million allowance for uncollectible
receivables related to 2000 and 2001 sales to the California Power Exchange
(CPX), the California Independent System Operator (CISO) and Enron Corp. and
certain of its affiliates (Enron). The receivable from the CPX and the CISO
is $16 million and the receivable from Enron is $0.8 million. This allowance
reflects a 50% reserve on amounts unpaid from the CPX, the CISO and Enron.
The reserve for the receivable from Enron was recorded in 2001.
TEP's collection shortfall from the CPX and CISO was approximately $9
million for sales made in 2000 and $7 million for sales made in 2001. We
recorded an allowance for doubtful accounts for the full amount of these
uncollected amounts in the fourth quarter of 2000 and the first quarter of
2001, totaling $16 million. In the fourth quarter of 2001, we decreased the
reserve by $8 million, or 50%, of the outstanding receivable because the
following events which occurred in late 2001 caused us to believe that it is
probable that TEP will collect at least 50% of this aggregate outstanding net
receivable: (a) the stabilization of the power markets, (b) rate increases
achieved by Pacific Gas and Electric Company (PG&E) and Southern California
Edison Company (SCE), (c) settlements made by California utilities with
various power providers, and (d) data in filings of FERC refund hearings.
SCE publicly disclosed that on March 1, 2002, it obtained financing and made
payments so that it has no material undisputed obligations that are past due
or in default. These payments included a payment to the CPX; however, TEP
has not received a corresponding payment from the CPX.
There are several other outstanding legal issues, complaints and
lawsuits concerning the California energy crisis related to the FERC,
wholesale power suppliers, SCE, PG&E, the CPX and the CISO, and concerning
Enron. In August 2002, the FERC staff proposed revised calculations to
determine amounts due from the CPX and the CISO, based on concern that
natural gas prices were manipulated. If we were to apply these proposed
adjustments to amounts due to TEP, TEP could receive as little as $4 million,
plus interest, of the amounts due from the CPX and the CISO. The FERC has
not yet confirmed or rejected the calculation proposed by its staff. Under
earlier calculations proposed by the FERC staff, TEP could receive up to $11
million plus interest. A FERC administrative law judge has issued a proposed
finding under which TEP would receive approximately $8.4 million, plus
interest. This represents amounts owed to TEP, net of TEP's estimated refund
liability. The FERC is accepting additional information and is expected to
issue a ruling on the recommended order later in 2003. We cannot predict the
outcome of these issues or lawsuits. We believe, however, that TEP is
adequately reserved for its transactions with the CPX, the CISO and Enron.
TEP's Accounts Receivable from Electric Wholesale Revenues, net of
allowances, totaled $31 million at December 31, 2002 and $70 million at
December 31, 2001. These amounts are included in Accounts Receivable on the
balance sheet. Excluding the receivables from the CPX, the CISO and Enron,
as described above, substantially all of the December 31, 2002 wholesale
receivable balance has been collected as of the date of this filing.
NOTE 12. INCOME TAXES
- ----------------------
Deferred tax assets (liabilities) consist of the following:
UniSource Energy TEP
------------------ -----------------
December 31, December 31,
2002 2001 2002 2001
- -----------------------------------------------------------------------------
-Millions of Dollars-
Gross Deferred Income Tax Liabilities
Electric Plant - Net $(397) $(398) $(397) $(398)
Income Taxes Recoverable Through
Future Revenues Regulatory Asset (23) (25) (23) (25)
Transition Recovery Asset (122) (131) (122) (131)
Other (26) (59) (24) (26)
- -----------------------------------------------------------------------------
Gross Deferred Income Tax
Liability (568) (613) (566) (580)
- -----------------------------------------------------------------------------
Gross Deferred Income Tax Assets
Capital Lease Obligations 334 346 334 346
Net Operating Loss Carryforwards 7 46 1 34
Investment Tax Credit Carryforwards 6 9 6 9
Alternative Minimum Tax 91 91 88 78
Accrued Pension Liabilities 16 14 16 14
Emission Allowance Inventory 15 15 15 15
Coal Contract Termination Fees 18 19 18 19
Springerville Coal Handling Facility 9 - 9 -
Other 69 64 44 36
- -----------------------------------------------------------------------------
Gross Deferred Income Tax Asset 565 604 531 551
Deferred Tax Assets Valuation
Allowance (16) (17) (16) (17)
- -----------------------------------------------------------------------------
Net Deferred Income Tax
Liability $ (19) $ (26) $ (51) $ (46)
=============================================================================
The net deferred income tax liability is included in the balance sheets
in the following accounts:
UniSource Energy TEP
------------------ ----------------
December 31, December 31,
2002 2001 2002 2001
- -----------------------------------------------------------------------------
-Millions of Dollars-
Deferred Income Taxes - Current
Assets $ 16 $ 11 $ 16 $ 5
Deferred Income Taxes - Noncurrent
Liabilities (35) (37) (67) (51)
- -----------------------------------------------------------------------------
Net Deferred Income Tax Liability $ (19) $ (26) $ (51) $ (46)
=============================================================================
We record deferred tax liabilities for amounts that will increase income
taxes on future tax returns. We record deferred tax assets for amounts that
could be used to reduce income taxes on future tax returns. We record a
Deferred Tax Assets Valuation Allowance for the amount of Deferred Tax Assets
that we may not be able to use on future tax returns. We estimate the
valuation allowance based on our interpretation of the tax rules, prior tax
audits, tax planning strategies, scheduled reversal of deferred tax
liabilities, and projected future taxable income. The valuation allowance of
$16 million at December 31, 2002, which reduces the Deferred Tax Asset
balance, relates to NOL and ITC carryforward amounts. In the future if TEP
determines that TEP should be able to use all or a portion of these amounts
on tax returns, then TEP would reduce the valuation allowance and recognize a
tax benefit up to $16 million. Factors that could cause TEP to recognize the
tax benefit include new or additional guidance through tax regulations, tax
rulings, case law and/or the use of such benefits on future tax returns.
In 2002, the Deferred Tax Assets Valuation Allowance decreased $1
million due primarily to the settlement of audits. In 2001, there was no
change in the Deferred Tax Assets Valuation Allowance. In 2000, the Deferred
Tax Assets Valuation Allowance decreased $8 million due primarily to the
improved likelihood of utilization of tax items.
TEP had a net intercompany tax receivable (payable) from affiliates of
zero at December 31, 2002 and ($5.0) million at December 31, 2001. These
amounts are included in TEP's intercompany accounts on its balance sheet.
In 2002, UniSource Energy recognized a tax benefit of $1.5 million as a
result of final agreement with the IRS on audit issues and a tax benefit of
$1.0 million from recognition of losses generated by the sale of a Nations
Energy foreign entity. These amounts are included in current and deferred
tax expense (benefit) in the following table.
Income tax expense (benefit) included in the income statements consists
of the following:
UniSource Energy TEP
-------------------- --------------------
Years Ended December 31,
2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------
-Millions of Dollars-
Current Tax Expense
Federal $ 19 $ 24 $ 14 $ 22 $ 25 $ 16
State 7 11 4 8 11 6
- -----------------------------------------------------------------------------
Total 26 35 18 30 36 22
Deferred Tax Expense (Benefit)
Federal (1) 16 6 9 22 13
State (7) (4) (1) (3) (2) -
- -----------------------------------------------------------------------------
Total (8) 12 5 6 20 13
- -----------------------------------------------------------------------------
Reduction in Valuation
Allowance - Benefit (1) - (8) (1) - (8)
- -----------------------------------------------------------------------------
Total Federal and State Income
Tax Expense $ 17 $ 47 $ 15 $ 35 $ 56 $ 27
- -----------------------------------------------------------------------------
The differences between the income tax expense and the amount obtained
by multiplying pre-tax income by the U.S. statutory federal income tax rate
of 35% are as follows:
UniSource Energy TEP
-------------------- --------------------
Years Ended December 31,
2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------
-Millions of Dollars-
Federal Income Tax Expense at
Statutory Rate $ 18 $ 38 $ 20 $ 32 $ 46 $ 27
State Income Tax Expense, Net
of Federal Deduction 2 5 3 4 6 4
Depreciation Differences (Flow
Through Basis) 4 5 5 4 5 5
Federal/State Credits (4) - - (4) - -
Reduction in Valuation
Allowance - Benefit (1) - (8) (1) - (8)
Foreign Operations of Millennium
Energy Businesses - (1) (3) - - -
Other (2) - (2) - (1) (1)
- -----------------------------------------------------------------------------
Total Federal and State Income
Tax Expense $ 17 $ 47 $ 15 $ 35 $ 56 $ 27
=============================================================================
The Total Federal and State Income Tax Expense in the tables above is
included on UniSource Energy and TEP's income statements. In addition, TEP
recorded a $2.6 million income tax benefit related to its minimum pension
liability at December 31, 2002 (see Note 13). This income tax benefit is
included in UniSource Energy and TEP's other comprehensive income at December
31, 2002.
At December 31, 2002, UniSource Energy and TEP had, for consolidated
federal income tax filing purposes:
- $21 million of NOL carryforwards expiring in 2006 through 2009;
- $6 million of unused ITC expiring in 2003 through 2022; and
- $91 million of AMT credit which will carry forward to future years.
Due to the issuance of common stock to various creditors of TEP in 1992,
a change in TEP's ownership was deemed to have occurred for tax purposes in
December 1991. As a result, TEP's use of the NOL and ITC generated before
1992 is limited under the tax code. At December 31, 2002, pre-1992 federal
NOL and ITC carryforwards which are subject to the limitation were
approximately $21 million and $4 million, respectively. We had $2 million of
ITC not subject to the limitation. Because of the appropriate valuation
allowance amounts recorded, we do not expect these annual limitations to have
a material adverse impact on the financial statements.
NOTE 13. EMPLOYEE BENEFITS PLANS
- ---------------------------------
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
TEP maintains noncontributory, defined benefit pension plans for all
regular employees. Benefits are based on years of service and the employee's
average compensation. TEP makes annual contributions to the plans sufficient
to meet the minimum funding requirements set forth by the Employee Retirement
Income Security Act of 1974, plus such additional tax deductible amounts as
may be advisable. Additionally, TEP provides supplemental retirement
benefits to certain employees whose benefits are limited by IRS benefit or
compensation limitations.
TEP also provides health care and life insurance benefits for retirees.
All regular employees may become eligible for these benefits if they reach
retirement age while working for TEP. The ACC allows TEP to recover
postretirement costs through rates only as benefit payments are made to or on
behalf of retirees. The postretirement benefits are currently funded
entirely on a pay-as-you-go basis. Under current accounting guidance, TEP
cannot record a regulatory asset for the excess of expense calculated per
Statement of Financial Accounting Standards No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions, over actual benefit
payments.
TEP amended its other postretirement benefit plan as of January 1, 2003,
capping its annual cost for Post-Medicare coverage for both current
classified retirees under age 65 and all classified employees retiring after
December 31, 2002. As of June 1, 2001, TEP amended this plan to eliminate
post-65 medical benefits for salaried employees retiring after January 1,
2002 and cap Medicare supplement payments for salaried retirees under age 65.
These amendments required TEP to recalculate benefits related to
participants' past service. TEP is amortizing the change in the benefit cost
from these plan amendments on a straight-line basis over 10 years.
The actuarial present values of the pension benefit obligations and
other postretirement benefit plan were measured at December 1. The change in
benefit obligation and plan assets and reconciliation of the funded status
are as follows:
Other Postretirement
Pension Benefits Benefits
---------------- -------------------
Years Ended December 31,
2002 2001 2002 2001
- -----------------------------------------------------------------------------
-Millions of Dollars-
Change in Benefit Obligation
Benefit Obligation at
Beginning of Year $ 117 $ 102 $ 59 $ 64
Actuarial (Gain) Loss 10 9 8 1
Interest Cost 8 8 4 4
Service Cost 4 4 2 2
Benefits Paid (6) (6) (2) (2)
Plan Amendments - - (12) (10)
-----------------------------------------
Benefit Obligation at
End of Year 133 117 59 59
-----------------------------------------
Change in Plan Assets
Fair Value of Plan Assets
at Beginning of Year 120 137 - -
Actual Return on Plan Assets (14) (13) - -
Benefits Paid (6) (6) (2) (2)
Employer Contributions 6 2 2 2
-----------------------------------------
Fair Value of Plan Assets
at End of Year 106 120 - -
-----------------------------------------
Reconciliation of Funded Status
to Balance Sheet
Funded Status (Difference
between Benefit Obligation
and Fair Value of Plan Assets) (27) 3 (59) (59)
Unrecognized Net (Gain) Loss 34 (1) 32 26
Unrecognized Prior Service Cost 14 16 (12) -
-----------------------------------------
Net Amount Recognized in
the Balance Sheets $ 21 $ 18 $ (39) $ (33)
=========================================
Amounts Recognized in the
Balance Sheets Consist of:
Prepaid Pension Costs Included
in Other Assets $ 13 $ 21 $ - $ -
Accrued Benefit Liability
Included in Other Liabilities (10) (3) (39) (33)
Intangible Asset Included in
Other Assets 11 - - -
Accumulated Other Comprehensive
Income 7 - - -
-----------------------------------------
Net Amount Recognized $ 21 $ 18 $ (39) $ (33)
=========================================
Benefit Obligation and Fair Value
of Plan Assets for Plans with
Benefit Obligations in Excess of
Plan Assets:
Benefit Obligation at
End of Year $ 133 $ 61 $ 59 $ 59
Fair Value of Plan Assets at
End of Year $ 106 $ 51 $ - $ -
- -----------------------------------------------------------------------------
At December 31, 2002, the pension benefit obligation exceeded the fair
value of Plan Assets for all three defined benefit plans maintained by TEP.
At December 31, 2001, the benefit obligation exceeded the fair value of Plan
Assets for only two of the three plans.
TEP recorded a minimum pension liability of $6.7 million on one of its
defined benefit plans at December 31, 2002. The adjustment is reflected in
other comprehensive income and other long-term liabilities, as appropriate,
and is prescribed when the accumulated benefit obligation in the plan exceeds
the fair value of the underlying pension plan assets and accrued pension
liabilities. The adjustment is primarily attributable to current stock market
conditions and a reduction in the assumed discount rate.
The components of net periodic benefit costs are as follows:
Other Postretirement
Pension Benefits Benefits
-------------------- --------------------
Years Ended December 31,
2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------
-Millions of Dollars-
Components of Net Periodic Cost
Service Cost $ 5 $ 4 $ 4 $ 2 $ 2 $ 1
Interest Cost 8 7 7 4 4 3
Expected Return on Plan Assets (11) (12) (11) - - -
Prior Service Cost Amortization 2 2 2 - - -
Recognized Actuarial (Gain) Loss - (2) (1) 2 2 1
Amortization of Transition Asset - - - - - 1
- -----------------------------------------------------------------------------
Net Periodic Benefits Cost
(Benefit) $ 4 $ (1) $ 1 $ 8 $ 8 $ 6
=============================================================================
Other Postretirement
Pension Benefits Benefits
-------------------- --------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------
Actuarial Assumptions as of
December 1,
Discount Rate 6.75% 7.25% 6.75% 7.25%
Rate of Compensation Increase 4.00% 4.00% - -
Expected Return on Plan Assets 8.75% 9.00% - -
Initial Health Care Cost Trend
Rate - - 12.00% 8.50%
- -----------------------------------------------------------------------------
The initial health care cost trend rate as of December 1, 2002 was
assumed to decrease gradually to 5.00% in 2011 and beyond.
Assumed health care cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects on the
December 31, 2002 amounts:
One-Percentage- One-Percentage-
Point Increase Point Decrease
------------------------------------------------------------------------
-Millions of Dollars-
Effect on Total of Service and
Interest Cost Components $ 1 $ (1)
Effect on Postretirement Benefit
Obligation $ 5 $ (4)
------------------------------------------------------------------------
DEFINED CONTRIBUTION PLANS
All regular employees may contribute a percentage of their pre-tax
compensation, subject to certain limitations, in TEP's voluntary, defined
contribution 401(k) plans. TEP contributes cash to the account of each
participant based on each participant's contributions not exceeding 4.5% of
the participant's compensation. Participants direct the investment of
contributions to certain funds in their account. TEP incurred approximately
$3 million in expense related to these plans in each of 2002, 2001 and 2000.
STOCK-BASED COMPENSATION PLANS
On May 20, 1994, the Shareholders approved two stock-based compensation
plans, the 1994 Outside Director Stock Option Plan (1994 Directors' Plan) and
the 1994 Omnibus Stock and Incentive Plan (1994 Omnibus Plan).
The 1994 Directors' Plan provided for the annual grant of 1,200 non-
qualified stock options to each eligible director at an exercise price equal
to the market price of the common stock at the grant date, beginning January
3, 1995. These options vest over three years, become exercisable in one-
third increments on each anniversary date of the grant and expire on the
tenth anniversary. In December 1998, the Board of Directors approved an
increase in the annual grant of non-qualified stock options to 2,000
beginning January 1999.
In May 2002, the Directors' Plan was amended to provide each eligible
director an annual award of non-qualified stock options to be determined as
of the first business day of the calendar year. The number of options
granted will be calculated by dividing $10,000 by the option's Black-Scholes
value on the date of grant. Additionally, each eligible director received an
initial award in May 2002 for a number of restricted shares of Common Stock
equal to $10,000 divided by the fair market value of a share of Common Stock
as of that date. Similar awards will be granted annually on the first
business day of each calendar year during the term of the plan. Each
participant may elect to receive stock units in lieu of restricted shares.
The restricted shares or stock units become 100% vested on the third
anniversary of the grant date. Compensation expense equal to the fair market
value on the date of award is recognized over the vesting period. In May
2002, 516 shares or units were awarded to each of nine directors. The total
number of shares of UniSource Energy Common Stock that may be awarded under
the Directors' Plan cannot exceed 324,000 shares.
The 1994 Omnibus Plan allows the Compensation Committee, a committee of
non-employee directors, to grant the following types of awards to each
eligible employee: stock options; stock appreciation rights; restricted
stock; stock units; performance units; performance shares; and dividend
equivalents. The total number of shares of UniSource Energy Common Stock
that may be awarded under the Omnibus Plan cannot exceed 4.1 million. There
were no stock unit awards granted in 2002 or 2001. Stock unit awards of
10,000 units were granted in 2000. Compensation expense equal to the fair
market value on the date of the award is recognized over a three or four year
vesting period for all stock unit awards. During 2002, 2001 and 2000, TEP
recognized compensation expense for stock unit awards of $0.5 million, $0.9
million and $0.9 million, respectively.
Stock Options
-------------
The Compensation Committee granted stock options to key employees during
2002, 2001, and 2000. These stock options were granted at exercise prices
equal to the market price of the common stock at the grant date. These
options vest over three years, become exercisable in one-third increments on
each anniversary date of the grant and expire on the tenth anniversary of the
grant.
A summary of the stock option activity of the 1994 Directors' Plan and
1994 Omnibus Plan is as follows:
2002 2001 2000
- -----------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
- -----------------------------------------------------------------------------
Options Outstanding,
Beginning of Year 2,075,234 $15.05 1,918,077 $14.36 1,390,033 $14.01
Granted 590,000 $18.14 410,000 $17.96 601,000 $15.14
Exercised (64,851) $14.42 (177,602) $14.56 (7,749) $12.88
Forfeited (23,564) $15.46 (75,241) $14.60 (65,207) $14.10
---------- ---------- ----------
Options Outstanding,
End of Year 2,576,819 $15.77 2,075,234 $15.05 1,918,077 $14.36
========== ========== ==========
Options Exercisable,
End of Year 1,442,179 $14.47 1,081,162 $14.38 856,656 $14.67
Exercise Price Range of Options Outstanding at December 31, 2002: $11.00
to $18.84
Weighted Average Remaining Contractual Life at December 31, 2002: 6.94
- -----------------------------------------------------------------------------
As discussed in Note 1, we apply APB 25 in accounting for our stock
option plans. Accordingly, we have not recognized any compensation cost for
these options. We have also adopted the disclosure-only provisions of FAS
123. As required by FAS 148, the effect on net income and earnings per share
if the company had applied the fair value recognition provisions of FAS 123
to stock-based employee compensation is presented in Note 1.
The fair value of each stock option grant is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted average assumptions:
2002 2001 2000
-------------------------------
Expected life (years) 5 5 5
Interest rate 1.45% 4.70% 6.10%
Volatility 23.74% 23.93% 23.04%
Dividend yield 2.83% 2.08% 2.14%
Stock options awarded after January 1, 2002 accrue dividend equivalents
that are paid in cash on the earlier of the date of exercise of the
underlying option or the date the option expires. Compensation expense is
recognized as dividends are declared. In 2002, TEP recognized compensation
expense of $0.3 million for dividend equivalents on stock option grants.
NOTE 17.14. UNISOURCE ENERGY EARNINGS PER SHARE (EPS)
- ---------------------------------------------------
Basic EPS is computed by dividing net income by the weighted average
number of common shares outstanding during the period. Diluted EPS assumes
that proceeds from the hypothetical exercise of stock options and other stock-
based awards are used to repurchase outstanding shares of stock at the
average fair market price during the reporting period. The following table
shows the amounts used in computing EPS and the effects of potential dilutive
common stock on the weighted average number of shares:
Years Ended December 31,
2002 2001 2000
-----------------------------------------------------------------------
-In Thousands-
Basic EPS: (except per share data)
Numerator:
Income Before Cumulative Effect of
Accounting Change $33,275 $60,875 $41,891
Cumulative Effect of Accounting Change - 470 -
-----------------------------------------------------------------------
Net Income $33,275 $61,345 $41,891
=======================================================================
Denominator:
Average Shares of Common Stock
Outstanding 33,665 33,399 32,445
=======================================================================
Basic EPS:
Before Cumulative Effect of Accounting
Change $0.99 $1.83 $1.29
Cumulative Effect of Accounting Change - 0.01 -
-----------------------------------------------------------------------
Net Income $0.99 $1.84 $1.29
=======================================================================
Diluted EPS:
Numerator:
Income Before Cumulative Effect of
Accounting Change $33,275 $60,875 $41,891
Cumulative Effect of Accounting
Change - 470 -
-----------------------------------------------------------------------
Net Income $33,275 $61,345 $41,891
=======================================================================
Denominator:
Average Shares of Common Stock
Outstanding 33,665 33,399 32,445
Effect of Dilutive Securities:
Warrants 81 143 -
Options and Stock Issuable under
Employee Benefit Plans 476 625 434
-----------------------------------------------------------------------
Total Shares 34,222 34,167 32,879
=======================================================================
Diluted EPS:
Before Cumulative Effect of Accounting
Change $0.97 $1.79 $1.27
Cumulative Effect of Accounting Change - 0.01 -
-----------------------------------------------------------------------
Net Income $0.97 $1.80 $1.27
=======================================================================
Options to purchase an average of 525,000 shares of common stock at
$16.56 to $18.84 per share were outstanding during the year 2002 but were not
included in the computation of diluted EPS because the options' exercise
price was greater than the average market price of the common stock.
At December 31, 2002, UniSource Energy had no outstanding warrants.
There were 4.6 million warrants that were exercisable into TEP common stock
until December 15, 2002, when they expired. See Note 9. The dilutive effect
of these warrants was the same as it would have been if the warrants were
exercisable into UniSource Energy Common Stock.
NOTE 15. ASSET PURCHASE AGREEMENTS
- -----------------------------------
On October 29, 2002, UniSource Energy entered into two Asset Purchase
Agreements with Citizens Communications Company (Citizens) for the purchase
by UniSource Energy of Citizens' Arizona electric utility and gas utility
businesses for a total of $230 million in cash. The purchase price of each
is subject to adjustment based on the date on which the transaction is closed
and, in each case, on the amount of certain assets and liabilities of the
purchased business at the time of closing. If the transaction closes before
July 28, 2003, the purchase price is reduced by $10 million. If the
transaction closes after October 29, 2003, the purchase price is increased by
$5 million. In addition, the purchase price in each transaction may also be
adjusted if there is a casualty loss, governmental taking, or discovery of
substantial additional environmental liabilities, in each case subject to
materiality thresholds, prior to the closing. UniSource Energy will assume
certain liabilities associated with the purchased assets, but will not assume
Citizens' obligations under the industrial development revenue bonds issued
to finance certain of the purchased assets for which Citizens will remain the
economic obligor. The asset purchases are expected to close in the second
half of 2003 after the conditions to the consummation of the transactions,
including federal and state regulatory approvals, are satisfied or waived.
The closing of the transactions is subject to approval by the ACC, the
FERC and the SEC under the Public Utility Holding Company Act of 1935, as
amended. The closing is also subject to the filing of the requisite
notification with the Federal Trade Commission and the Department of Justice
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and other
customary closing conditions.
The Asset Purchase Agreements are subject to termination if the closing
has not occurred within 15 months of the date of the Asset Purchase
Agreements (subject to extension in limited circumstances), if a governmental
authority seeks to prohibit the transactions, if required regulatory
approvals are not obtained with satisfactory terms and conditions, or if
either party is in material breach and such breach is not cured. If one
Asset Purchase Agreement is terminated, the other will also be automatically
terminated. If the Asset Purchase Agreements are terminated by Citizens due
to UniSource Energy's breach, UniSource Energy must pay to Citizens a $25
million termination fee as liquidated damages. If the Asset Purchase
Agreements are terminated by UniSource Energy due to Citizen's breach,
Citizens must pay to UniSource Energy a $10 million termination fee as
liquidated damages. The termination fees are also payable in certain other
limited circumstances.
Citizens had two cases pending before the ACC requesting rate relief for
both the Arizona electric and Arizona gas assets prior to entering into the
Asset Purchase Agreements with UniSource Energy. In December 2002, UniSource
Energy and Citizens filed a Joint Application with the ACC requesting smaller
increases in both pending cases. Under the proposal, UniSource Energy asked
that the 45% electric rate increase requested by Citizens be reduced to 22%,
and that the 29% increase in gas rates be reduced to 23%. UniSource Energy
believes that the smaller proposed rate increases are sufficient in light of
the discounted purchase price. We are currently in settlement discussions
with the ACC Staff and intervenors regarding the Joint Application. The ACC
Administrative Law Judge set a hearing date of May 1, 2003 for this matter.
We currently anticipate the ACC to review this case and issue a decision by
June 2003.
We expect that the purchase price will be financed by funds from
UniSource Energy and its affiliates and debt secured by the purchased assets.
TEP is limited by its Credit Agreement, however, as to the amount of
affiliate investments it may make. UniSource Energy may also consider
financing a portion of the purchase with new equity, depending on market
conditions and other considerations. UniSource Energy expects to form a new
subsidiary to hold the purchased assets. This new subsidiary will maintain a
separate rate structure from TEP. If UniSource Energy is unable to obtain
financing and therefore fails to consummate the purchase of these assets,
this would constitute a breach under the contracts and termination damages of
$25 million would be payable.
NOTE 16. SUPPLEMENTAL CASH FLOW INFORMATION
- --------------------------------------------
WeUniSource Energy and TEP define Cash and Cash Equivalents as cash
(unrestricted demand deposits) and all highly liquid investments purchased
with an original maturity of three months or less. A reconciliation of net
income to net cash flows from operating activities follows:
UniSource Energy
----------------------------------------------------------------------
Years Ended December 31,
2002 2001 2000
1999
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
Net Income $ 33,275 $ 61,345 $ 41,891 $ 79,107
Adjustments to Reconcile Net Income
to Net Cash Flows
Extraordinary Income - Net of Tax - - (22,597)
Depreciation and Amortization Expense 127,923 120,346 114,038
92,740Depreciation Recorded to Fuel and Other
O&M Expense 5,701 6,001 5,307
Coal Contract Amendment Fee (14,248) - 13,231 -
Deferred Income Taxes and Investment
Tax Credit 8,317 13,905 12,407
Lease Payments Deferred - - 28,318
Amortization of Transition Recovery Asset 24,554 21,609 17,008
2,302
Net Unrealized (Gain) Loss on TEP Forward
SalesContracts and PurchasesMEG Trading Activities (721) 564 - -
Amortization of Deferred Debt-Related
Costs included in Interest Expense 2,058 1,996 3,167
5,091Provision for Bad Debts 1,688 (529) 9,607
Deferred Contract Termination Fee - - 3,205
UnremittedIncome Taxes 2,066 8,317 13,905
Losses of
Unconsolidated Subsidiariesfrom Equity Method Entities 3,560 2,516 4,206 3,370
Emission Allowances - - (12,926)
Gain on Sale of NewEnergy - - (34,651)
Gain on Sale of Nations Energy's Curacao
Project - (10,737) -
Gain on Sale of Real Estate - (1,572) -
Other (8,963)(11,114) (7,391) 4,878 4,018
Changes in Assets and Liabilities which
Provided (Used) Cash Exclusive of
Changes Shown Separately
Accounts Receivable (4,106) (47,816) 2,989
Tax Settlement Deposit - - (22,403)40,465 (3,577) (57,423)
Materials and Fuel 4,011 (2,280) (5,579)Inventory (2,118) (653) (6,744)
Accounts Payable (35,193) 17,626 37,655
36Interest Accrued 18,542 10,191 2,543
Taxes Accrued (9,096) (907) 4,908 (929)
Interest Accrued 10,191 2,543 (1,108)
Other Current Assets (12,199) (14,094) (7,647) (4,988)
Other Current Liabilities 2,517 (4,328) 5,891 (6,528)
Other Deferred Assets (2,149) 5,801 (2,961)(14,120) (3,486) 4,958
Other Deferred Liabilities 9,423 12,142 3,655
(5,685)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows - Operating Activities $172,963 $215,379 $215,034
$113,228
============================================================================================================================================================
TEP
----------------------------------------------------------------------
Years Ended December 31,
2002 2001 2000
1999
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
Net Income $ 53,737 $ 75,284 $ 51,169 $ 73,475
Adjustments to Reconcile Net Income
to Net Cash Flows
Extraordinary Income - Net of Tax - - (22,597)
Depreciation and Amortization Expense 124,054 117,063 113,507
92,583Depreciation Recorded to Fuel and Other
O&M Expense 5,701 6,001 5,307
Coal Contract Amendment Fee (14,248) - 13,231 -
Deferred Income Taxes and Investment
Tax Credit 18,205 27,633 277
Lease Payments Deferred - - 28,318
Amortization of Transition Recovery Asset 24,554 21,609 17,008
2,302
Net Unrealized (Gain) Loss on Forward
Electric Sales and Purchases (533) 532 - -
Amortization of Deferred Debt-Related
Costs included in Interest Expense 2,058 1,996 3,167
5,091Provision for Bad Debts 1,688 (529) 9,607
Deferred Contract Termination Fee - - 3,205
Unremitted (Earnings)Income Taxes 15,186 18,205 27,633
Losses of
Unconsolidated Subsidiariesfrom Equity Method Entities 530 1,812 2,414 (471)
Emission Allowances - - (12,926)
Interest Accrued on Note Receivable
from UniSource Energy (9,329) - -
9,329Gain on Sale of Real Estate - (1,572) -
Other 8652,830 2,437 157 9,035
Changes in Assets and Liabilities which
Provided (Used) Cash Exclusive of
Changes Shown Separately
Accounts Receivable (4,513) (46,648) 4,338
Tax Settlement Deposit - - (22,403)35,192 (3,984) (56,255)
Materials and Fuel 4,829 (1,812) (5,540)Inventory (1,331) 165 (6,276)
Accounts Payable (35,011) 15,238 36,981
(2)Interest Accrued 18,542 10,191 2,543
Taxes Accrued (4,428) (2,470) 7,218 (4,491)
Interest Accrued 10,191 2,543 (1,108)
Other Current Assets (12,771) (1,229) (336) (3,366)
Other Current Liabilities 2,683 (3,358) 973 (6,432)
Other Deferred Assets (3,857) 3,341 (2,961)(13,265) (5,194) 2,498
Other Deferred Liabilities 7,678 8,972 3,644
(5,699)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows - Operating Activities $203,517 $261,169 $234,190 $139,957
===============================================================================234,190
=============================================================================
Non-cash investing and financing activities of UniSource Energy and TEP
that affected recognized assets and liabilities but did not result in cash
receipts or payments were as follows:
Years Ended December 31,
2002 2001 2000
1999
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
Capital Lease Obligations $11,604 $20,743 $ 1,031 $38,747
Capital Lease Asset - - 26,019
Minimum Pension Liability - - (10,036)
Notes Receivable Received From the Sale of
Nations Energy's Curacao Project* - 8,300 -
-
Notes Receivable Received From the Sale of
NewEnergy* - - 22,800
AES Stock Received From the Sale of NewEnergy* - - 27,203
NewEnergy Investment* - - (15,351)
* These items areThis item is a non-cash investing and financing activitiesactivity of Millennium, and
therefore, areis not reflected on TEP's financial statements.
The non-cash change in capital lease obligations represents interest
accrued for accounting purposes in excess of interest payments in 2002, 2001,
2000,
and 1999 as well as a $26 million increase in the capital lease obligation and
asset resulting from the Springerville Common Facilities Lease refinancing
which occurred in 1999. See Note 7.
Non-cash consideration received upon the sale of NewEnergy in 1999
included two NewEnergy promissory notes, as well as AES common stock.
Concurrent with the receipt of these notes and stock, we removed the NewEnergy
investment from our balance sheet and recorded a gain on the sale. See Note
4.
2000.
NOTE 18.17. QUARTERLY FINANCIAL DATA (UNAUDITED)
- ----------------------------------------------
UniSource Energy
----------------------------------------------------------------------------------
First Second Third Fourth
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
2002
Operating Revenues $171,195 $227,203 $258,546 $199,278
Operating Income 24,686 51,971 65,211 41,993
Net Income (Loss) (6,314) 11,888 22,819 4,882
Basic EPS (0.19) 0.35 0.68 0.14
Diluted EPS (0.19) 0.35 0.67 0.14
- -----------------------------------------------------------------------------
2001
Operating Revenues $283,665 $406,615 $429,662 $324,766$397,466 $420,389 $315,492
Operating Income 70,822 63,036 55,276 59,326
Income Before Cumulative Effect of
Accounting Change 18,795 13,254 15,548 13,278
Cumulative Effect of Accounting
Change - Net of Tax 470 - - -
Net Income 19,265 13,254 15,548 13,278
Basic Earnings Per Share:EPS:
- ------------------------
Income Before Cumulative Effect of
Accounting Change 0.57 0.40 0.46 0.40
Cumulative Effect of Accounting
Change - Net of Tax 0.01 - - -
Net Income 0.58 0.40 0.46 0.40
Diluted Earnings Per Share:EPS:
- --------------------------
Income Before Cumulative Effect of
Accounting Change 0.56 0.39 0.45 0.39
Cumulative Effect of Accounting
Change - Net of Tax 0.01 - - -
Net Income 0.57 0.39 0.45 0.39
- -------------------------------------------------------------------------------
2000
Operating Revenues $177,479 $236,475 $342,217 $277,498
Operating Income 36,057 47,850 64,766 61,655
Net Income 242 10,659 17,239 13,751
Basic Earnings Per Share 0.01 0.33 0.53 0.42
Diluted Earnings Per Share 0.01 0.32 0.52 0.42
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
TEP
----------------------------------------------------------------------------------
First Second Third Fourth
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
2002
Operating Revenues $169,577 $226,362 $257,022 $198,132
Operating Income 29,170 58,163 71,833 50,009
Interest Income - Note Receivable
from UniSource Energy 2,301 2,325 2,352 2,351
Net Income (Loss) (1,930) 17,467 26,562 11,638
- -----------------------------------------------------------------------------
2001
Operating Revenues $281,800 $404,027 $427,483 $323,055$394,878 $418,210 $313,781
Operating Income 74,875 66,875 60,077 63,657
Interest Income - Note Receivable
from UniSource Energy 2,300 2,327 2,351 2,352
Income Before Cumulative Effect of
Accounting Change 23,041 18,904 14,440 18,429
Cumulative Effect of Accounting
Change - Net of Tax 470 - - -
Net Income 23,511 18,904 14,440 18,429
- -------------------------------------------------------------------------------
2000
Operating Revenues $176,623 $235,570 $340,501 $275,674
Operating Income 38,382 50,789 68,575 67,574
Interest Income - Note Receivable
from-----------------------------------------------------------------------------
EPS is computed independently for each of the quarters presented.
Therefore, the sum of the quarterly EPS do not necessarily equal the total
for the year.
Due to seasonal fluctuations in TEP'S sales and unusual items, each
quarter's results is not indicative of annual operating results. the
principal unusual items for TEP and UniSource Energy 2,326 2,311 2,345 2,347
Net Income (Loss) (86) 13,387 19,835 18,033
- -------------------------------------------------------------------------------
EARNINGS PER SHARE IS COMPUTED INDEPENDENTLY FOR EACH OF THE QUARTERS
PRESENTED. THEREFORE, THE SUM OF THE QUARTERLY EARNINGS PER SHARE DO NOT
NECESSARILY EQUAL THE TOTAL FOR THE YEAR.
DUE TO SEASONAL FLUCTUATIONS IN TEP'S SALES AND UNUSUAL ITEMS, THE
QUARTERLY RESULTS ARE NOT INDICATIVE OF ANNUAL OPERATING RESULTS. THE
PRINCIPAL UNUSUAL ITEMS FOR UNISOURCE ENERGY AND TEP INCLUDE:include:
TEP
- FIRST QUARTERThird Quarter 2002: TEP recorded a one-time $11.3 million pre-tax
expense related to the termination of the Irvington coal contract. See
Note 10. TEP also recognized a $2 million tax benefit due to the
resolution of various tax items. See Note 12.
- First Quarter 2001: TEP RECORDED Arecorded a $0.5 MILLION UNREALIZED GAIN FOR THE
CUMULATIVE EFFECTS OF ADOPTINGmillion unrealized gain for the
cumulative effects of adopting FAS 133 FOR ITS FORWARD WHOLESALE TRADING
ACTIVITY. SEE NOTEfor its forward wholesale trading
activity. See Note 3.
In addition to the unusual TEP items mentioned above, UniSource Energy
results include:
- SECOND QUARTER 2000: TEP RECOGNIZED A $6 MILLION TAX BENEFIT DUE TO THE
RESOLUTION OF VARIOUS TAX ITEMS. SEE NOTEThird Quarter 2002: Millennium recognized a $2.8 million tax benefit due
to the resolution of various tax items. See Note 12.
- THIRD QUARTER 2000:Third Quarter 2001: Nations Energy recorded a pre-tax gain of $11
million from the sale of its 26% equity interest in a power project located
in Curacao, Netherland Antilles. See Note 4.
In the third quarter of 2002, TEP RECORDED A ONE-TIME $13 MILLION PRE-TAX EXPENSE
RELATED TO THE AMENDMENT OF THE SAN JUAN COAL SUPPLY CONTRACT. SEE NOTE 10.
IN ADDITION TO THE UNUSUALbegan reporting purchase and sale
transactions under a Resource Management agreement with one of its
counterparties on a net basis, because TEP's purchases and sales to this
counterparty exactly offset each other and are made only for scheduling
purposes. TEP ITEMS MENTIONED ABOVE, UNISOURCE ENERGY
RESULTS INCLUDE:
- THIRD QUARTER 2001: NATIONS ENERGY RECORDED A PRE-TAX GAIN OF $11 MILLION
FROM THE SALE OF ITS 26% EQUITY INTEREST IN A POWER PROJECT LOCATED IN
CURACAO, NETHERLAND ANTILLES. SEE NOTE 4.
- FIRST QUARTER 2000: NATIONS ENERGY RECORDED A PRE-TAX GAIN OF $3 MILLION
FROM THE SALE OF ITS MINORITY INTEREST IN A POWER PROJECT LOCATED IN THE CZECH
REPUBLIC. SEE NOTE 4.
IN THE SECOND QUARTER OFreclassified purchased power related to its purchases from the
counterparty as a reduction of Electric Wholesale Revenues related to its
sales to the counterparty.
In the second quarter of 2001, WE BEGAN REPORTING UNREALIZED GAIN (LOSS)
ON FORWARD PURCHASES NET OF UNREALIZED GAIN (LOSS) ON FORWARD SALES AS A
COMPONENT OF OPERATING REVENUES. IN THE FIRST QUARTER OFTEP began reporting Unrealized Gain
(Loss) on Forward Purchases net of Unrealized Gain (Loss) on Forward Sales as
a component of Operating Revenues. In the first quarter of 2001, WE PRESENTED
UNREALIZED GAIN (LOSS) ON FORWARD PURCHASES AS A COMPONENT OF OPERATING
EXPENSES. ALSO, IN THE FOURTH QUARTER OFTEP
presented Unrealized Gain (Loss) on Forward Purchases as a component of
Operating Expenses. Also, in the fourth quarter of 2001, WE CONSOLIDATED INCOME TAXES
INTO A SINGLE LINE ITEM BELOW INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEM
AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE. PREVIOUSLY, INCOME TAXES WERE
INCLUDED IN OPERATING EXPENSES AND OTHER INCOME (DEDUCTIONS)UniSource Energy
and TEP consolidated Income Taxes into a single line item below Income Before
Income Taxes, Extraordinary Item and Cumulative Effect of Accounting Change.
Previously, Income Taxes were included in Operating Expenses and Other Income
(Deductions).
UniSource Energy
----------------------------------------------------------------------------------
First Second Third Fourth
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
2002
Operating Revenues - Historical $180,267 $236,375 $258,546 $199,278
Reclassification (9,072) (9,172) - -
Operating Revenues - Restated 171,195 227,203 258,546 199,278
- -----------------------------------------------------------------------------
2001
Operating Revenues - Historical $241,206 $406,615 $429,662 $324,766
Reclassification 42,459 - - -(9,149) (9,273) (9,274)
Operating Revenues - Restated 283,665 406,615 429,662 324,766397,466 420,389 315,492
Operating Income - Historical $ 57,250 $ 52,587 $ 47,846 $ 59,326
Reclassification 13,572 10,449 7,430 -
Operating Income - Restated 70,822 63,036 55,276 59,326
- -------------------------------------------------------------------------------
2000
Operating Income - Historical $ 38,055 $ 51,087 $ 55,293 $ 52,968
Reclassification (1,998) (3,237) 9,473 8,687
Operating Income - Restated 36,057 47,850 64,766 61,655
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
TEP
----------------------------------------------------------------------------------
First Second Third Fourth
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
2002
Operating Revenues - Historical $178,649 $235,534 $257,022 $198,132
Reclassification (9,072) (9,172) - -
Operating Revenues - Restated 169,577 226,362 257,022 198,132
- -----------------------------------------------------------------------------
2001
Operating Revenues - Historical $239,341 $404,027 $427,483 $323,055
Reclassification 42,459 - - -(9,149) (9,273) (9,274)
Operating Revenues - Restated 281,800 404,027 427,483 323,055394,878 418,210 313,781
Operating Income - Historical $ 59,680 $ 54,889 $ 50,721 $ 63,657
Reclassification 15,195 11,986 9,356 -
Operating Income - Restated 74,875 66,875 60,077 63,657
- -------------------------------------------------------------------------------
2000
Operating Income - Historical $ 39,444 $ 52,846 $ 57,512 $ 56,482
Reclassification (1,062) (2,057) 11,063 11,092
Operating Income - Restated 38,382 50,789 68,575 67,574
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
SUPPLEMENTARY DATA
- -------------------------------------------------------------------------------
Schedule II - Valuation and Qualifying Accounts
Additions-
Beginning Charged to Ending
Description Balance Income(1) Deductions(2) Balance
- -------------------------------------------------------------------------------
Year Ended December 31, -Millions of Dollars-
Allowance for Doubtful Accounts
2002 $ 9.2 $ 1.7 $ 1.9 $ 9.0
2001 $ 9.7 $ 1.3 $ 1.8 $ 9.2
2000 6.9 10.2 7.4 9.7
1999 4.9 3.2 1.2 6.9
- -------------------------------------------------------------------------------
(1) TEP recorded $7 million of expense in the first quarter of 2001 and $9
million in the fourth quarter of 2000 to reserve for uncollectible amounts
related to sales to the state of California in 2000 and the first quarter
of 2001. TEP reversed $8 million of the $16 million reserve in the fourth
quarter of 2001 (see Note 11 of Notes to Consolidated Financial
Statements).
(2) Deductions principally reflect amounts charged off as uncollectible, less
amounts recovered.
ITEM 9. - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------
None.
PART III
ITEM 10. - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- --------------------------------------------------------------------------------
DIRECTORS
---------
Certain of the individuals serving as Directors of UniSource Energy also
serve as the Directors of TEP. Information concerning Directors will be
contained under Election of Directors in UniSource Energy's Proxy Statement
relating to the 20022003 Annual Meeting of Shareholders, which will be filed with
the SEC not later than 120 days after December 31, 2001,2002, which information is
incorporated herein by reference.
EXECUTIVE OFFICERS - UNISOURCE ENERGY
-------------------------------------
Executive Officers of UniSource Energy who are elected annually by
UniSource Energy's Board of Directors, are as follows:
EXECUTIVE
OFFICER
NAME AGE POSITION(S) HELD SINCE
- ---- --- ---------------- ---------
JAMES
Executive
Officer
Name Age Position(s) Held Since
------------------------------------------------------------------------------------------------
James S. Pignatelli 59 Chairman, President and Chief Executive Officer 1998
Michael J. DeConcini 38 Senior Vice President, Investments and Planning 1999
Dennis R. Nelson 52 Senior Vice President, Utility Services 1998
Karen G. Kissinger 48 Vice President, Controller and Chief Compliance Officer 1998
Kevin P. Larson 46 Vice President, Chief Financial Officer and Treasurer 2000
Steven W. Lynn 56 Vice President, Communications and Government Relations 2003
Vincent Nitido, Jr. 47 Vice President, General Counsel and Chief Administrative
Officer 2000
Catherine A. Nichols 44 Corporate Secretary 2003
James S. 58 CHAIRMAN, PRESIDENT AND CHIEF 1998
PIGNATELLI EXECUTIVE OFFICER Mr. Pignatelli joined TEP as Senior Vice President in
Pignatelli August 1994 and was elected Senior Vice President and Chief
Operating Officer in 1996. He was named Senior Vice President
and Chief Operating Officer of UniSource Energy in January
1998, and Executive Vice President and Chief Operating Officer
of TEP in March 1998. On June 23, 1998, Mr. Pignatelli was
named Chairman, President and CEO of UniSource Energy and TEP.
Prior to joining TEP, he was President and Chief Executive
Officer from 1988 to 1993 of Mission Energy Company, a
subsidiary of SCE Corp.
MICHAELMichael J. 37 SENIOR VICE PRESIDENT, STRATEGIC 1999
DECONCINI PLANNING AND INVESTMENTS Mr. DeConcini joined TEP in 1988 and served in various
DeConcini positions in finance, strategic planning and wholesale
marketing. He was Manager of TEP's Wholesale Marketing
Department in 1994, adding Product Development and Business
Development in 1997. In November 1998, he was elected Vice
President of MEH, and elected Vice President, Strategic
Planning of UniSource Energy in February 1999. He was named
Senior Vice President, StrategicInvestments and Planning and
Investments of UniSource
Energy in October 2000. DENNISMr. DeConcini was elected Senior Vice
President of the Energy Resources business unit of TEP,
effective January 1, 2003.
Dennis R. NELSON 51 SENIOR VICE PRESIDENT, 1998
GOVERNMENTAL AFFAIRS Mr. Nelson joined TEP as a staff attorney in 1976. He was
Nelson manager of the Legal Department from 1985 to 1990. He was
elected Vice President, General Counsel and Corporate
Secretary in January 1991. He was named Vice President,
General Counsel and Corporate Secretary of UniSource Energy in
January 1998. Mr. Nelson was named Senior Vice President and
General Counsel of TEP in November 1998. In December 1998 he
was named Chief Operating Officer, Corporate Services of TEP.
In October 2000, he was named Senior Vice President,
Governmental Affairs of UniSource Energy and Senior Vice
President and Chief Operating Officer of the Energy Resources
business unit of TEP. KARENMr. Nelson was elected Senior Vice
President of Utility Services, effective January 1, 2003.
Karen G. 47 VICE PRESIDENT, CONTROLLER AND 1998
KISSINGER PRINCIPAL ACCOUNTING OFFICER Ms. Kissinger joined TEP as Vice President and Controller
Kissinger in January 1991. She was named Vice President, Controller and
Principal Accounting Officer of UniSource Energy in January
1998. In November 1998, Ms. Kissinger was also named Chief
Information Officer of TEP. KEVINShe was named Chief Compliance
Officer of UniSource Energy and TEP, effective January 1,
2003.
Kevin P. LARSON 45 VICE PRESIDENT, CHIEF FINANCIAL 2000
OFFICER AND TREASURER Mr. Larson joined TEP in 1985 and thereafter held various
Larson positions in its finance department and at TEP's investment
subsidiaries. In January 1991, he was elected Assistant
Treasurer of TEP and named Manager of Financial Programs. He
was elected Treasurer of TEP in August 1994 and Vice President
in March 1997. In October 2000, he was elected Vice President
and Chief Financial Officer of both UniSource Energy and TEP
and remains Treasurer of both organizations.
VINCENT NITIDO, 46 VICE PRESIDENT, GENERAL COUNSELSteven W. Mr. Lynn joined TEP in 2000 JR. AND CORPORATE SECRETARYas Manager of Corporate Relations
Lynn for UniSource Energy and was named Manager of Corporate
Relations of both TEP and UniSource Energy during 2000. In
January 2003, he was elected Vice President of Communications
and Government Relations at UniSource Energy and TEP. Prior
to joining TEP, Mr. Lynn was an owner-partner from 1984 - 2000
of Nordensson Lynn & Associates, Inc.
Vincent Mr. Nitido joined TEP as a staff attorney in 1991. He
Nitido, Jr. was promoted to Manager of the Legal Department in 1994, and
elected Vice President and Assistant General Counsel in 1998.
In October 2000, he was elected Vice President, General
Counsel of both UniSource Energy and TEP and Corporate
Secretary of UniSource Energy. Mr. Nitido was also named
Chief Administrative Officer of UniSource Energy and TEP,
effective January 1, 2003.
Catherine A. Ms. Nichols joined TEP as a staff attorney in 1989.
Nichols She was promoted to Manager of the Legal Department and
elected Corporate Secretary of TEP in 1998. She assumed the
additional role of Manager of the Human Resources Department
in 1999. Ms. Nichols was elected Corporate Secretary of
UniSource Energy, effective January 1, 2003, and remains
Corporate Secretary of TEP.
EXECUTIVE OFFICERS - TUCSON ELECTRIC POWER COMPANY
--------------------------------------------------
Executive Officers of TEP who are elected annually by TEP's Board of
Directors, are:
EXECUTIVE
OFFICER
NAME AGE POSITION(S) HELD SINCE
- ---- --- ---------------- --------
JAMES
Executive
Officer
Name Age Position(s) Held Since
------------------------------------------------------------------------------------------------
James S. Pignatelli 59 Chairman, President and Chief Executive Officer 1994
Michael J. DeConcini 38 Senior Vice President, Energy Resources Business Unit 2003
Steven J. Glaser 45 Senior Vice President and Chief Operating Officer,
Transmission and Distribution Business Unit 1994
Thomas A. Delawder 56 Vice President, Energy Resources Business Unit 1985
Thomas N. Hansen 52 Vice President / Technical Advisor 1992
Karen G. Kissinger 48 Vice President, Controller and Chief Compliance Officer 1991
Kevin P. Larson 46 Vice President, Chief Financial Officer and Treasurer 1994
Steven Lynn W. 56 Vice President, Communications and Government Relations 2003
Vincent Nitido, Jr. 47 Vice President, General Counsel and Chief Administrative
Officer 1998
James Pyers 61 Vice President, Utility Distribution Business Unit,
Operations 1998
Catherine A. Nichols 44 Corporate Secretary 1998
James S.
58 CHAIRMAN, PRESIDENT AND CHIEF 1994
PIGNATELLI EXECUTIVE OFFICERPignatelli See description shown under UniSource Energy Corporation above.
STEVENMichael J.
GLASER 44 SENIOR VICE PRESIDENT AND CHIEF 1994
OPERATING OFFICER, TRANSMISSION &
DISTRIBUTION BUSINESS UNITDeConcini See description shown under UniSource Energy Corporation above.
Steven J. Mr. Glaser joined TEP in 1990 as a Senior Attorney in
Glaser charge of Regulatory Affairs. He was Manager of TEP's Legal
Department from 1992 to 1994, and Manager of Contracts and
Wholesale Marketing from 1994 until elected Vice President,
Business Development. In 1995, he was named Vice President,
Wholesale/Retail Pricing and System Planning. He was named
Vice President, Energy Services in 1996 and Vice President,
Rates and Regulatory Support and Utility Distribution Company
Energy Services in November 1998. In October 2000, he was
named Senior Vice President and Chief Operating Officer of the
Transmission and Distribution business unit.
DENNIS R. NELSON 51 SENIOR VICE PRESIDENT AND CHIEF 1991
OPERATING OFFICER, ENERGY
RESOURCES BUSINESS UNIT
See description shown under UniSource Energy Corporation above.
THOMASThomas A. 55 VICE PRESIDENT, ENERGY RESOURCES 1985
DELAWDER BUSINESS UNIT Mr. Delawder joined TEP in 1974 and thereafter served in
Delawder various engineering and operations positions. In April 1985
he was named Manager, Systems Operations and was elected Vice
President, Power Supply and System Control in November 1985.
In February 1991, he became Vice President, Engineering and
Power Supply and in January 1992 he became Vice President,
System Operations. In 1994, he became Vice President of the
Energy Resources business unit.
THOMASThomas N. HANSEN 51 VICE PRESIDENT / TECHNICAL 1992
SERVICES ADVISOR Mr. Hansen joined TEP in December 1992 as Vice President,
Hansen Power Production. Prior to joining TEP, Mr. Hansen was
Century Power Corporation's Vice President, Operations from
1989 and Plant Manager at Springerville from 1987 through
1988. In 1994, he was named Vice President / Technical
Services Advisor.
KARENKaren G.
47 VICE PRESIDENT, CONTROLLER, AND 1991
KISSINGER CHIEF INFORMATION OFFICERKissinger See description shown under UniSource Energy Corporation above.
KEVINKevin P.
LARSON 45 VICE PRESIDENT, CHIEF FINANCIAL 1994
OFFICER AND TREASURERLarson See description shown under UniSource Energy Corporation above.
VINCENT NITIDO, 46 VICE PRESIDENT AND GENERAL 1998
JR. COUNSELSteven W.
Lynn See description shown under UniSource Energy Corporation above.
JAMES PYERS 60 VICE PRESIDENT, UTILITY 1998
DISTRIBUTION BUSINESS UNIT,
OPERATIONSVincent
Nitido, Jr. See description shown under UniSource Energy Corporation above.
James Mr. Pyers joined TEP in 1974 as a Supervisor. Thereafter, he
Pyers held various supervisory positions and was promoted to Manager
of Customer Service Operations in February 1998. Mr. Pyers
was elected Vice President, Utility Distribution business
unit, Operations in November 1998.
CATHERINECatherine A.
43 CORPORATE SECRETARY 1998
NICHOLS
Ms. Nichols joined TEP as a staff attorney in 1989. She was
promoted to Manager of the Legal Department and elected Corporate
Secretary in 1998. She assumed the additional role of Manager of
the Human Resources Department in 1999.See description shown under UniSource Energy Corporation above.
ITEM 11. - EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
Information concerning Executive Compensation will be contained under
Executive Compensation and Other Information in UniSource Energy's Proxy
Statement relating to the 20022003 Annual Meeting of Shareholders, which will be
filed with the SEC not later than 120 days after December 31, 2001,2002, which
information is incorporated herein by reference.
ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- --------------------------------------------------------------------------------
GENERAL
-------
At February 25, 2002,March 4, 2003, UniSource Energy had outstanding 33,539,48733,583,182 shares of
Common Stock. As of February 25, 2002,March 4, 2003, the number of shares of Common Stock
beneficially owned by all directors and officers of UniSource Energy as a
group amounted to 2%approximately 3% of the outstanding Common Stock.
At February 25, 2002,March 4, 2003, UniSource Energy owned greater than 99.9% of the
outstanding shares of common stock of TEP.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
-----------------------------------------------
Information concerning the security ownership of certain beneficial
owners of UniSource Energy will be contained under Security Ownership of
Certain Beneficial Owners in UniSource Energy's Proxy Statement relating to
the 20022003 Annual Meeting of Shareholders, which will be filed with the SEC not
later than 120 days after December 31, 2001,2002, which information is
incorporated herein by reference.
SECURITY OWNERSHIP OF MANAGEMENT
--------------------------------
Information concerning the security ownership of the Directors and
Executive Officers of UniSource Energy and TEP will be contained under
Security Ownership of Management in UniSource Energy's Proxy Statement
relating to the 20022003 Annual Meeting of Shareholders, which will be filed with
the SEC not later than 120 days after December 31, 2001,2002, which information is
incorporated herein by reference.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Information concerning securities authorized for issuance under equity
compensation plans will be contained under Securities Authorized for Issuance
under Equity Compensation Plans in UniSource Energy's Proxy Statement
relating to the 2003 Annual Meeting of Shareholders, which will be filed with
the SEC not later than 120 days after December 31, 2002, which information is
incorporated herein by reference.
ITEM 13. - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
Information concerning certain relationships and related transactions of
UniSource Energy and TEP will be contained under Transactions with Management
and Others and Compensation Committee Interlocks and Insider Participation in
UniSource Energy's Proxy Statement relating to the 20022003 Annual Meeting of
Shareholders, which will be filed with the SEC not later than 120 days after
December 31, 2001,2002, which information is incorporated herein by reference.
PART IV
ITEM 14. - CONTROLS AND PROCEDURES
- --------------------------------------------------------------------------------
UniSource Energy and TEP have disclosure controls and procedures to
ensure that material information contained in their filings with the SEC is
recorded, processed, summarized and reported on an accurate and timely basis.
The principal executive officer and principal financial officer of UniSource
Energy and TEP have evaluated these disclosure controls and procedures as
defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of
1934, as amended, within 90 days prior to the filing of this report. Based
on such evaluation, the principal executive officer and principal financial
officer of UniSource Energy and TEP have concluded that such disclosure
controls and procedures are effective at ensuring that material information
is recorded, processed, summarized and reported accurately and within the
time periods specified by the SEC's rules and forms. Since such evaluation
there have not been any significant changes in UniSource Energy and TEP's
internal controls, or in other factors that could significantly affect these
controls.
ITEM 15. - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
Page
----
(a) 1. Consolidated Financial Statements as of
----
December 31, 20012002 and 20002001 and for Each
of the Three Years in the Period Ended
December 31, 2001.2002.
UniSource Energy Corporation
----------------------------
Report of Independent Accountants 5355
Consolidated Statements of Income 5456
Consolidated Statements of Cash Flows 5557
Consolidated Balance Sheets 5658
Consolidated Statements of Capitalization 5759
Consolidated Statements of Changes in Stockholders'
Equity 5860
Notes to Consolidated Financial Statements 6466
Tucson Electric Power Company
-----------------------------
Report of Independent Accountants 5355
Consolidated Statements of Income 5961
Consolidated Statements of Cash Flows 6062
Consolidated Balance Sheets 6163
Consolidated Statements of Capitalization 6264
Consolidated Statements of Changes in Stockholders'
Equity 6365
Notes to Consolidated Financial Statements 6466
2. Financial Statement Schedules
Schedule II
Valuation and Qualifying Accounts 101106
3. Exhibits.
Reference is made to the Exhibit Index commencing on page 111.121.
(b) Reports on Form 8-K.
None.UniSource Energy Corporation and Tucson Electric Power Company
--------------------------------------------------------------
- Form 8-K, dated August 9, 2002 (filed August 9, 2002) regarding
Officer Sworn Statements pursuant to Order 4-460 and Section 21
(a)(1) of the Securities Exchange Act of 1934.
- Form 8-K, dated November 25, 2002 (filed November 27, 2002)
regarding the new TEP bank credit agreement.
UniSource Energy Corporation
----------------------------
- Form 8-K, dated October 31, 2002 (filed October 31, 2002) regarding
UniSource Energy Purchase of Citizens Communications Company
Electric Utility Business and Gas Utility Business in Arizona.
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.
UNISOURCE ENERGY CORPORATION
Date: March 7, 200210, 2003 By: /s/Kevin P. Larson
---------------------------------------------------------------------------------
Kevin P. Larson
Vice President and Principal
Financial 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.
Date: March 7, 200210, 2003 /s/ James S. Pignatelli*
-----------------------------------------
James S. Pignatelli
Chairman of the Board, President and
Principal Executive Officer
Date: March 7, 200210, 2003 /s/ Kevin P. Larson
-----------------------------------------
Kevin P. Larson
Principal Financial Officer
Date: March 7, 200210, 2003 /s/ Karen G. Kissinger*
-----------------------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 7, 200210, 2003 /s/ Lawrence J. Aldrich*
-----------------------------------------
Lawrence J. Aldrich
Director
Date: March 7, 200210, 2003 /s/ Larry W. Bickle*
-----------------------------------------
Larry W. Bickle
Director
Date: March 7, 200210, 2003 /s/ Elizabeth T. Bilby*
-----------------------------------------
Elizabeth T. Bilby
Director
Date: March 7, 200210, 2003 /s/ Harold W. Burlingame*
-----------------------------------------
Harold W. Burlingame
Director
Date: March 7, 2002 /s/ Jose L. Canchola*
-----------------------------------------
Jose L. Canchola
Director
Date: March 7, 200210, 2003 /s/ John L. Carter*
-----------------------------------------
John L. Carter
Director
Date: March 7, 200210, 2003 /s/ Daniel W. L. Fessler*
-----------------------------------------
Daniel W. L. Fessler
Director
Date: March 7, 200210, 2003 /s/ Kenneth Handy*
-----------------------------------------
Kenneth Handy
Director
Date: March 7, 200210, 2003 /s/ Warren Y. Jobe*
-----------------------------------------
Warren Y. Jobe
Director
Date: March 7, 2002 /s/ Martha R. Seger*
-----------------------------------------
Martha R. Seger
Director
Date: March 7, 200210, 2003 /s/ H. Wilson Sundt*
-----------------------------------------
H. Wilson Sundt
Director
Date: March 7, 200210, 2003 By: /s/Kevin P. Larson
-----------------------------------------
Kevin P. Larson
as attorney-in-fact for each
of the persons indicated
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.
TUCSON ELECTRIC POWER COMPANY
Date: March 7, 200210, 2003 By: /s/ Kevin P. Larson
-----------------------------------------
Kevin P. Larson
Vice President and Principal
Financial 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.
Date: March 7, 200210, 2003 /s/ James S. Pignatelli*
-----------------------------------------
James S. Pignatelli
Chairman of the Board, President and
Principal Executive Officer
Date: March 7, 200210, 2003 /s/ Kevin P. Larson
-----------------------------------------
Kevin P. Larson
Principal Financial Officer
Date: March 7, 200210, 2003 /s/ Karen G. Kissinger*
-----------------------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 7, 200210, 2003 /s/ Lawrence J. Aldrich*
-----------------------------------------
Lawrence J. Aldrich
Director
Date: March 7, 200210, 2003 /s/ Elizabeth T. Bilby*
-----------------------------------------
Elizabeth T. Bilby
Director
Date: March 7, 200210, 2003 /s/ Harold W. Burlingame*
-----------------------------------------
Harold W. Burlingame
Director
Date: March 7, 200210, 2003 /s/ John L. Carter*
-----------------------------------------
John L. Carter
Director
Date: March 7, 200210, 2003 /s/ Daniel W. L. Fessler*
-----------------------------------------
Daniel W. L. Fessler
Director
Date: March 7, 200210, 2003 /s/ Kenneth Handy*
-----------------------------------------
Kenneth Handy
Director
Date: March 7, 200210, 2003 /s/ Warren Y. Jobe*
-----------------------------------------
Warren Y. Jobe
Director
Date: March 7, 200210, 2003 By: /s/ Martha R. Seger*
-----------------------------------------
Martha R. Seger
Director
Date: March 7, 2002 By: /s/Kevin P. Larson
-----------------------------------------
Kevin P. Larson
as attorney-in-fact for each
of the persons indicated
CERTIFICATION
Pursuant to Section 302 of the Sarbanes-Oxley Act
I, James S. Pignatelli, certify that:
1. I have reviewed this annual report on Form 10-K of UniSource Energy
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 10, 2003 /s/ James S. Pignatelli
-------------- ----------------------------------------------
James S. Pignatelli
Chairman, President, and
Chief Executive Officer
CERTIFICATION
Pursuant to Section 302 of the Sarbanes-Oxley Act
I, Kevin P. Larson, certify that:
1. I have reviewed this annual report on Form 10-K of UniSource Energy
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 10, 2003 /s/ Kevin P. Larson
-------------- ----------------------------------------------
Kevin P. Larson
Vice President, Chief Financial Officer
and Treasurer
CERTIFICATION
Pursuant to Section 302 of the Sarbanes-Oxley Act
I, James S. Pignatelli, certify that:
1. I have reviewed this annual report on Form 10-K of Tucson Electric
Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 10, 2003 /s/ James S. Pignatelli
-------------- ----------------------------------------------
James S. Pignatelli
Chairman, President, and
Chief Executive Officer
CERTIFICATION
Pursuant to Section 302 of the Sarbanes-Oxley Act
I, Kevin P. Larson, certify that:
1. I have reviewed this annual report on Form 10-K of Tucson Electric
Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 10, 2003 /s/ Kevin P. Larson
-------------- ----------------------------------------------
Kevin P. Larson
Vice President, Chief Financial Officer
and Treasurer
EXHIBIT INDEX
*2(a) -- Agreement and Plan of Exchange, dated as of March 20, 1995,
between TEP, UniSource Energy and NCR Holding, Inc.
*3(a) -- Restated Articles of Incorporation of TEP, filed with the ACC
on August 11, 1994, as amended by Amendment to Article Fourth
of the Company's Restated Articles of Incorporation, filed
with the ACC on May 17, 1996. (Form 10-K for year ended
December 31, 1996, File No. 1-
5924--Exhibit1-5924 -- Exhibit 3(a).)
*3(b) -- Bylaws of TEP, as amended May 20, 1994. (Form 10-Q for the
quarter ended June 30, 1994, File No. 1-5924--1-5924 -- Exhibit 3.)
*3(c) -- Amended and Restated Articles of Incorporation of UniSource
Energy. (Form 8-A/A, dated January 30, 1998, File No. 1-13739--Exhibit1-13739
-- Exhibit 2(a).)
*3(d) -- Bylaws of UniSource Energy, as amended December 11, 1997.
(Form 8-A, dated December 23, 1997, File No. 1-
13739--Exhibit1-13739 --
Exhibit 2(b).)
*4(a)(1) -- Indenture dated as of April 1, 1941, to The Chase National
Bank of the City of New York, as Trustee. (Form S-7, File No.
2-59906--Exhibit2-59906 -- Exhibit 2(b)(1).)
*4(a)(2) -- First Supplemental Indenture, dated as of October 1, 1946.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(2).)
*4(a)(3) -- Second Supplemental Indenture dated as of October 1, 1947.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(3).)
*4(a)(4) -- Third Supplemental Indenture, dated as of April 1, 1949.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(4).)
*4(a)(5) -- Fourth Supplemental Indenture, dated as of December 1, 1952.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(5).)
*4(a)(6) -- Fifth Supplemental Indenture, dated as of January 1, 1955.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(6).)
*4(a)(7) -- Sixth Supplemental Indenture, dated as of January 1, 1958.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(7).)
*4(a)(8) -- Seventh Supplemental Indenture, dated as of November 1, 1959.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(8).)
*4(a)(9) -- Eighth Supplemental Indenture, dated as of November 1, 1961.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(9).)
*4(a)(10) -- Ninth Supplemental Indenture, dated as of February 20, 1964.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(10).)
*4(a)(11) -- Tenth Supplemental Indenture, dated as of February 1, 1965.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(11).)
*4(a)(12) -- Eleventh Supplemental Indenture, dated as of February 1, 1966.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(12).)
*4(a)(13) -- Twelfth Supplemental Indenture, dated as of November 1, 1969.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(13).)
*4(a)(14) -- Thirteenth Supplemental Indenture, dated as of January 20,
1970. (Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(14).)
*4(a)(15) -- Fourteenth Supplemental Indenture, dated as of September 1,
1971. (Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(15).)
*4(a)(16) -- Fifteenth Supplemental Indenture, dated as of March 1, 1972.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(16).)
*4(a)(17) -- Sixteenth Supplemental Indenture, dated as of May 1, 1973.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(17).)
*4(a)(18) -- Seventeenth Supplemental Indenture, dated as of November 1,
1975. (Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(18).)
*4(a)(19) -- Eighteenth Supplemental Indenture, dated as of November 1,
1975. (Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(19).)
*4(a)(20) -- Nineteenth Supplemental Indenture, dated as of July 1, 1976.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(20).)
*4(a)(21) -- Twentieth Supplemental Indenture, dated as of October 1, 1977.
(Form S-7, File No. 2-59906--Exhibit2-59906 -- Exhibit 2(b)(21).)
*4(a)(22) -- Twenty-first Supplemental Indenture, dated as of November 1,
1977. (Form 10-K for year ended December 31, 1980, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(v).)
*4(a)(23) -- Twenty-second Supplemental Indenture, dated as of January 1,
1978. (Form 10-K for year ended December 31, 1980, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(w).)
*4(a)(24) -- Twenty-third Supplemental Indenture, dated as of July 1, 1980.
(Form 10-K for year ended December 31, 1980, File No. 1-5924--Exhibit1-5924
-- Exhibit 4(x).)
*4(a)(25) -- Twenty-fourth Supplemental Indenture, dated as of October 1,
1980. (Form 10-K for year ended December 31, 1980, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(y).)
*4(a)(26) -- Twenty-fifth Supplemental Indenture, dated as of April 1,
1981. (Form 10-Q for quarter ended March 31, 1981, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(a).)
*4(a)(27) -- Twenty-sixth Supplemental Indenture, dated as of April 1,
1981. (Form 10-Q for quarter ended March 31, 1981, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(b).)
*4(a)(28) -- Twenty-seventh Supplemental Indenture, dated as of October 1,
1981. (Form 10-Q for quarter ended September 30, 1982, File
No. 1-5924--Exhibit1-5924 -- Exhibit 4(c).)
*4(a)(29) -- Twenty-eighth Supplemental Indenture, dated as of June 1,
1990. (Form 10-Q for quarter ended June 30, 1990, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(a)(1).)
*4(a)(30) -- Twenty-ninth Supplemental Indenture, dated as of December 1,
1992. (Form S-1, Registration No. 33-55732--33-55732 -- Exhibit 4(a)(30).)
*4(a)(31) -- Thirtieth Supplemental Indenture, dated as of December 1,
1992. (Form S-1, Registration No. 33-55732--33-55732 -- Exhibit
4(a)(31).)
*4(a)(32) -- Thirty-first Supplemental Indenture, dated as of May 1, 1996.
(Form 10-K for the year ended December 31, 1996, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(a)(32).)
*4(a)(33) -- Thirty-second Supplemental Indenture, dated as of May 1, 1996.
(Form 10-K for the year ended December 31, 1996, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(a)(33).)
*4(a)(34) -- Thirty-third Supplemental Indenture, dated as of May 1, 1998.
(Form 10-Q for the quarter ended June 30, 1998, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(a).)
*4(a)(35) -- Thirty-fourth Supplemental Indenture dated as of August 1,
1998. (Form 10-Q for the quarter ended June 30, 1998, File
No. 1-5924--Exhibit1-5924 -- Exhibit 4(b).)
*4(b)(1) -- Installment Sale Agreement, dated as of December 1, 1973,
among the City of Farmington, New Mexico, Public Service
Company of New Mexico and TEP. (Form 8-K for the month of
January 1974, File No. 0-269--Exhibit0-269 -- Exhibit 3.)
*4(b)(2) -- Ordinance No. 486, adopted December 17, 1973, of the City of
Farmington, New Mexico. (Form 8-K for the month of January
1974, File No. 0-269--Exhibit0-269 -- Exhibit 4.)
*4(b)(3) -- Amended and Restated Installment Sale Agreement dated as of
April 1, 1997, between the City of Farmington, New Mexico and
TEP relating to Pollution Control Revenue Bonds, 1997 Series A
(Tucson Electric Power Company San Juan Project). (Form 10-Q
for the quarter ended March 31, 1997, File No. 1-5924--Exhibit1-5924
-- Exhibit 4(a).)
*4(b)(4) -- City of Farmington, New Mexico Ordinance No. 97-
1055,97-1055, adopted
April 17, 1997, authorizing Pollution Control Revenue Bonds,
1997 Series A (Tucson Electric Power Company San Juan
Project). (Form 10-Q for the quarter ended March 31, 1997,
File No. 1-5924--Exhibit1-5924 -- Exhibit 4(b).)
*4(c)(1) -- Loan Agreement, dated as of October 1, 1982, between the Pima
County Authority and TEP relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A
(Tucson Electric Power Company Irvington Project). (Form 10-Q
for the quarter ended September 30, 1982, File No. 1-5924--Exhibit1-5924
-- Exhibit 4(a).)
*4(c)(2) -- Indenture of Trust, dated as of October 1, 1982, between the
Pima County Authority and Morgan Guaranty authorizing Floating
Rate Monthly Demand Industrial Development Revenue Bonds, 1982
Series A (Tucson Electric Power Company Irvington Project).
(Form 10-Q for the quarter ended September 30, 1982, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(b).)
*4(c)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and TEP relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Irvington Project). (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 4(h)(3).)
*4(c)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty
relating to Industrial Development Revenue Bonds, 1982 Series
A (Tucson Electric Power Company Irvington Project). (Form S-4,S-
4, Registration No. 33-52860--33-52860 -- Exhibit 4(h)(4).)
*4(d)(1) -- Loan Agreement, dated as of December 1, 1982, between the Pima
County Authority and TEP relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A
(Tucson Electric Power Company Projects). (Form 10-K for the
year ended December 31, 1982, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(k)(1).)
*4(d)(2) -- Indenture of Trust, dated as of December 1, 1982, between the
Pima County Authority and Morgan Guaranty authorizing Floating
Rate Monthly Demand Industrial Development Revenue Bonds, 1982
Series A (Tucson Electric Power Company Projects). (Form 10-K
for the year ended December 31, 1982, File No. 1-5924--Exhibit1-5924
-- Exhibit 4(k)(2).)
*4(d)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and TEP relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Projects). (Form S-
4,S-4, Registration No.
33-52860--Exhibit33-52860 -- Exhibit 4(i)(3).)
*4(d)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty
relating to Industrial Development Revenue Bonds, 1982 Series
A (Tucson Electric Power Company Projects). (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 4(i)(4).)
*4(e)(1) -- Loan Agreement, dated as of December 1, 1983, between the
Apache County Authority and TEP relating to Floating Rate
Monthly Demand Industrial Development Revenue Bonds, 1983
Series A (Tucson Electric Power Company Springerville
Project). (Form 10-K for the year ended December 31, 1983,
File No. 1-5924--Exhibit1-5924 -- Exhibit 4(l)(1).)
*4(e)(2) -- Indenture of Trust, dated as of December 1, 1983, between the
Apache County Authority and Morgan Guaranty authorizing
Floating Rate Monthly Demand Industrial Development Revenue
Bonds, 1983 Series A (Tucson Electric Power Company
Springerville Project). (Form 10-K for the year ended
December 31, 1983, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(l)(2).)
*4(e)(3) -- First Supplemental Loan Agreement, dated as of December 1,
1985, between the Apache County Authority and TEP relating to
Floating Rate Monthly Demand Industrial Development Revenue
Bonds, 1983 Series A (Tucson Electric Power Company
Springerville Project). (Form 10-K for the year ended
December 31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(k)(3).)
*4(e)(4) -- First Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty
relating to Floating Rate Monthly Demand Industrial
Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company Springerville Project). (Form 10-K for the year
ended December 31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(k)(4).)
*4(e)(5) -- Second Supplemental Loan Agreement, dated as of March 31,
1992, between the Apache County Authority and TEP relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 4(k)(5).)
*4(e)(6) -- Second Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty
relating to Industrial Development Revenue Bonds, 1983 Series
A (Tucson Electric Power Company Springerville Project).
(Form S-4, Registration No. 33-
52860--Exhibit33-52860 -- Exhibit 4(k)(6).)
*4(f)(1) -- Loan Agreement, dated as of December 1, 1983, between the
Apache County Authority and TEP relating to Variable Rate
Demand Industrial Development Revenue Bonds, 1983 Series B
(Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1983, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(m)(1).)
*4(f)(2) -- Indenture of Trust, dated as of December 1, 1983, between the
Apache County Authority and Morgan Guaranty authorizing
Variable Rate Demand Industrial Development Revenue Bonds,
1983 Series B (Tucson Electric Power Company Springerville
Project). (Form 10-K for the year ended December 31, 1983,
File No. 1-5924--Exhibit1-5924 -- Exhibit 4(m)(2).)
*4(f)(3) -- First Supplemental Loan Agreement, dated as of December 1,
1985, between the Apache County Authority and TEP relating to
Floating Rate Monthly Demand Industrial Development Revenue
Bonds, 1983 Series B (Tucson Electric Power Company
Springerville Project). (Form 10-K for the year ended
December 31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(l)(3).)
*4(f)(4) -- First Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty
relating to Floating Rate Monthly Demand Industrial
Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form 10-K for the year
ended December 31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(l)(4).)
*4(f)(5) -- Second Supplemental Loan Agreement, dated as of March 31,
1992, between the Apache County Authority and TEP relating to
Industrial Development Revenue Bonds, 1983 Series B (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 4(l)(5).)
*4(f)(6) -- Second Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty
relating to Industrial Development Revenue Bonds, 1983 Series
B (Tucson Electric Power Company Springerville Project).
(Form S-4, Registration No. 33-
52860--Exhibit33-52860 -- Exhibit 4(l)(6).)
*4(g)(1) -- Loan Agreement, dated as of December 1, 1983, between the
Apache County Authority and TEP relating to Variable Rate
Demand Industrial Development Revenue Bonds, 1983 Series C
(Tucson Electric Power Company Springerville Project). (Form
10-K for year ended December 31, 1983, File No. 1-5924--Exhibit1-5924
-- Exhibit 4(n)(1).)
*4(g)(2) -- Indenture of Trust, dated as of December 1, 1983, between the
Apache County Authority and Morgan Guaranty authorizing
Variable Rate Demand Industrial Development Revenue Bonds,
1983 Series C (Tucson Electric Power Company Springerville
Project). (Form 10-K for the year ended December 31, 1983,
File No. 1-5924--Exhibit1-5924 -- Exhibit 4(n)(2).)
*4(g)(3) -- First Supplemental Loan Agreement, dated as of December 1,
1985, between the Apache County Authority and TEP relating to
Floating Rate Monthly Demand Industrial Development Revenue
Bonds, 1983 Series C (Tucson Electric Power Company
Springerville Project). (Form 10-K for the year ended
December 31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(m)(3).)
*4(g)(4) -- First Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty
relating to Floating Rate Monthly Demand Industrial
Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form 10-K for the year
ended December 31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(m)(4).)
*4(g)(5) -- Second Supplemental Loan Agreement, dated as of March 31,
1992, between the Apache County Authority and TEP relating to
Industrial Development Revenue Bonds, 1983 Series C (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 4(m)(5).)
*4(g)(6) -- Second Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty
relating to Industrial Development Revenue Bonds, 1983 Series
C (Tucson Electric Power Company Springerville Project).
(Form S-4, Registration No. 33-
52860--Exhibit33-52860 -- Exhibit 4(m)(6).)
*4(h) -- Reimbursement Agreement, dated as of September 15, 1981, as
amended, between TEP and Manufacturers Hanover Trust Company.
(Form 10-K for the year ended December 31, 1984, File No.
1-5924--Exhibit1-5924 -- Exhibit 4(o)(4).)
*4(i)(1) -- Loan Agreement, dated as of December 1, 1985, between the
Apache County Authority and TEP relating to Variable Rate
Demand Industrial Development Revenue Bonds, 1985 Series A
(Tucson Electric Power Company Springerville Project). (Form
10-K for the year ended December 31, 1985, File No. 1-5924--Exhibit1-5924
-- Exhibit 4(r)(1).)
*4(i)(2) -- Indenture of Trust, dated as of December 1, 1985, between the
Apache County Authority and Morgan Guaranty authorizing
Variable Rate Demand Industrial Development Revenue Bonds,
1985 Series A (Tucson Electric Power Company Springerville
Project). (Form 10-K for the year ended December 31, 1985,
File No. 1-5924--Exhibit1-5924 -- Exhibit 4(r)(2).)
*4(i)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and TEP relating to
Industrial Development Revenue Bonds, 1985 Series A (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 4(o)(3).)
*4(i)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty
relating to Industrial Development Revenue Bonds, 1985 Series
A (Tucson Electric Power Company Springerville Project).
(Form S-4, Registration No. 33-
52860--Exhibit33-52860 -- Exhibit 4(o)(4).)
*4(j)(1) -- Warrant Agreement and Form of Warrant, dated as of
December 15, 1992. (Form S-1, Registration No. 33-55732--
Exhibit 4(q).)
*4(j)(2) -- Form of Warrant Agreement relating to the UniSource
Energy Warrants, dated as of August 4, 1998. (Form S-4,
Registration No. 333-60809--Exhibit 4(a).)
*4(k)(1) -- Indenture of Mortgage and Deed of Trust dated as of December
1, 1992, to Bank of Montreal Trust Company, Trustee. (Form
S-1, Registration No. 33-55732--Exhibit33-55732 -- Exhibit 4(r)(1).)
*4(k)*4(j)(2) -- Supplemental Indenture No. 1 creating a series of bonds
designated Second Mortgage Bonds, Collateral Series A, dated
as of December 1, 1992. (Form S-1, Registration No. 33-55732--Exhibit33-55732
-- Exhibit 4(r)(2).)
*4(k)*4(j)(3) -- Supplemental Indenture No. 2 creating a series of bonds
designated Second Mortgage Bonds, Collateral Series B, dated
as of December 1, 1997. (Form 10-K for year ended December
31, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(m)(3).)
*4(k)*4(j)(4) -- Supplemental Indenture No. 3 creating a series of bonds
designated Second Mortgage Bonds, Collateral Series, dated as
of August 1, 1998. (Form 10-Q for the quarter ended June 30,
1998, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(c).)
*4(l)*4(j)(5) -- Supplemental Indenture No. 4 creating a series of bonds
designated Second Mortgage Bonds, Collateral Series C, dated
as of November 1, 2002. (Form 8-K dated November 27, 2002,
File Nos. 1-05924 and 1-13739 -- Exhibit 99.2.)
*4(k)(1) -- Loan Agreement, dated as of April 1, 1997, between Coconino
County, Arizona Pollution Control Corporation and TEP relating
to Pollution Control Revenue Bonds, 1997 Series A (Tucson
Electric Power Company Navajo Project). (Form 10-Q for the
quarter ended March 31, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(c).)
*4(l)*4(k)(2) -- Indenture of Trust, dated as of April 1, 1997, between
Coconino County, Arizona Pollution Control Corporation and
First Trust of New York, National Association, authorizing
Pollution Control Revenue Bonds, 1997 Series A (Tucson
Electric Power Company Navajo Project). (Form 10-Q for the
quarter ended March 31, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(d).)
*4(m)*4(l)(1) -- Loan Agreement, dated as of April 1, 1997, between Coconino
County, Arizona Pollution Control Corporation and TEP relating
to Pollution Control Revenue Bonds, 1997 Series B (Tucson
Electric Power Company Navajo Project). (Form 10-Q for the
quarter ended March 31, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(e).)
*4(m)*4(l)(2) -- Indenture of Trust, dated as of April 1, 1997, between
Coconino County, Arizona Pollution Control Corporation and
First Trust of New York, National Association, authorizing
Pollution Control Revenue Bonds, 1997 Series B (Tucson
Electric Power Company Navajo Project). (Form 10-Q for the
quarter ended March 31, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(f).)
*4(n)*4(m)(1) -- Loan Agreement, dated as of September 15, 1997, between The
Industrial Development Authority of the County of Pima and TEP
relating to Industrial Development Revenue Bonds, 1997 Series
A (Tucson Electric Power Company Project). (Form 10-Q for the
quarter ended September 30, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(a).)
*4(n)*4(m)(2) -- Indenture of Trust, dated as of September 15, 1997, between
The Industrial Development Authority of the County of Pima and
First Trust of New York, National Association, authorizing
Industrial Development Revenue Bonds, 1997 Series A (Tucson
Electric Power Company Project). (Form 10-Q for the quarter
ended September 30, 1997, File No. 1-
5924--Exhibit1-5924 -- Exhibit 4(b).)
*4(o)*4(n)(1) -- Loan Agreement, dated as of September 15, 1997, between The
Industrial Development Authority of the County of Pima and TEP
relating to Industrial Development Revenue Bonds, 1997 Series
B (Tucson Electric Power Company Project). (Form 10-Q for the
quarter ended September 30, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(c).)
*4(o)*4(n)(2) -- Indenture of Trust, dated as of September 15, 1997, between
The Industrial Development Authority of the County of Pima and
First Trust of New York, National Association, authorizing
Industrial Development Revenue Bonds, 1997 Series B (Tucson
Electric Power Company Project). (Form 10-Q for the quarter
ended September 30, 1997, File No. 1-
5924--Exhibit1-5924 -- Exhibit 4(d).)
*4(p)*4(o)(1) -- Loan Agreement, dated as of September 15, 1997, between The
Industrial Development Authority of the County of Pima and TEP
relating to Industrial Development Revenue Bonds, 1997 Series
C (Tucson Electric Power Company Project). (Form 10-Q for the
quarter ended September 30, 1997, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(e).)
*4(p)*4(o)(2) -- Indenture of Trust, dated as of September 15, 1997, between
The Industrial Development Authority of the County of Pima and
First Trust of New York, National Association, authorizing
Industrial Development Revenue Bonds, 1997 Series C (Tucson
Electric Power Company Project). (Form 10-Q for the quarter
ended September 30, 1997, File No. 1-
5924--Exhibit1-5924 -- Exhibit 4(f).)
*4(q)*4(p)(1) -- Loan Agreement, dated as of March 1, 1998, between The
Industrial Development Authority of the County of Apache and
TEP relating to Pollution Control Revenue Bonds, 1998 Series A
(Tucson Electric Power Company Project). (Form 10-Q for the
quarter ended March 31, 1998, File No. 1-5924--Exhibit1-5924 -- Exhibit
4(a).)
*4(q)*4(p)(2) -- Indenture of Trust, dated as of March 1, 1998, between The
Industrial Development Authority of the County of Apache and
First Trust of New York, National Association, authorizing
Pollution Control Revenue Bonds, 1998 Series A (Tucson
Electric Power Company Project). (Form 10-Q for the quarter
ended March 31, 1998, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(b).)
*4(r)*4(q)(1) -- Loan Agreement, dated as of March 1, 1998, between The
Industrial Development Authority of the County of Apache and
TEP relating to Pollution Control Revenue Bonds, 1998 Series B
(Tucson Electric Power Company Project). (Form 10-Q for the
quarter ended March 31, 1998, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(c).)
*4(r)*4(q)(2) -- Indenture of Trust, dated as of March 1, 1998, between The
Industrial Development Authority of the County of Apache and
First Trust of New York, National Association, authorizing
Pollution Control Revenue Bonds, 1998 Series B (Tucson
Electric Power Company Project). (Form 10-Q for the quarter
ended March 31, 1998, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(d).)
*4(s)*4(r)(1) -- Loan Agreement, dated as of March 1, 1998, between The
Industrial Development Authority of the County of Apache and
TEP relating to Industrial Development Revenue Bonds, 1998
Series C (Tucson Electric Power Company Project). (Form 10-Q
for the quarter ended March 31, 1998, File No. 1-5924
--- Exhibit 4(e).)
*4(s)*4(r)(2) -- Indenture of Trust, dated as of March 1, 1998, between The
Industrial Development Authority of the County of Apache and
First Trust of New York, National Association, authorizing
Industrial Development Revenue Bonds, 1998 Series C (Tucson
Electric Power Company Project). (Form 10-Q for the quarter
ended March 31, 1998, File No. 1-5924--Exhibit1-5924 -- Exhibit 4(f).)
*4(t)*4(s)(1) -- Indenture of Trust, dated as of August 1, 1998, between TEP
and the Bank of Montreal Trust Company. (Form 10-Q for the
quarter ended June 30, 1998, File No. 1-5924 --Exhibit-- Exhibit 4(d).)
*4(u)*4(t)(1) -- Rights Agreement dated as of March 5, 1999, between UniSource
Energy Corporation and The Bank of New York, as Rights Agent.
(Form 8-K dated March 5, 1999, File No. 1-
13739--Exhibit1-13739 -- Exhibit
4.)
*10(a)(1) -- Lease Agreements, dated as of December 1, 1984, between
Valencia and United States Trust Company of New York, as
Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended
and supplemented. (Form 10-K for the year ended December 31,
1984, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(d)(1).)
*10(a)(2) -- Guaranty and Agreements, dated as of December 1, 1984, between
TEP and United States Trust Company of New York, as Trustee,
and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the
year ended December 31, 1984, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(d)(2).)
*10(a)(3) -- General Indemnity Agreements, dated as of December 1, 1984,
between Valencia and TEP, as Indemnitors; General Foods Credit
Corporation, Harvey Hubbell Financial, Inc. and J.C.J. C. Penney
Company, Inc. as Owner Participants; United States Trust
Company of New York, as Owner Trustee; Teachers Insurance and
Annuity Association of America as Loan Participant; and Marine
Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the
year ended December 31, 1984, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(d)(3).)
*10(a)(4) -- Tax Indemnity Agreements, dated as of December 1, 1984,
between General Foods Credit Corporation, Harvey Hubbell
Financial, Inc. and J.C.J. C. Penney Company, Inc., each as
Beneficiary under a separate Trust Agreement dated December 1,
1984, with United States Trust of New York as Owner Trustee,
and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia,
Lessee, and TEP, Indemnitors. (Form 10-K for the year ended
December 31, 1984, File No. 1-5924 --Exhibit-- Exhibit 10(d)(4).)
*10(a)(5) -- Amendment No. 1, dated December 31, 1984, to the Lease
Agreements, dated December 1, 1984, between Valencia and
United States Trust Company of New York, as Owner Trustee, and
Thomas B. Zakrzewski as Co-Trustee. (Form 10-
K10-K for the year
ended December 31, 1986, File No. 1-5924--1-5924 -- Exhibit 10(e)(5).)
*10(a)(6) -- Amendment No. 2, dated April 1, 1985, to the Lease Agreements,
dated December 1, 1984, between Valencia and United States
Trust Company of New York, as Owner Trustee, and Thomas B.
Zakrzewski as Co-Trustee. (Form 10-K for the year ended
December 31, 1986, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(6).)
*10(a)(7) -- Amendment No. 3, dated August 1, 1985, to the Lease
Agreements, dated December 1, 1984, between Valencia and
United States Trust Company of New York, as Owner Trustee, and
Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year
ended December 31, 1986, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(7).)
*10(a)(8) -- Amendment No. 4, dated June 1, 1986, to the Lease Agreement,
dated December 1, 1984, between Valencia and United States
Trust Company of New York as Owner Trustee, and Thomas
Zakrzewski as Co-Trustee, under a Trust Agreement dated as of
December 1, 1984, with General Foods Credit Corporation as
Owner Participant. (Form 10-K for the year ended December 31,
1986, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(8).)
*10(a)(9) -- Amendment No. 4, dated June 1, 1986, to the Lease Agreement,
dated December 1, 1984, between Valencia and United States
Trust Company of New York as Owner Trustee, and Thomas
Zakrzewski as Co-Trustee, under a Trust Agreement dated as of
December 1, 1984, with J.C.J. C. Penney Company, Inc. as Owner
Participant. (Form 10-K for the year ended December 31, 1986,
File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(9).)
*10(a)(10) -- Amendment No. 4, dated June 1, 1986, to the Lease Agreement,
dated December 1, 1984, between Valencia and United States
Trust Company of New York as Owner Trustee, and Thomas
Zakrzewski as Co-Trustee, under a Trust Agreement dated as of
December 1, 1984, with Harvey Hubbell Financial Inc. as Owner
Participant. (Form 10-K for the year ended December 31, 1986,
File No. 1-5924--1-5924 -- Exhibit 10(e)(10).)
*10(a)(11) -- Lease Amendment No. 5 and Supplement No. 2, to the Lease
Agreement, dated July 1, 1986, between Valencia, United States
Trust Company of New York as Owner Trustee, and Thomas
Zakrzewski as Co-Trustee and J.C.J. C. Penney Company,
Inc., as Owner
Participant. (Form 10-K for the year ended December 31, 1986,
File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(11).)
*10(a)(12) -- Lease Amendment No. 5, to the Lease Agreement, dated June 1,
1987, between Valencia, United States Trust Company of New
York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and
General Foods Credit Corporation as Owner Participant. (Form
10-K for the year ended December 31, 1988, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(f)(12).)
*10(a)(13) -- Lease Amendment No. 5, to the Lease Agreement, dated June 1,
1987, between Valencia, United States Trust Company of New
York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and
Harvey Hubbell Financial Inc. as Owner Participant. (Form
10-K for the year ended December 31, 1988, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(f)(13).)
*10(a)(14) -- Lease Amendment No. 6, to the Lease Agreement, dated June 1,
1987, between Valencia, United States Trust Company of New
York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and
J.C.J. C. Penney Company, Inc. as Owner Participant. (Form 10-K
for the year ended December 31, 1988, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(f)(14).)
*10(a)(15) -- Lease Supplement No. 1, dated December 31, 1984, to Lease
Agreements, dated December 1, 1984, between Valencia, as
Lessee and United States Trust Company of New York and Thomas
B. Zakrzewski, as Owner Trustee and Co-
Trustee,Co-Trustee, respectively
(document filed relates to General Foods Credit Corporation;
documents relating to Harvey Hubbel Financial, Inc. and J.C.JC
Penney Company, Inc. are not filed but are substantially
similar). (Form S-4, Registration No. 33-52860--Exhibit33-52860 -- Exhibit
10(f)(15).)
*10(a)(16) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity
Agreement, dated as of December 1, 1984, between Valencia and
TEP, as Indemnitors, General Foods Credit Corporation, as
Owner Participant, United States Trust Company of New York, as
Owner Trustee, Teachers Insurance and Annuity Association of
America, as Loan Participant, and Marine Midland Bank, N.A.,
as Indenture Trustee. (Form 10-K for the year ended December
31, 1986, File No. 1-5924 --Exhibit-- Exhibit 10(e)(12).)
*10(a)(17) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity
Agreement, dated as of December 1, 1984, between Valencia and
TEP, as Indemnitors, J.C.J. C. Penney Company, Inc., as Owner
Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of
America, as Loan Participant, and Marine Midland Bank, N.A.,
as Indenture Trustee. (Form 10-K for the year ended December
31, 1986, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(13).)
*10(a)(18) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity
Agreement, dated as of December 1, 1984, between Valencia and
TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner
Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of
America, as Loan Participant, and Marine Midland Bank, N.A.,
as Indenture Trustee. (Form 10-K for the year ended December
31, 1986, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(e)(14).)
*10(a)(19) -- Amendment No. 2, dated as of July 1, 1986, to the General
Indemnity Agreement, dated as of December 1, 1984, between
Valencia and TEP, as Indemnitors, J.C.J. C. Penney Company, Inc.,
as Owner Participant, United States Trust Company of New York,
as Owner Trustee, Teachers Insurance and Annuity Association
of America, as Loan Participant, and Marine Midland Bank,
N.A., as Indenture Trustee. (Form S-4, Registration No.
33-52860--Exhibit33-52860 -- Exhibit 10(f)(19).)
*10(a)(20) -- Amendment No. 2, dated as of June 1, 1987, to the General
Indemnity Agreement, dated as of December 1, 1984, between
Valencia and TEP, as Indemnitors, General Foods Credit
Corporation, as Owner Participant, United States Trust Company
of New York, as Owner Trustee, Teachers Insurance and Annuity
Association of America, as Loan Participant, and Marine
Midland Bank, N.A., as Indenture Trustee. (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 10(f)(20).)
*10(a)(21) -- Amendment No. 2, dated as of June 1, 1987, to the General
Indemnity Agreement, dated as of December 1, 1984, between
Valencia and TEP, as Indemnitors, Harvey Hubbell Financial,
Inc., as Owner Participant, United States Trust Company of New
York, as Owner Trustee, Teachers Insurance and Annuity
Association of America, as Loan Participant, and Marine
Midland Bank, N.A., as Indenture Trustee. (Form S-4,
Registration No. 33-52860--Exhibit33-52860 -- Exhibit 10(f)(21).)
*10(a)(22) -- Amendment No. 3, dated as of June 1, 1987, to the General
Indemnity Agreement, dated as of December 1, 1984, between
Valencia and TEP, as Indemnitors, J.C.J. C. Penney Company, Inc.,
as Owner Participant, United States Trust Company of New York,
as Owner Trustee, Teachers Insurance and Annuity Association
of America, as Loan Participant, and Marine Midland Bank,
N.A., as Indenture Trustee. (Form S-4, Registration No.
33-52860--Exhibit33-52860 -- Exhibit 10(f)(22).)
*10(a)(23) -- Supplemental Tax Indemnity Agreement, dated July 1, 1986,
between J.C.J. C. Penney Company, Inc., as Owner Participant, and
Valencia and TEP, as Indemnitors. (Form 10-K for the year
ended December 31, 1986, File No. 1-5924 --Exhibit-- Exhibit
10(e)(15).)
*10(a)(24) -- Supplemental General Indemnity Agreement, dated as of July 1,
1986, among Valencia and TEP, as Indemnitors, J.C.J. C. Penney
Company, Inc., as Owner Participant, United States Trust
Company of New York, as Owner Trustee, Teachers Insurance and
Annuity Association of America, as Loan Participant, and
Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K
for the year ended December 31, 1986, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(e)(16).)
*10(a)(25) -- Amendment No. 1, dated as of June 1, 1987, to the Supplemental
General Indemnity Agreement, dated as of July 1, 1986, among
Valencia and TEP, as Indemnitors, J.C.J. C. Penney Company, Inc.,
as Owner Participant, United States Trust Company of New York,
as Owner Trustee, Teachers Insurance and Annuity Association
of America, as Loan Participant, and Marine Midland Bank,
N.A., as Indenture Trustee. (Form S-4, Registration No.
33-52860--Exhibit33-52860 -- Exhibit 10(f)(25).)
*10(a)(26) -- Valencia Agreement, dated as of June 30, 1992, among TEP, as
Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity
Association of America, as Loan Participant, Marine Midland
Bank, N.A., as Indenture Trustee, United States Trust Company
of New York, as Owner Trustee, and Thomas B. Zakrzewski, as
Co-Trustee, and the Owner Participants named therein relating
to the Restructuring of Valencia's lease of the coal-handling
facilities at the Springerville Generating Station. (Form
S-4, Registration No. 33-52860--Exhibit33-52860 -- Exhibit 10(f)(26).)
*10(a)(27) -- Amendment, dated as of December 15, 1992, to the Lease
Agreements, dated December 1, 1984, between Valencia, as
Lessee, and United States Trust Company of New York, as Owner
Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1,
Registration No. 33-55732--Exhibit33-55732 -- Exhibit 10(f)(27).)
*10(b)(1) -- Lease Agreements, dated as of December 1, 1985, between TEP
and San Carlos Resources Inc. (San Carlos) (a(a wholly-owned
subsidiary of the Registrant) jointly and severally, as Lessee,
and Wilmington Trust Company, as Trustee, as amended and
supplemented. (Form 10-K for the year ended December 31,
1985, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(f)(1).)
*10(b)(2) -- Tax Indemnity Agreements, dated as of December 1, 1985,
between Philip Morris Credit Corporation, IBM Credit Financing
Corporation and Emerson Finance Co., each as beneficiary under
a separate trust agreement, dated as of December 1, 1985, with
Wilmington Trust Company, as Owner Trustee, and William J.
Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form
10-K for the year ended December 31, 1985, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(f)(2).)
*10(b)(3) -- Participation Agreement, dated as of December 1, 1985, among
TEP and San Carlos as Lessee, Philip Morris Credit
Corporation, IBM Credit Financing Corporation, and Emerson
Finance Co. as Owner Participants, Wilmington Trust Company as
Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as
Loan Participant, and Bankers Trust Company, as Indenture
Trustee. (Form 10-K for the year ended December 31, 1985,
File No. 1-5924--Exhibit1-5924 -- Exhibit 10(f)(3).)
*10(b)(4) -- Restructuring Commitment Agreement, dated as of June 30, 1992,
among TEP and San Carlos, jointly and severally, as Lessee,
Philip Morris Credit Corporation, IBM Credit Financing
Corporation and Emerson Capital Funding, William J. Wade, as
Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank,
Limited, New York Branch, as Loan Participant and United
States Trust Company of New York, as Indenture Trustee. (Form
S-4, Registration No. 33-
52860--Exhibit33-52860 -- Exhibit 10(g)(4).)
*10(b)(5) -- Lease Supplement No. 1, dated December 31, 1985, to Lease
greements,Agreements, dated as of December 1, 1985, between TEP and San
Carlos, jointly and severally, as Lessee Trustee and
Co-Trustee, respectively (document filed relates to Philip
Morris Credit Corporation; documents relating to IBM Credit
Financing Corporation and Emerson Financing Co. are not filed
but are substantially similar). (Form S-4, Registration No.
33-52860--Exhibit33-52860 -- Exhibit 10(g)(5).)
*10(b)(6) -- Amendment No. 1, dated as of December 15, 1992, to Lease
Agreements, dated as of December 1, 1985, between TEP and San
Carlos, jointly and severally, as Lessee, and Wilmington Trust
Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, as Lessor. (Form S-
1,S-1, Registration No. 33-55732--Exhibit33-55732
-- Exhibit 10(g)(6).)
*10(b)(7) -- Amendment No. 1, dated as of December 15, 1992, to Tax
Indemnity Agreements, dated as of December 1, 1985, between
Philip Morris Credit Corporation, IBM Credit Financing
Corporation and Emerson Capital Funding Corp., as Owner
Participants and TEP and San Carlos, jointly and severally, as
Lessee. (Form S-1, Registration No. 33-
55732--Exhibit33-55732 -- Exhibit
10(g)(7).)
*10(b)(8) -- Amendment No. 2, dated as of December 1, 1999, to Lease
Agreement, dated as of December 1, 1985, between TEP and San
Carlos, jointly and severally, as Lessee, and Wilmington Trust
Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, under a Trust Agreement with Philip Morris
Capital Corporation as Owner Participant. (Form 10-K for the
year ended December 31, 1999, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(b)(8).)
*10(b)(9) -- Amendment No. 2, dated as of December 1, 1999, to Lease
Agreement, dated as of December 1, 1985, between TEP and San
Carlos, jointly and severally, as Lessee, and Wilmington Trust
Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, under a Trust Agreement with IBM Credit
Financing Corporation as Owner Participant. (Form 10-K for
the year ended December 31, 1999, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(b)(9).)
*10(b)(10) -- Amendment No. 2, dated as of December 1, 1999, to Lease
Agreement, dated as of December 1, 1985, between TEP and San
Carlos, jointly and severally, as Lessee, and Wilmington
Trust Company and William J. Wade, as Owner Trustee and
Co-Trustee, respectively, under a Trust Agreement with
Emerson Finance Co. as Owner Participant. (Form 10-K for the
year ended December 31, 1999, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(b)(10).)
*10(b)(11) -- Amendment No. 2, dated as of December 1, 1999, to Tax
Indemnity Agreement, dated as of December 1, 1985, between TEP
and San Carlos, jointly and severally, as Lessee, and Philip
Morris Capital Corporation as Owner Participant, beneficiary
under a Trust Agreement dated as of December 1, 1985, with
Wilmington Trust Company and William J. Wade, as Owner Trustee
and Co-Trustee, respectively, together as Lessor. (Form 10-K
for the year ended December 31, 1999, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(b)(11).)
*10(b)(12) -- Amendment No. 2, dated as of December 1, 1999, to Tax
Indemnity Agreement, dated as of December 1, 1985, between TEP
and San Carlos, jointly and severally, as Lessee, and IBM
Credit Financing Corporation as Owner Participant, beneficiary
under a Trust Agreement dated as of December 1, 1985, with
Wilmington Trust Company and William J. Wade, as Owner Trustee
and Co-Trustee, respectively, together as Lessor. (Form 10-K
for the year ended December 31, 1999, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(b)(12).)
*10(b)(13) -- Amendment No. 2, dated as of December 1, 1999, to Tax
Indemnity Agreement, dated as of December 1, 1985, between TEP
and San Carlos, jointly and severally, as Lessee, and Emerson
Finance Co. as Owner Participant, beneficiary under a Trust
Agreement dated as of December 1, 1985, with Wilmington Trust
Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, together as Lessor. (Form 10-K for the year
ended December 31, 1999, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(b)(13).)
*10(c)(1) -- Amended and Restated Participation Agreement, dated as of
November 15, 1987, among TEP, as Lessee, Ford Motor Credit
Company, as Owner Participant, Financial Security Assurance
Inc., as Surety, Wilmington Trust Company and William J. Wade
in their respective individual capacities as provided therein,
but otherwise solely as Owner Trustee and Co-Trustee under the
Trust Agreement, and Morgan Guaranty, in its individual
capacity as provided therein, but Secured Party. (Form 10-K
for the year ended December 31, 1987, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(j)(1).)
*10(c)(2) -- Lease Agreement, dated as of January 14, 1988, between
Wilmington Trust Company and William J. Wade, as Owner Trust
Agreement described therein, dated as of November 15, 1987,
between such parties and Ford Motor Credit Company, as Lessor,
and TEP, as Lessee. (Form 10-K for the year ended December
31, 1987, File No. 1-5924--1-5924 -- Exhibit 10(j)(2).)
*10(c)(3) -- Tax Indemnity Agreement, dated as of January 14, 1988, between
TEP, as Lessee, and Ford Motor Credit Company, as Owner
Participant, beneficiary under a Trust Agreement, dated as of
November 15, 1987, with Wilmington Trust Company and William
J. Wade, Owner Trustee and Co-
Trustee,Co-Trustee, respectively, together
as Lessor. (Form 10-K for the year ended December 31, 1987,
File No. 1-5924--Exhibit1-5924 -- Exhibit 10(j)(3).)
*10(c)(4) -- Loan Agreement, dated as of January 14, 1988, between the Pima
County Authority and Wilmington Trust Company and William J.
Wade in their respective individual capacities as expressly
stated, but otherwise solely as Owner Trustee and Co-Trustee,
respectively, under and pursuant to a Trust Agreement, dated
as of November 15, 1987, with Ford Motor Credit Company as
Trustor and Debtor relating to Industrial Development Lease
Obligation Refunding Revenue Bonds, 1988 Series A (TEP's
Irvington Project). (Form 10-K for the year ended December
31, 1987, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(j)(4).)
*10(c)(5) -- Indenture of Trust, dated as of January 14, 1988, between the
Pima County Authority and Morgan Guaranty authorizing
Industrial Development Lease Obligation Refunding Revenue
Bonds, 1988 Series A (Tucson Electric Power Company Irvington
Project). (Form 10-K for the year ended December 31, 1987,
File No. 1-5924--Exhibit1-5924 -- Exhibit 10(j)(5).)
*10(c)(6) -- Lease Amendment No. 1, dated as of May 1, 1989, between TEP,
Wilmington Trust Company and William J. Wade as Owner Trustee
and Co-trustee, respectively under a Trust Agreement dated as
of November 15, 1987 with Ford Motor Credit Company. (Form
10-K for the year ended December 31, 1990, File No. 1-5924--Exhibit1-5924
-- Exhibit 10(i)(6).)
*10(c)(7) -- Lease Supplement, dated as of January 1, 1991, between TEP,
Wilmington Trust Company and William J. Wade as Owner Trustee
and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10K10-K for the year
ended December 31, 1991, File No. 1-
5924--Exhibit1-5924 -- Exhibit 10(i)(8).)
*10(c)(8) -- Lease Supplement, dated as of March 1, 1991, between TEP,
Wilmington Trust Company and William J. Wade as Owner Trustee
and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10-K for the year
ended December 31, 1991, File No. 1-5924--Exhibit1-5924 -- Exhibit 10(i)(9).)
*10(c)(9) -- Lease Supplement No. 4, dated as of December 1, 1991, between
TEP, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement
dated as of November 15, 1987, with Ford. (Form 10-K for the
year ended December 31, 1991, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(i)(10).)
*10(c)(10) -- Supplemental Indenture No. 1, dated as of December 1, 1991,
between the Pima County Authority and Morgan Guaranty relating
to Industrial Lease Development Obligation Revenue Project).Project.
(Form 10-K for the year ended December 31, 1991, File No.
1-5924--Exhibit 10(I)1-5924 -- Exhibit 10(i)(11).)
*10(c)(11) -- Restructuring Commitment Agreement, dated as of June 30, 1992,
among TEP, as Lessee, Ford Motor Credit Company, as Owner
Participant, Wilmington Trust Company and William J. Wade, as
Owner Trustee and Co-Trustee, respectively, and Morgan
Guaranty, as Indenture Trustee and Refunding Trustee, relating
to the restructuring of the Registrant's lease of Unit 4 at
the Irvington Generating Station. (Form S-4, Registration No.
33-52860--33-52860 -- Exhibit 10(i)(12).)
*10(c)(12) -- Amendment No. 1, dated as of December 15, 1992, to Amended and
Restated Participation Agreement, dated as of November 15,
1987, among TEP, as Lessee, Ford Motor Credit Company, as
Owner Participant, Wilmington Trust Company and William J.
Wade, as Owner Trustee and Co-Trustee, respectively, Financial
Security Assurance Inc., as Surety, and Morgan Guaranty, as
Indenture Trustee. (Form S-1, Registration No. 33-55732--Exhibit33-55732
-- Exhibit 10(h)(12).)
*10(c)(13) -- Amended and Restated Lease, dated as of December 15, 1992,
between TEP, as Lessee and Wilmington Trust Company and
William J. Wade, as Owner Trustee and Co-
Trustee,Co-Trustee,
respectively, as Lessor. (Form S-1, Registration No.
33-55732--Exhibit33-55732 -- Exhibit 10(h)(13).)
*10(c)(14) -- Amended and Restated Tax Indemnity Agreement, dated as of
December 15, 1992, between TEP, as Lessee, and Ford Motor
Credit Company, as Owner Participant. (Form S-1, Registration
No. 33-55732--Exhibit33-55732 -- Exhibit 10(h)(14).)
*10(d) -- Power Sale Agreement for the years 1990 to 2011, dated as of
March 10, 1988, between TEP and Salt River Project
Agricultural Improvement and Power District. (Form 10-K for
the year ended December 31, 1987, File No. 1-5924 --Exhibit-- Exhibit
10(k).)
+*10(e)(1) -- Employment Agreements between TEP and currently in
effect with Michael DeConcini, Thomas A. Delawder, Steven
J. Glaser, Thomas N. Hansen, Karen G. Kissinger, Kevin P.
Larson, Dennis R. Nelson, Catherine Nichols, Vincent
Nitido, James S. Pignatelli, and James Pyers. (Form 10-K
for the year ended December 31, 1996, File No. 1-
5924--Exhibit 10(g)(1).)
*10(e)(3) -- Letter, dated February 25, 1992, from Dr. Martha R.
Seger to TEP and Capital Holding Corporation. (Form S-4,
Registration No. 33-52860--Exhibit 10(k)(4).)
+*10(e)(5) -- Amendment No. 1 to Amended and Restated Employment
Agreement between TEP and currently in effect with Michael
DeConcini, Thomas A. Delawder, Steven J. Glaser, Thomas N.
Hansen, Karen G. Kissinger, Kevin P. Larson, Dennis R.
Nelson, Catherine Nichols, Vincent Nitido, James S.
Pignatelli, and James Pyers. (Form 10-K for the year
ended December 31, 1997, File Nos. 1-5924 and 1-
13739--Exhibit 10(e)(5).)
*10(f) -- Participation Agreement, dated as of June 30, 1992, among TEP,
as Lessee, various parties thereto, as Owner Wilmington Trust
Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, and LaSalle National Bank, as Indenture Trustee
relating to TEP's lease of Springerville Unit 1. (Form S-1,
Registration No. 33-
55732--Exhibit33-55732 -- Exhibit 10(u).)
*10(g)*10(f) -- Lease Agreement, dated as of December 15, 1992, between TEP,
as Lessee and Wilmington Trust Company and William J. Wade, as
Owner Trustee and Co-Trustee, respectively, as Lessor. (Form
S-1, Registration No. 33-
55732--Exhibit33-55732 -- Exhibit 10(v).)
*10(h)*10(g) -- Tax Indemnity Agreements, dated as of December 15, 1992,
between the various Owner Participants parties thereto and
TEP, as Lessee. (Form S-1, Registration No. 33-55732--Exhibit33-55732
-- Exhibit 10(w).)
*10(i)*10(h) -- Restructuring Agreement, dated as of December 1, 1992, between
TEP and Century Power Corporation. (Form S-
1,S-1, Registration
No. 33-55732--Exhibit33-55732 -- Exhibit 10(x).)
*10(j)*10(i) -- Voting Agreement, dated as of December 15, 1992, between TEP
and Chrysler Capital Corporation (documents relating to
CILCORP Lease Management, Inc., MWR Capital Inc., US West
Financial Services, Inc. and Philip Morris Capital Corporation
are not filed but are substantially similar). (Form S-1,
Registration No. 33-55732--Exhibit33-55732 -- Exhibit 10(y).)
*10(k)*10(j)(1) -- Wholesale Power Supply Agreement between TEP and Navajo Tribal
Utility Authority dated January 5, 1993. (Form 10-K for the
year ended December 31, 1992, File No. 1-5924--Exhibit1-5924 -- Exhibit
10(t).)
*10(k)*10(j)(2) -- Amended and Restated Wholesale Power Supply Agreement between
TEP and Navajo Tribal Utility Authority, dated June 25, 1997.
(Form 10-Q for the quarter ended June 30, 1997, File No.
1-5924--Exhibit1-5924 -- Exhibit 10.)
*10(l) -- Credit Agreement dated as of December 30, 1997,
among TEP, Toronto Dominion (Texas), Inc., as
Administrative Agent, The Bank of New York, as Syndication
Agent, Societe Generale, as Documentation Agent, the
lenders party hereto, and the issuing banks party hereto.
(Form 10-K for year ended December 31, 1997, File No. 1-
5924--Exhibit 10(m).)
+*10(m)10(k) -- 1994 Omnibus Stock and Incentive Plan of UniSource Energy.
(Form S-8 dated January 6, 1998, File No. 333-
43767.333-43767.)
+*10(n) -- 1994 Outside Director Stock Option Plan of
UniSource Energy. (Form S-8 dated January 6, 1998, File
No. 333-43765.)
+*10(o)10(l) -- Management and Directors Deferred Compensation Plan of
UniSource Energy. (Form S-8 dated January 6, 1998, File No.
333-43769.)
+*10(p)10(m) -- TEP Supplemental Retirement Account for Classified Employees.
(Form S-8 dated May 21, 1998, File No. 333-
53309.333-53309.)
+*10(q)10(n) -- TEP Triple Investment Plan for Salaried Employees. (Form S-8
dated May 21, 1998, File No. 333-53333.)
+*10(r)10(o) -- UniSource Energy Management and Directors Deferred
Compensation Plan. (Form S-8 dated May 21, 1998, File No.
333-53337.)
+10(p) -- Officer Change in Control Agreement between TEP and currently
in effect with Thomas A. Delawder, Michael DeConcini, Steven
J. Glaser, Thomas N. Hansen, Neil Holstad, Karen G. Kissinger,
Kevin P. Larson, Steven W. Lynn, Dennis R. Nelson, Vincent
Nitido, Jr., James S. Pignatelli, and James Pyers dated as of
December 4, 1998.
*10(q)(1) -- Sworn Statement by UniSource Energy Principal Executive
Officer Regarding Facts and Circumstances Relating to Exchange
Act Filings pursuant to SEC Order No. 4-460. (Form 8-K dated
August 9, 2002, File No. 1-13739 -- Exhibit 99.1.)
*10(q)(2) -- Sworn Statement by UniSource Energy Principal Financial
Officer Regarding Facts and Circumstances Relating to Exchange
Act Filings pursuant to SEC Order No. 4-460. (Form 8-K dated
August 9, 2002, File No. 1-13739 -- Exhibit 99.2.)
+*10(r) -- Amended and Restated UniSource Energy 1994 Outside Director
Stock Option Plan of UniSource Energy. (Form S-8 dated
September 9, 2002, File No. 333-99317.)
*10(s)(1) -- Asset Purchase Agreement dated as of October 29, 2002, by and
between UniSource Energy and Citizens Communications Company
relating to the Purchase of Citizens' Electric Utility
Business in the State of Arizona. (Form 8-K dated October 31,
2002, File No. 1-13739 -- Exhibit 99-1.)
*10(s)(2) -- Asset Purchase Agreement dated as of October 29, 2002, by and
between UniSource Energy and Citizens Communications Company
relating to the Purchase of Citizens' Gas Utility Business in
the State of Arizona. (Form 8-K dated October 31, 2002, File
No. 1-13739 -- Exhibit 99-2.)
*10(t) -- Credit Agreement dated as of November 14, 2002, among TEP,
Toronto Dominion (Texas), Inc., as Administrative Agent, The
Bank of New York and Union Bank of California as
Co-Syndication Agents, Credit Suisse First Boston as
Documentation Agent, TD Securities (USA) Inc. and Credit
Suisse First Boston as Co-Lead Arrangers and Joint
Bookrunners, the lenders party hereto, and the issuing banks
party hereto. (Form 8-K dated November 27, 2002, File Nos.
1-5924 and 1-13739 -- Exhibit 99-1.)
12 -- Computation of Ratio of Earnings to Fixed Charges--Charges -- TEP.
21 -- Subsidiaries of the Registrants.
23 -- Consents of experts.
24(a) -- Power of Attorney--UniSourceAttorney -- UniSource Energy.
24(b) -- Power of Attorney--TEP.Attorney -- TEP.
99 -- Statements of Corporate Officers pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
(*) Previously filed as indicated and incorporated herein by reference.
(+) Management contracts or compensatory plans or arrangements required to
be filed as exhibits to this Form 10-K by item 601(b)(10)(iii) of
Regulation S-K.