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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, 2001
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
Corporation value and Preferred 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. [ ]
The aggregate market value of UniSource Energy Corporation voting Common
Stock held by non-affiliates of the registrant was $578,856,011 based on
the last reported sale price thereof on the consolidated tape on February 25,
2002.
At February 25, 2002, 33,539,487 shares of UniSource Energy Corporation
Common Stock, no par value (the only class of Common Stock), were outstanding.
At February 25, 2002, UniSource Energy Corporation is the holder of
32,139,434 shares of the outstanding Common Stock of Tucson Electric Power
Company.
Documents incorporated by reference: Specified portions of UniSource
Energy Corporation's Proxy Statement relating to the 2002 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......................................................4
Generating and Other Resources..........................................6
Rates and Regulation....................................................8
Fuel Supply............................................................13
Water Supply...........................................................14
TEP's Utility Operating Statistics.....................................15
Environmental Matters....................................................16
Millennium Energy Businesses.............................................17
UniSource Energy Development Company.....................................18
Employees................................................................19
Item 2. - Properties.......................................................19
Item 3. - Legal Proceedings................................................21
Item 4. - Submission of Matters to a Vote of Security Holders..............21
- PART II -
Item 5. - Market for Registrant's Common Equity and Related
Stockholder Matters..............................................22
Item 6. - Selected Consolidated Financial Data
UniSource Energy.........................................................23
TEP......................................................................24
Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview.................................................................25
Factors Affecting Results of Operations
Competition............................................................26
Industry Restructuring.................................................27
Market Risks...........................................................30
Critical Accounting Policies.............................................33
Results of Operations....................................................35
Contribution by Business Segment.......................................36
Utility Sales and Revenues.............................................36
Operating Expenses.....................................................38
Interest Income........................................................40
TABLE OF CONTENTS
(continued)
Page
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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......................................................43
Cash Flows.............................................................45
Investing and Financing Activities
UniSource Energy - Parent Company....................................46
TEP - Electric Utility...............................................46
Millennium - Unregulated Energy Businesses...........................50
UED - Unregulated Energy Business....................................51
Safe Harbor for Forward-Looking Statements...............................51
Item 7A. - Quantitative and Qualitative Disclosures about Market Risk......52
Item 8. - Consolidated Financial Statements and Supplementary Data.........52
Report of Independent Accountants........................................53
UniSource Energy Corporation
Consolidated Statements of Income......................................54
Consolidated Statements of Cash Flows..................................55
Consolidated Balance Sheets............................................56
Consolidated Statements of Capitalization..............................57
Consolidated Statements of Changes in Stockholders' Equity.............58
Tucson Electric Power Company
Consolidated Statements of Income......................................59
Consolidated Statements of Cash Flows..................................60
Consolidated Balance Sheets............................................61
Consolidated Statements of Capitalization..............................62
Consolidated Statements of Changes in Stockholders' Equity.............63
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting
Policies......................................................64
Note 2. Regulatory Matters..............................................68
Note 3. Accounting for Derivative Instruments and Hedging Activities....73
Note 4. Millennium Energy Businesses....................................75
Note 5. Segment and Related Information.................................77
Note 6. TEP's Utility Plant and Jointly-Owned Facilities................79
Note 7. Long-Term Debt and Capital Lease Obligations....................79
Note 8. Fair Value of UniSource Energy Financial Instruments............82
Note 9. Dividend Limitations............................................82
Note 10. Commitments and Contingencies...................................83
Note 11. Wholesale Accounts Receivable and Allowances....................86
Note 12. Income Taxes....................................................88
Note 13. Employee Benefits Plans.........................................90
Note 14. UniSource Energy Earnings Per Share (EPS).......................94
Note 15. Warrants........................................................95
Note 16. UniSource Energy Shareholder Rights Plan........................95
Note 17. Supplemental Cash Flow Information..............................96
Note 18. Quarterly Financial Data (Unaudited)............................98
TABLE OF CONTENTS
(concluded)
Page
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Schedule II - Valuation and Qualifying Accounts........................ 101
- PART III -
Item 9. - Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................102
Item 10. - Directors and Executive Officers of the Registrants
Directors...............................................................102
Executive Officers......................................................102
Item 11. - Executive Compensation.........................................104
Item 12. - Security Ownership of Certain Beneficial Owners and Management
General.................................................................104
Security Ownership of Certain Beneficial Owners.........................105
Security Ownership of Management........................................105
Item 13. - Certain Relationships and Related Transactions.................105
- PART IV -
Item 14. - Exhibits, Financial Statement Schedules, and Reports
on Form 8-K...........................................................106
Signatures..............................................................107
Exhibit Index...........................................................111
DEFINITIONS
The abbreviations and acronyms used in the 2001 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.
ALJ.......................... FERC Administrative Law Judge.
APS.......................... Arizona Public Service Company.
BTU.......................... British 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.
Common Stock................. UniSource Energy's common stock, without par
value.
Company or UniSource Energy.. UniSource Energy Corporation.
Cooling Degree Days.......... 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.
Emission Allowance(s)........ An EPA-issued allowance which permits
emission of one ton of sulfur dioxide.
These allowances can be bought or 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.
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, which develops and
manufactures thin-film photovoltaic cells.
Heating Degree Days.......... 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..... Infinite Power Solutions, Inc., a wholly-owned
subsidiary of GES, which develops thin-film
batteries.
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.
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., a company owned 49% by
Millennium, which was formed to develop and
commercialize small-scale satellites.
Millennium................... Millennium Energy Holdings, Inc., a wholly-owned
subsidiary of UniSource Energy.
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 approved by the
ACC in August 1998, which provided retail base
price decreases over a two-year period.
Revolving Credit.Facility.... $100 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.
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.
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.
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.
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. We conduct our business in these three
primary business segments--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, Millennium Energy Businesses and UniSource
Energy Development Company below.
References in this report to "we" and "our" are to UniSource
Energy and its subsidiaries, collectively. References in this
report to the "utility business" are to TEP.
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 - Nature of Operations
and Summary of Significant Accounting Policies.
OUTLOOK AND STRATEGY
- --------------------
In recent years, the electric utility industry has undergone
significant regulatory change designed to encourage competition in
the sale of electric generation services. Recent actions by the
Arizona Corporation Commission (ACC), however, have added
uncertainty regarding the ongoing implementation of competition
rules in Arizona. Additionally, FERC issued various orders in
response to the California energy crisis which have impacted our
businesses. We continually evaluate our position to develop
strategies to remain competitive and flexible in this changing
environment. Our plans and strategies include the following:
- Enhance the value of our transmission system while continuing
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 ELECTRIC UTILITY OPERATIONS
- -------------------------------
OVERVIEW OF ELECTRIC UTILITY
TEP is a vertically integrated utility that provides regulated
electric service to over 350,000 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 871,000 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 City of Tucson. This franchise expires in 2026. 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 its 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 fully 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 Rules 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. The
peak demand for TEP's retail service area occurs during the summer
months due to the cooling requirements of our retail customers.
TEP's retail peak demand has grown at an average annual rate of
approximately 3.0% 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. 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, of total retail energy consumption during that
period.
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.
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, 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, 2002 no TEP retail customers are currently served by
alternate energy suppliers. See TEP's Settlement Agreement and
Retail Electric Competition Rules, 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, defense, health care,
education and governmental entities. 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-tariffed rates. These
contracts expire between 2003 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. Whether these contracts are extended or
terminated will depend, in part, on market conditions and available
alternatives.
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, market prices
for copper were consistent with year 2000 prices, which were
slightly higher than the low prices experienced during 1998 and
1999. However, these prices still remain low relative to historical
prices. As a result of these low copper prices, TEP's mining
customers have reduced operation levels in recent years to lower
their electricity costs. These customers recently announced
additional reductions for 2002, which we anticipate will result in a
40 MW load reduction to system retail peak demand.
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
long-term strips of energy 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) 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 sales in the last
three years:
2001 2000 1999
-------------------------------------------------------------
Long-term Contracts 10% 14% 26%
Forward Contracts 63% 36% 42%
Short-term Sales and Other 26% 48% 29%
Transmission 1% 2% 3%
-------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------
TEP's kWh wholesale sales increased by 15% in 2001 while
revenues from 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 prices in the western U.S. wholesale energy markets
during the first two quarters 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
online in the western U.S., lower natural gas prices, increased
hydro supply and weaker demand. As of February 2002, the average
forward around-the-clock market price for the balance of 2002 was
approximately $27 per MWh, based on the Dow Jones Palo Verde Index.
As a result, we expect our wholesale revenues to be significantly
lower in 2002 than in 2001. A large portion of our revenues in 2001
was 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 expect the market price and demand for capacity and energy
to continue to be influenced by the following factors 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, 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, TEP owned or leased 1,999 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
Turbine Tucson, AZ Gas Owned 75 TEP 100.0 75
Internal Combustion
Turbine Tucson, AZ Gas Leased 20 TEP 100.0 20
- -----------------------------------------------------------------------------------------------------
Total TEP Capacity (1) 1,999
- -----------------------------------------------------------------------------------------------------
(1) Excludes 217 MW of additional resources, which consist of certain capacity purchases
and interruptible retail load. At December 31, 2001, total owned capacity was 1,443 MW
and leased capacity was 556 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 subsidiary, 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 facilitating the construction of
Springerville Units 3 and 4. TEP will be the operator of the new
units. See UniSource Energy Development Company, below.
The initial terms of the Springerville Unit 1 Leases, which
include a 50% interest in the Springerville Common Facilities,
expire on January 1, 2015, but have optional fair market value
renewal and purchase provisions. The annual cash cost of lease
payments for 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.
In 1985, TEP sold and leased back a 50% interest in the
Springerville Common Facilities. The initial lease term for the
Springerville Common Facilities Leases expires in 2017 for one owner
participant 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
-----------------
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 but is able to operate on gas. In
1988, Unit 4 was sold and then leased back 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.
The Irvington Station, along with the internal combustion
turbines located in Tucson, are designated as "must-run generation"
facilities. Must-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.
POWER EXCHANGE AGREEMENT
As part of a 1992 litigation settlement, TEP and Southern
California Edison Company (SCE) agreed to a ten-year power exchange
agreement. Since the agreement began in 1995, TEP has relied upon
the 110 MW provided under this agreement as a firm source of energy
to supply its retail load during the peak summer months. TEP is
obligated to return to SCE in the winter months the same amount of
energy that it received during the preceding summer. For example,
in the summer of 2000, TEP received approximately 140,000 MWh from
SCE and returned the same amount during the winter months from
November 2000 to February 2001. Except for a few occasions 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.
OTHER PURCHASES AND INTERCONNECTIONS
TEP participates in a number of interchange agreements by which
it can purchase additional electric energy from other utilities.
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.
See also Wholesale Business, above and Item 7. - Management's
Discussion and Analysis of Financial Condition and 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 regional reserve sharing, reliability and power pooling
organizations.
In January 2001, TEP and Citizens Communications Company
(Citizens) entered into a project development agreement for the
construction of a transmission line from Tucson 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. TEP plans to begin construction by
the first quarter of 2003. This project, when completed, will meet
one 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
discussion of possible changes in the operation and oversight of
TEP's transmission facilities.
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, Competition.
TEP will continue to add peaking resources in the Tucson area
as needed based upon our forecasts of retail and firm wholesale
load. For the longer term, TEP is also considering entering into a
power purchase contract for up to 100 MW of the generation from the
proposed addition of Units 3 and 4 at Springerville under
development by UED. See UniSource Energy Development Company,
below.
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.
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.
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 reproduction 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.
With the introduction of retail electric competition in TEP's
service territory in 2000, 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, after these reductions, 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 due 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
decrease 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-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 ENVIRONMENT
In January 2002, the ACC began to formally reexamine
circumstances that have changed since the Rules were adopted in 1996
and to revisit the path to deregulation of the retail electric
market. The ACC sent questions related to retail competition to
stakeholders, requesting comments by February 25, 2002. At the
current time, the outcome of this proceeding 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 FERC and certain state regulatory authorities in the
region.
The ACC Retail Electric Competition Rules also required the
formation and implementation of an Arizona Independent Scheduling
Administrator (AISA). The purpose 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 participated 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 participate with the other affected
utilities in developing the AISA's structure 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.
See Item 7. - Management's Discussion and Analysis of Financial
Condition and Results of Operations, Tax Exempt Local Furnishing
Bonds for a discussion of the possible effect of the establishment
of an RTO, ISO and/or an AISA on TEP's capital structure and refinancing
requirements.
WESTERN ENERGY MARKETS
As a participant 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 with 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 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. 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 MATTERS
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.
On June 19, 2001, the FERC issued an order adopting 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, 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
calls 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 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.
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. See Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of
Operation, Critical Accounting Policies - Payment Defaults and
Allowances for Doubtful Accounts.
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 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.
TEP's UTILITY OPERATING STATISTICS
For Years Ended December 31,
2001 2000 1999 1998 1997
- -------------------------------------------------------------------------------------------------------
Generation and Purchased Power-kWh (000)
Remote Generation (Coal) 10,362,211 10,278,393 10,000,401 10,002,250 9,694,152
Local Generation (Oil, Gas & Coal) 1,820,783 1,667,308 1,115,277 720,515 806,819
Purchased Power 4,052,674 3,174,244 2,712,570 2,227,773 1,222,970
- -------------------------------------------------------------------------------------------------------
Total Generation and Purchased Power 16,235,668 15,119,945 13,828,248 12,950,538 11,723,941
Less Losses and Company Use 846,287 724,677 814,945 810,117 824,072
- -------------------------------------------------------------------------------------------------------
Total Energy Sold 15,389,381 14,395,268 13,013,303 12,140,421 10,899,869
=======================================================================================================
Sales-kWh (000)
Residential 3,122,332 3,027,963 2,736,837 2,662,598 2,608,515
Commercial 1,573,213 1,496,558 1,383,756 1,355,319 1,316,360
Industrial 2,270,446 2,262,212 2,220,900 2,139,464 2,115,332
Mining 1,040,762 1,140,811 1,200,214 1,230,259 1,193,094
Public Authorities 254,130 258,470 247,361 242,845 237,113
- -------------------------------------------------------------------------------------------------------
Total - Electric Retail Sales 8,260,883 8,186,014 7,789,068 7,630,485 7,470,414
Electric Wholesale Sales 7,128,498 6,209,254 5,224,235 4,509,936 3,429,455
- -------------------------------------------------------------------------------------------------------
Total Electric Sales 15,389,381 14,395,268 13,013,303 12,140,421 10,899,869
=======================================================================================================
Operating Revenues (000)
Residential $283,673 $276,720 $253,352 $248,821 $246,251
Commercial 164,345 157,744 148,039 146,269 146,377
Industrial 161,584 162,790 160,963 157,735 158,266
Mining 41,994 48,484 49,399 51,965 53,231
Public Authorities 18,521 18,908 18,147 17,950 17,531
- -------------------------------------------------------------------------------------------------------
Total - Electric Retail Sales 670,117 664,646 629,900 622,740 621,656
Amortization of MSR Option Gain
Regulatory Liability - - - - 8,105
Electric Wholesale Sales 761,255 359,814 171,219 143,269 97,567
Net Unrealized Loss on Forward
Electric Sales and Purchases (1,315) - - - -
Other Revenues 6,308 3,908 2,964 2,981 2,565
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues $1,436,365 $1,028,368 $804,083 $768,990 $729,893
=======================================================================================================
Customers (End of Period)
Residential 318,976 311,673 303,653 295,469 287,857
Commercial 31,194 30,467 29,714 28,648 28,309
Industrial 705 711 705 684 664
Mining 2 2 4 4 4
Public Authorities 61 61 61 61 61
- -------------------------------------------------------------------------------------------------------
Total Retail Customers 350,938 342,914 334,137 324,866 316,895
=======================================================================================================
Average Retail Revenue per kWh Sold (cents)
Residential 9.1 9.1 9.3 9.3 9.4
Commercial 10.5 10.5 10.7 10.8 11.1
Industrial and Mining 6.1 6.2 6.1 6.2 6.4
Average Retail Revenue per kWh Sold 8.1 8.1 8.1 8.2 8.4
Average Revenue per Residential Customer $899 $899 $845 $855 $865
Average kWh Sales per Residential Customer 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.
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. 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-
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. 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.
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. Failure to comply with any EPA or state compliance
requirements may result in substantial penalties or fines.
In 2001, TEP applied to the Arizona Department of Environmental
Quality (ADEQ) for a major revision to the Springerville Generating
Station Title V permit to allow for expansion of the facility to
include two new 400 MW coal-fired generating units. The proposed
permit would allow the construction of Units 3 and 4 without
subjecting those units to full review under the CAAA regulations
concerning Prevention of Significant Deterioration (PSD). The
proposed permit would allow Units 3 and 4 to avoid a full PSD review
because of a "netting" proposal whereby the total emissions from all
four units would be less than the emissions from Units 1 and 2
today.
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, 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. However, in the event that TEP would be
required to install such new technology, the cost could be up to
$200 million.
MILLENNIUM ENERGY BUSINESSES
- ----------------------------
Millennium's assets comprised approximately 6% of the
consolidated assets of UniSource Energy at December 31, 2001 and
2000. Millennium had an after-tax loss of $9 million in 2001, which
included a $6 million after-tax gain on the sale of a power project.
Through its affiliates, Millennium holds investments in the energy-
related businesses which are described below.
Energy Technology Investments
-----------------------------
In 1996, Millennium and a privately held company formed an
entity to develop renewable energy and thin-film technologies.
Millennium owns approximately 67% of the following entities:
- Global Solar Energy, Inc., a developer of flexible thin-film
photovoltaic cells, started limited production of photovoltaic
cells in 1999. Target markets for its products include military,
space and commercial applications.
- Infinite Power Solutions, Inc., a developer of thin-film
batteries.
In 2001, Millennium and a privately held company formed and
began to provide funding to MicroSat Systems, Inc. (MicroSat) and
ITN Energy Systems, Inc. (ITN). MicroSat is a developer of small-
scale satellites, focusing on research and development activities
related to 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.
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 we 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
$14 million to its various technology investments in 2002.
Nations Energy
--------------
Nations Energy Corporation 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. 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
----------------------------
The following Millennium investments represented less than 1%
of consolidated assets and consolidated net income of UniSource
Energy at December 31, 2001 and 2000:
- Southwest Energy Solutions, Inc. was established in January 1997
and provides electrical contracting services statewide to
commercial, industrial and governmental customers in both high
voltage and inside wiring capacities and meter reading services for
local utilities, including TEP.
- Millennium Environmental Group, Inc. (MEG) was established in
September 2001 to manage and trade emission allowances, coal and
other environmental related products including financial
instruments.
- Powertrusion International, Inc. (Powertrusion), a manufacturer of
lightweight utility poles. Millennium invested $3 million in
Powertrusion in August 2001 for a controlling 50.5% interest in
the company.
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 Investing and Financing Activities - Millennium.
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 evaluate 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 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.
Springerville was originally designed for four units. Units 3
and 4 would consist of two 400 MW coal-fired, base-load generating
units at the same site as Springerville Units 1 and 2, and would
allow us to spread the fixed costs of the existing common facilities
over the two additional generating units. We are developing the
project scope and schedule and defining 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 addition to SRP.
The ACC approved construction of a third and fourth unit at the
Springerville Generating Station in 1977 and 1987, respectively,
providing 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 requesting 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.
Environmental activist groups have expressed concerns regarding
the construction of Units 3 and 4. 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, 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 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 can make no assurances, however, about the ultimate timing,
or whether we will proceed with this project. See also Item 7. -
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Investing and Financing Activities, UED.
EMPLOYEES
- ---------
As of December 31, 2001, TEP had 1,141 employees and the wholly-
owned subsidiaries of Millennium had 16 employees. The International
Brotherhood of Electrical Workers (IBEW) Local 1116 represents
approximately 60% of TEP's employees. A new collective bargaining
agreement between the IBEW and TEP was ratified in March 1999 and
extends until January 2003. The new agreement resulted in a wage
increase of 3% in 2000 and an additional 3% in 2001.
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
------- --------
Arizona Public Service Co. Arizona
Arizona Electric Power Cooperative Arizona
El Paso Electric Co. New Mexico, Texas
Public Service Co. of New Mexico New Mexico
Salt River Project Arizona
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, 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;
- 372 circuit-miles of 138 kV lines;
- 434 circuit-miles of 46 kV lines; and
- 11,529 circuit-miles of lower voltage primary lines.
The underground electric distribution system is comprised of
6,870 cable-miles. TEP owns approximately 77% of the poles on which
the lower voltage lines are located. Electric substation capacity
consisted of 185 substations with a total installed transformer
capacity of 5,589,772 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. TEP, individually and in conjunction with PNM in
connection with San Juan, has acquired easements and leases for
transmission lines and a water diversion facility located on the
Navajo Indian Reservation. 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
Debt and Capital Lease 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. - Business - Rates and Regulation.
SPRINGERVILLE GENERATING STATION COMPLAINT
See Note 10 of Notes to Consolidated Financial Statements.
ITEM 4. - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------
Not Applicable.
PART II
ITEM 5. - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
Stock Trading
-------------
UniSource Energy's common stock is traded under the ticker
symbol UNS. It is listed on the New York and Pacific Stock
Exchanges and began trading under the symbol UNS on January 2, 1998.
As of February 25, 2002, the closing price was $17.62, with 20,297
shareholders of record.
Dividends
---------
UniSource Energy pays dividends on its common stock after its
Board of Directors declares them. There is no limitation on
UniSource Energy paying common stock dividends.
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.
- 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).
- 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
---------------------------------------
2001 2000
----------------------------------------------------------------------------------
Quarter: Market Price per Dividends Market Price per Dividends
Share of Common Paid Share of Common Paid
Stock (1) Stock (1)
High Low High Low
---- --- ---- ---
First $21.00 $15.13 $0.10 $15.25 $10.81 $0.08
Second 25.98 20.16 0.10 16.38 14.13 0.08
Third 24.05 13.80 0.10 17.25 14.75 0.08
Fourth 19.30 13.80 0.10 19.31 14.13 0.08
----------------------------------------------------------------------------------
Total $0.40 $0.32
----------------------------------------------------------------------------------
(1) UniSource Energy's common stock price on the consolidated tape as reported by
Dow Jones.
On February 7, 2002, UniSource Energy declared a cash dividend
of $0.125 per share on its common stock, a 25% increase over the
prior quarter. The dividend is payable March 8, 2002 to
shareholders of record at the close of business February 21, 2002.
TEP declared and paid cash dividends of $50 million in the
fourth quarter of 2001, $30 million in the fourth quarter of 2000,
and $34 million in the fourth quarter of 1999.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
- --------------------------------------------------------------------------------
UNISOURCE ENERGY 2001 2000 1999 1998 1997 (1)
-----------------------------------------------------------
- Thousands of Dollars -
(except per share data)
Summary of Operations
- ----------------------------------------------------------------------------------------------
Operating Revenues $1,444,708 $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 Losses of Millennium Energy
Businesses (2) $(14,455) $(12,059) $(11,276) $(11,884) $(8,182)
Income Before Extraordinary Item
and Accounting Change $60,875 $41,891 $56,510 $28,032 $83,572
Net Income $61,345 $41,891 $79,107 $28,032 $83,572
Basic Earnings per Share:
Before Extraordinary Item &
Accounting Change $1.83 $1.29 $1.75 $0.87 $2.60
Net Income $1.84 $1.29 $2.45 $0.87 $2.60
Diluted Earnings per Share:
Before Extraordinary Item &
Accounting Change $1.79 $1.27 $1.74 $0.87 $2.59
Net Income $1.80 $1.27 $2.43 $0.87 $2.59
Shares of Common Stock Outstanding
Average 33,399 32,445 32,321 32,177 32,138
End of Year 33,502 33,219 32,349 32,258 32,139
Year-end Book Value per Share $12.68 $11.20 $10.02 $7.65 $6.75
Cash Dividends Declared per Share $0.40 $0.24 $0.08 - -
- ----------------------------------------------------------------------------------------------
Financial Position
- ----------------------------------------------------------------------------------------------
Total Utility Plant - Net $1,677,671 $1,706,290 $1,729,856 $1,915,590 $1,935,513
Investments and Other Property $182,747 $121,811 $114,483 $110,289 $79,471
Total Assets $2,735,325 $2,671,384 $2,656,255 $2,634,049 $2,634,409
Long-Term Debt (3) $802,804 $1,132,395 $1,135,820 $1,184,423 $1,215,120
Non-Current Capital Lease
Obligations 853,793 857,829 880,427 889,543 890,257
Common Stock Equity 424,722 372,169 324,248 246,646 216,878
- ----------------------------------------------------------------------------------------------
Total Capitalization $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 $215,379 $215,034 $113,228 $160,933 $126,283
Capital Expenditures $(121,622) $(105,996) $(92,808) $(81,147) $(72,475)
Other Investing Cash Flows 4,775 (7,554) (242) (27,810) (4,030)
- ----------------------------------------------------------------------------------------------
Net Cash Flows From Investing
Activities $(116,847) $(113,550) $(93,050) $(108,957) $(76,505)
- ----------------------------------------------------------------------------------------------
Net Cash Flows From Financing
Activities $(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 Losses of Millennium Energy Businesses are before income taxes, do not include
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) 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. 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.
See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
- --------------------------------------------------------------------------------
TEP 2001 2000 1999 1998 1997 (1)
----------------------------------------------------------
- Thousands of Dollars -
Summary of Operations
- ----------------------------------------------------------------------------------------------
Operating Revenues $1,436,365 $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 $74,814 $51,169 $50,878 $41,676 $83,572
Net Income $75,284 $51,169 $73,475 $41,676 $83,572
- ----------------------------------------------------------------------------------------------
Financial Position
- ----------------------------------------------------------------------------------------------
Total Utility Plant - Net $1,677,671 $1,706,290 $1,729,856 $1,915,590 $1,935,513
Investments and Other Property $105,875 $92,334 $67,838 $62,978 $79,471
Total Assets $2,633,943 $2,600,935 $2,600,508 $2,628,588 $2,634,409
Long-Term Debt (3) $801,924 $1,132,395 $1,135,820 $1,184,423 $1,215,120
Non-Current Capital Lease
Obligations 853,447 857,519 880,111 889,543 890,257
Common Stock Equity 322,471 295,660 270,134 229,861 216,878
- ----------------------------------------------------------------------------------------------
Total Capitalization $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 $261,169 $234,190 $139,957 $180,487 $126,283
Capital Expenditures $(103,913) $(98,063) $(90,940) $(81,011) $(72,475)
Other Investing Cash Flows (11,981) (23,273) (24,480) (43,937) (4,030)
- ----------------------------------------------------------------------------------------------
Net Cash Flows From Investing
Activities $(115,894) $(121,336) $(115,420) $(124,948) $(76,505)
- ----------------------------------------------------------------------------------------------
Net Cash Flows From Financing
Activities $(74,307) $(112,544) $(54,371) $(83,559) $(33,813)
- ----------------------------------------------------------------------------------------------
Ratio of Earnings to Fixed Charges 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. 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.
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, 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 general
financial condition and the results of operations for UniSource
Energy and its three primary business segments--the electric utility
business of TEP and the unregulated energy businesses of Millennium
and UED--and includes the following:
- operating results during 2001 compared with 2000, and during 2000
compared with 1999,
- changes in liquidity and capital resources during 2001, and
- expectations of identifiable material trends which may affect our
business in the future.
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, 2001, 2000, and 1999. 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.
OVERVIEW
- --------
UniSource Energy recorded net income of $61 million in 2001,
compared with net income of $42 million in 2000 and $79 million in
1999. UniSource Energy's total revenues increased by 40% to $1.4
billion in 2001, resulting from growth in retail electricity sales
and wholesale marketing activities at TEP. The following factors
contributed to the improvement in net income in 2001:
- 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;
- 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;
- a 5% reduction in interest expense at TEP due to lower debt
balances and lower rates on variable rate debt;
- a $6 million after-tax gain from the sale of an independent power
project by a Millennium subsidiary, Nations Energy; and
- a one-time $8 million after-tax expense related to the amendment
of a coal supply contract recorded in the third quarter of 2000.
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
quarter of 1999;
- the $21 million after-tax gain on the sale of one of our
unregulated energy businesses recorded in the third quarter of 1999;
- $9 million in tax benefits recorded in the fourth quarter of
1999;
- a one-time $8 million after-tax expense related to the amendment
of a coal supply contract recorded in the third quarter of 2000; and
- the impact of accounting changes related to the discontinuation
of FAS 71 regulatory accounting for TEP's generation operations in
November 1999.
See Factors Affecting Results of Operations and Results of Operations,
below.
Outlook and Strategy
--------------------
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:
- Enhance the value of our transmission system while continuing 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 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 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 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
to be highly leveraged, and as a result, our access to the capital
markets may be limited or more expensive than for less leveraged
companies.
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 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-
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, the ACC adopted 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.
- 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, 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 requires that by December 31,
2002, TEP, as the Utility Distribution Company (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.
Approval of 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.
Recent Developments in the Arizona Regulatory Environment
---------------------------------------------------------
In February 2002, the ACC consolidated several retail
competition matters to reexamine circumstances that have changed
since the ACC adopted the Rules in 1996. In a letter dated January
14, 2002, ACC Chairman William Mundell suggested three possible
outcomes:
- Implementation of the Rules according to the existing schedule,
- Delayed 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,
- 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 predict 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.
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. 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. 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 have appealed the decision to the Court
of Appeals. In addition, the Cooperatives filed a notice of cross
appeal of certain aspects of the decision. 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, 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. The Congress in 2002 will
likely focus on administrative controls and oversight of the 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 monitored by the legislature. The 2002
legislature is expected to review legislation to modify the
valuation of power plants within the state.
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. 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 with the outcomes of deregulation of the electric power
industry.
Rates and Market Prices
-----------------------
In 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 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 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-ahead and real-time (hourly) markets typically exceeded
TEP's total cost of service. The average market price for around-
the-clock energy based on the Dow Jones Palo Verde Index was $94 per
MWh in 2001, compared with $87 per MWh in 2000. The 2001 average
price represents a steep decline, however, from $156 per MWh in the
first half of 2001 to $23 per MWh in the fourth quarter of 2001.
This reduction was due to a number of factors, including more
generation online in the western U.S., lower natural gas prices,
increased hydropower supply, and weaker demand. As of February
2002, the average forward around-the-clock market price for the
balance of the year 2002 was approximately $27 per MWh, based on the
Dow Jones Palo Verde Index. As a result, we expect our wholesale
revenues to be significantly lower in 2002 than in 2001. A large
portion of our 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 expect the market price and demand for capacity and energy
to continue to be influenced by the following factors 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.
Payment Defaults and Allowances for Doubtful Accounts
-----------------------------------------------------
In early 2001, California's two largest utilities, SCE and
PG&E, defaulted on payment obligations owed to various energy
sellers, including the CPX and the 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 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. 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
approvals and numerous parties have expressed opposition to the plan.
On December 2, 2001, Enron 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.
As a result of payment defaults made by market participants in
California and by Enron, TEP established allowances for doubtful
accounts.
See Note 11 of Notes to Consolidated Financial Statements and
Critical Accounting Policies, below.
SCE Power Exchange Agreement
----------------------------
A power exchange agreement between TEP and SCE requires SCE to
provide firm system capacity of 110 MW to TEP during summer months.
TEP is then obligated to return to SCE in the winter months the same
amount of energy that TEP received from SCE during the preceding
summer. Since 1995, TEP has relied upon this 110 MW from SCE.
During 2000 and 2001, volatility in the western energy markets and
the deterioration in SCE's financial condition created uncertainty
for TEP regarding the availability of this resource for TEP's summer
peaking needs. Except for a few occasions in 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.
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,
2001 and 2000, TEP's debt included $329 million of tax-exempt
variable rate debt. The average interest rate on TEP's variable
rate debt was 2.68% for 2001 and 4.17% for 2000. A one percent
increase (decrease) in average interest rates would result in a
decrease (increase) in pre-tax net income of approximately $3
million. See Note 8 of Notes to Consolidated Financial Statements -
Fair Value of UniSource Energy Financial Instruments.
Marketable Securities Risk
--------------------------
TEP and Millennium are exposed to fluctuations in the return on
marketable securities, which are investments in debt securities. At
December 31, 2001 and 2000, TEP had marketable debt securities with
an estimated fair value of $74 million and $76 million, which
exceeded the carrying value by $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 and
coal trading activities of MEG. Our Risk Management Committee
consists of officers with responsibility for finance, accounting,
legal, wholesale marketing, and the generation operations of
UniSource Energy. To limit our exposure to commodity price risk,
the Risk Management Committee approves trading policies and limits,
which are reviewed frequently to respond to constantly changing
market conditions. To limit our exposure to credit risk in these
activities, the Risk Management Committee approves 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 and 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. These positions are managed on both a volumetric and
dollar basis and are closely monitored using risk management
policies and procedures with oversight 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 should
have supply backing up all forward sales positions.
TEP also enters 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 types of transactions are
considered to be our trading positions. TEP marks its trading
positions 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 forward 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 of 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 loss of $0.5 million was recorded on TEP's balance
sheet as of December 31, 2001 to adjust 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 changes in the fair value of TEP's
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.
TEP uses a sensitivity analysis to measure the impact of an
unfavorable change in market prices on the fair value of its trading
positions. As of December 31, 2001, a 10% unfavorable change in the
market prices of electric power from year-end levels would have
decreased the fair value of these instruments by less than $1
million. Beginning in 2001, changes in the fair value of these
derivative instruments are measured in our 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.
During the fourth quarter of 2001, we entered into the business
of managing and trading emission allowances, coal and other
environmental related products, including financial instruments
through MEG, a wholly-owned subsidiary of Millennium. 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. MEG's
trading activities are closely monitored using risk management
policies and procedures with oversight by the Risk Management
Committee. MEG marks its trading positions to market on a daily
basis using actively quoted prices obtained from brokers. As of
December 31, 2001, the fair value of MEG's trading positions was
less than $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 energy 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.
TEP also purchases coal and natural gas in the normal course of
business for fuel for its generating plants. TEP acquires its coal
under long-term coal supply contracts. Purchases of gas
historically provided fuel for only 3-4% of total generation.
Beginning in the third quarter of 2000 through June 2001, however,
the sustained high levels of wholesale energy 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 quarter 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 of its gas supply as a retail customer of the
local gas supplier. 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 swap
agreements in May 2001 to hedge our risk of fluctuations in the
market price of gas related to approximately a third of our
anticipated gas purchases from June through October 2001. See
Results of Operations - Operating Expenses, below.
Credit Risk
-----------
UniSource Energy is exposed to credit risk in its energy
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-market value of any forward
contracts. As of December 31, 2001, TEP's total credit exposure
related to its wholesale trading activities (excluding defaulted
amounts owed by CPX, CISO and Enron), was less than $10 million, of
which 98% was with counterparties with investment grade ratings. At
December 31, 2001, MEG's total credit exposure was nominal due to
the start-up nature of the business. Based on a review of our
credit exposures at December 31, 2001, we do not anticipate any
nonperformance by any of our other counterparties. See Critical
Accounting Policies - Payment Defaults and Allowances for Doubtful
Accounts, below.
CRITICAL ACCOUNTING POLICIES
- ----------------------------
In preparing financial statements under GAAP, management
exercises judgement in the selection and application of accounting
principles, including making estimates and assumptions. We 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. We
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 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 continue to apply FAS 71 in accounting for the distribution
and transmission portions of TEP's business, our regulated
operations. We periodically assess whether we can continue to apply
FAS 71. If we stopped applying FAS 71 to TEP's remaining regulated
operations, we would write off the related balances of TEP's
regulatory assets as a charge in our income statement. Based on the
balances of TEP's regulatory assets at December 31, 2001, if we had
stopped applying FAS 71 to TEP's remaining regulated operations, we
would have recorded an extraordinary loss, after-tax, of
approximately $245 million. Our cash flows would not be affected if
we stopped applying FAS 71 unless a regulatory order limited our
ability to recover the cost of that regulatory asset.
See Note 2 of Notes to Consolidated Financial Statements -
Regulatory Matters.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In 1998, the Financial Accounting Standards Board (FASB) issued
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. 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.
When we adopted FAS 133 on January 1, 2001, 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. Some of the contracts qualified for hedge accounting
while some were considered to be trading activities. See Note 3 of
Notes to Consolidated Financial Statements.
We recorded the cumulative effects of adopting FAS 133 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 related asset
or liability 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 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 requirements of FAS
133. We implemented this new guidance, on a prospective basis,
beginning July 1, 2001. As a result, we determined the cash flow
hedge items 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, 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.
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. 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 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, we 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.
Recent events have 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 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 we ultimately collect would have an impact on our
earnings if the amount is more or less than the $8 million we have
reserved. If we collect all of the $16 million, pre-tax income will
increase by $8 million. If we do not collect any of the $16
million, pre-tax income will decrease by $8 million. We also
believe that we are due interest on the amounts we are 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 value of approximately $1 million. The unrealized gains
associated with these contracts were removed from TEP's revenues as
of 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 receivable 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 expect 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 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 on UED's balance sheet were approximately
$7 million. In addition, under certain limited circumstances
associated with the 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.
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. We then record
revenue for each customer class based on the various bill rates for
each customer class. Due to the seasonal fluctuations of our 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, a 40% increase over 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%,
largely 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 result of the robust wholesale
marketing conditions in the first five months of the year.
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 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:
- elimination 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 million at December 31,
2001. If the project is not completed, UED would immediately
expense the capitalized costs. In addition, under certain limited
circumstances associated with the 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. As of February 28, 2002, the capitalized costs of
UED's balance sheet are approximately $11 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
covenant that requires TEP to maintain a minimum level of net worth.
As of December 31, 2001, 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
with 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 the 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.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
OVERALL LIQUIDITY
Our primary source of liquidity is our cash flow from
operations, which exceeded $200 million in both 2001 and 2000.
These cash flows are 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, 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 million at year-end 1999 to $228 million at year-
end 2001. We have been using 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 our
cash flows from operations is reduced energy demand by our large
mining customers. As we have reported elsewhere in this document,
our two major mining customers have reduced operations during the
last few years due to lower copper prices. This trend will continue
in 2002 and we expect a 40 MW load reduction to our system peak
demand. We expect 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. We do not, therefore, expect
these reductions to have a significant impact on cash flows.
In the event that we experience lower cash from operations due
to these, or other events, 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 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.
Our primary sources of cash are dividends from our
subsidiaries, primarily TEP. In 2001 TEP paid dividends to its
parent of $50 million, compared with $30 million in 2000 and $34
million in 1999. In 1999, Millennium paid $10 million in dividends
to its parent.
We also received $13 million in December 2000 from the exercise
of 791,966 UniSource Energy Warrants into UniSource Energy common
stock, of which 30%, or $4 million, was invested in TEP as required
by the ACC Holding Company Order. See Note 15 of Notes to
Consolidated Financial Statements - Warrants.
Although no specific offerings are currently contemplated, we
may also issue debt and/or equity securities from time to time. If
cash flows were to fall short of expectations, we would 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
- -------------------------------------------------------------------------------------
During 2002, 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.
If cash flows were to fall short of expectations or if monthly cash
requirements temporarily exceeded available cash balances, TEP would
borrow from its Revolving Credit Facility. At December 31, 2001,
TEP had $100 million available under its Revolving Credit Facility.
Capital Expenditures
--------------------
TEP's forecasted construction expenditures for the next five
years are: $124 million in 2002, $156 million in 2003, $85 million
in 2004, $82 million in 2005, and $74 million in 2006. These
estimated capital expenditures for 2002-2006 break down in the
following categories:
- $289 million for transmission, distribution and other facilities
in the Tucson area;
- $44 million in renewable energy projects, including expansion of
its solar generation portfolio;
- $118 million for production facilities; and
- $70 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.
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, with an expected in-service date of December 31,
2003. Construction costs are expected to be approximately $70
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 Activities - UED, 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 Debt and Capital Lease
Obligations.
Bond Issuance and Redemption
----------------------------
During 2001, TEP purchased and retired $0.2 million of its
8.50% First Mortgage Bond 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
-------------------------
TEP has a $441 million Credit Agreement with a number of banks
which matures on December 30, 2002. The agreement consists of a
$100 million Revolving Credit Facility and a $341 million Letter of
Credit Facility. The Revolving Credit Facility is used to provide
liquidity for general corporate purposes. The Letter of Credit
Facility supports $329 million aggregate principal amount of tax-
exempt variable rate debt. The facilities are secured by $441
million in aggregate principal amount of Second Mortgage Bonds. The
Credit Agreement contains a number of restrictive covenants
including restrictions on additional indebtedness, liens, sale of
assets or mergers and sale-leasebacks. The Credit Agreement also
contains several financial covenants including (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 6.40 in 2001 and decreasing to 6.20 in 2002. As of
December 31, 2001, TEP was in compliance with these financial
covenants.
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 the credit rating on TEP's senior
secured debt. Also, TEP pays a commitment fee on the unused portion
of the Revolving Credit Facility, and a fee on the Letter of Credit
Facility. These fees are also dependent on TEP's credit ratings.
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. TEP had no borrowings outstanding
under the Revolving Credit Facility at December 31, 2001.
TEP intends to enter into a new credit agreement prior to the
maturity of its existing 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.
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, TEP had approximately $580 million of tax-exempt
local furnishing bonds outstanding. Approximately $325 million in
principal amount of such bonds financed Springerville Unit 2 and the
Express Line. In addition, approximately $72 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-
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 had the ability to issue
approximately $152 million of new First 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's Credit Agreement allows no more than $411 million of
First Mortgage Bonds to be outstanding. There were $224 million of
First Mortgage Bonds outstanding at December 31, 2001. Additionally,
the Credit Agreement contains certain financial covenants that limit
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.
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. TEP is required by its current
Settlement Agreement to form a wholly-owned generation subsidiary by
December 31, 2002. If this process proceeds, TEP will be
transferring certain property to the generation subsidiary and may
release all or a portion of the property from the liens of the
indentures based on the fair market values of the properties
transferred.
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 2001 and 2000.
Investments in Energy Technologies
----------------------------------
As of December 31, 2001, Millennium had provided the following
funding under its commitments to these Energy Technology
Investments:
- $19 million in debt to Global Solar, drawn on a $20 million line
of credit commitment;
- $6 million in debt 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.
Millennium expects to fund the remaining balance of $14 million
under its current commitments to its various energy technology
investments in 2002. A significant portion of the funding under
these agreements will be utilized for research and development
purposes, establishment of the production line, and other
administrative costs. As these funds are expended for these
purposes, we will recognize expense.
As of December 31, 2001, Millennium had approximately $45
million invested in these Energy Technology Investments. If 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, we will analyze the prospects for each of
these investments, determine if additional funding is needed, and
whether we will provide such funding or if we will look for outside
funding sources. If management determines that any of these
entities are not viable, we would take the appropriate write-offs.
Nations Energy
--------------
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 an $8
million note receivable in connection with this transaction. In
addition, $15 million in related construction deposits were returned
to Nations Energy.
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 contributed $5 million in capital and $4 million in
debt to MEG. Such funds were used to provide sufficient working
capital to facilitate MEG's entry into the emission allowance and
coal markets.
Millennium contributed $3 million in equity funding to
Powertrusion, in exchange for a controlling interest in
Powertrusion. Maintaining control of Powertrusion will depend upon
many factors, including providing an additional $2 million in
contingent consideration by August 2002. Contribution of the
contingent additional investment will be solely determined by
Millennium.
Millennium contributed $4 million to a limited partnership that
funds energy related investments. This investment brings
Millennium's funding to approximately $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 made a $1 million investment in a venture capital
fund. The fund will focus on information technology, optics 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
approximately $1 million under this agreement in 2002. A member of
the UniSource Energy Board of Directors owns 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
expansion of Springerville Units 3 and 4. On October 19, 2001, UED
and SRP signed a joint development agreement to share ownership and
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 expect to provide
between $30 million and $100 million in funding to UED during 2002.
Our funding to UED will depend upon the timing of 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. We can make no assurances, however, about the ultimate
timing, or whether we will proceed with this project.
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-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, 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.
5. 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. Changes in governmental policies and regulatory actions with
respect to financings and rate structures.
7. Changes affecting the cost of competing energy alternatives,
including changes in available generating technologies and changes
in the cost of natural gas.
8. Changes in accounting principles or the application of such
principles to UniSource Energy or TEP.
9. Market conditions and technological changes affecting UniSource
Energy's unregulated businesses.
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, page 106, for a list of the Consolidated Financial
Statements that are included in the following pages. See Note 18 of
Notes to Consolidated Financial Statements.
Report of Independent Accountants
To the Board of Directors and Stockholders of
UniSource Energy Corporation and to the
Board of Directors and Stockholder of
Tucson Electric Power Company
In our opinion, the consolidated financial statements listed
in the index appearing under Item 14(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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States
of America. In addition, in our opinion, the financial
statement schedule listed in the index appearing under Item 14
(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, 2002
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
2001 2000 1999
- -----------------------------------------------------------------------------
-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $ 670,117 $ 664,646 $ 629,900
Electric Wholesale Sales 761,255 359,814 171,219
Net Unrealized Loss on Forward Sales
and Purchases (1,347) - -
Other Revenues 14,683 9,209 13,709
- -----------------------------------------------------------------------------
Total Operating Revenues 1,444,708 1,033,669 814,828
- -----------------------------------------------------------------------------
Operating Expenses
Fuel 258,761 239,939 194,205
Purchased Power 570,283 207,596 92,144
Coal Contract Amendment Fee - 13,231 -
Capital Lease Expense - - 85,320
Amortization of Springerville
Unit 1 Allowance - - (29,098)
Other Operations and Maintenance 179,036 181,392 159,721
Depreciation and Amortization 120,346 114,038 92,740
Amortization of Transition Recovery
Asset 21,609 17,008 2,241
Taxes Other Than Income Taxes 46,213 50,137 48,473
- -----------------------------------------------------------------------------
Total Operating Expenses 1,196,248 823,341 645,746
- -----------------------------------------------------------------------------
Operating Income 248,460 210,328 169,082
- -----------------------------------------------------------------------------
Other Income (Deductions)
Interest Income 14,600 13,532 9,606
Gain on the Sale of NewEnergy - - 34,651
Other Income (Deductions) 3,868 (468) (2,380)
- -----------------------------------------------------------------------------
Total Other Income (Deductions) 18,468 13,064 41,877
- -----------------------------------------------------------------------------
Interest Expense
Long-Term Debt 61,218 66,377 66,836
Interest on Capital Leases 90,402 92,712 16,267
Interest Imputed on Losses Recorded at
Present Value 820 198 29,159
Other Interest Expense 6,139 7,059 10,995
- -----------------------------------------------------------------------------
Total Interest Expense 158,579 166,346 123,257
- -----------------------------------------------------------------------------
Income Before Income Taxes,
Extraordinary Item and Cumulative
Effect of Accounting Change 108,349 57,046 87,702
Income Taxes 47,474 15,155 31,192
- -----------------------------------------------------------------------------
Income Before Extraordinary Item and
Cumulative Effect of Accounting Change 60,875 41,891 56,510
Extraordinary Item - Net of Tax - - 22,597
Cumulative Effect of Accounting Change
- Net of Tax 470 - -
- -----------------------------------------------------------------------------
Net Income $ 61,345 $ 41,891 $ 79,107
=============================================================================
Average Shares of
Common Stock Outstanding (000) 33,399 32,445 32,321
=============================================================================
Basic Earnings per Share
Income Before Extraordinary Item and
Cumulative Effect of Accounting Change $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 $1.80 $1.27 $2.43
=============================================================================
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales $ 731,379 $ 716,955 $ 680,141
Cash Receipts from Electric Wholesale Sales 760,258 301,281 171,628
Fuel Costs Paid (262,283) (213,999) (183,093)
Purchased Power Costs Paid (544,472) (196,137) (93,258)
Wages Paid, Net of Amounts Capitalized (71,043) (61,862) (68,711)
Payment of Other Operations and
Maintenance Costs (127,382) (96,722) (96,998)
Capital Lease Interest Paid (79,745) (90,418) (82,421)
Interest Paid, Net of Amounts Capitalized (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 (38,951) (3,503) (23,593)
Transfer of Tax Settlement to Escrow Account - - (22,403)
Emission Allowance Inventory Purchases - - (13,666)
Other 3,110 5,473 8,667
- -------------------------------------------------------------------------------
Net Cash Flows - Operating Activities 215,379 215,034 113,228
- -------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (121,622) (105,996) (92,808)
Purchase of Springerville Lease Debt
and Equity (13,000) (27,633) (26,768)
Investments in and Loans to Equity Investees (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 4,041
Proceeds from the Sale of Real Estate 6,580 - -
Sale of Securities - - 27,516
Other (2,536) 7,281 2,143
- -------------------------------------------------------------------------------
Net Cash Flows - Investing Activities (116,847) (113,550) (93,050)
- -------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt - - 1,977
Payments to Retire Long-Term Debt (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) -
Payments to Retire Capital Lease Obligations (26,015) (39,019) (23,602)
Proceeds from the Exercise of Warrants - 12,671 -
Common Stock Dividends Paid (13,376) (10,349) -
Other 7,880 3,045 3,293
- -------------------------------------------------------------------------------
Net Cash Flows - Financing Activities (33,382) (83,768) (20,057)
- -------------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents 65,150 17,716 121
Cash and Cash Equivalents, Beginning of Year 163,004 145,288 145,167
- -------------------------------------------------------------------------------
Cash and Cash Equivalents, End of Year $ 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,
2001 2000
- -----------------------------------------------------------------------------
-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service $ 2,498,046 $ 2,389,587
Utility Plant Under Capital Leases 741,446 741,446
Construction Work in Progress 70,992 94,789
- -----------------------------------------------------------------------------
Total Utility Plant 3,310,484 3,225,822
Less Accumulated Depreciation and Amortization (1,270,089) (1,186,035)
Less Accumulated Depreciation of Capital
Lease Assets (362,724) (333,497)
- -----------------------------------------------------------------------------
Total Utility Plant - Net 1,677,671 1,706,290
- -----------------------------------------------------------------------------
Investments and Other Property 182,747 121,811
- -----------------------------------------------------------------------------
Current Assets
Cash and Cash Equivalents 228,154 163,004
Accounts Receivable 119,646 115,540
Materials and Fuel 45,052 44,399
Deferred Income Taxes - Current 11,165 17,790
Other 30,891 19,475
- -----------------------------------------------------------------------------
Total Current Assets 434,908 360,208
- -----------------------------------------------------------------------------
Regulatory and Other Assets
Transition Recovery Asset 331,674 353,283
Income Taxes Recoverable Through Future Revenues 64,239 73,459
Other Regulatory Assets 9,072 7,690
Other Assets 35,014 48,643
- -----------------------------------------------------------------------------
Total Regulatory and Other Assets 439,999 483,075
- -----------------------------------------------------------------------------
Total Assets $ 2,735,325 $ 2,671,384
=============================================================================
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity $ 424,722 $ 372,169
Capital Lease Obligations 853,793 857,829
Long-Term Debt 802,804 1,132,395
- -----------------------------------------------------------------------------
Total Capitalization 2,081,319 2,362,393
- -----------------------------------------------------------------------------
Current Liabilities
Current Obligations Under Capital Leases 20,158 21,147
Current Maturities of Long-Term Debt 330,424 1,725
Accounts Payable 84,011 65,891
Interest Accrued 53,300 63,852
Taxes Accrued 25,904 26,811
Accrued Employee Expenses 13,577 14,405
Other 16,105 8,547
- -----------------------------------------------------------------------------
Total Current Liabilities 543,479 202,378
- -----------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 43,507 51,035
Other 67,020 55,578
- -----------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 110,527 106,613
- -----------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
- -----------------------------------------------------------------------------
Total Capitalization and Other Liabilities $ 2,735,325 $ 2,671,384
=============================================================================
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
2001 2000
- ----------------------------------------------------------------------------
COMMON STOCK EQUITY - Thousands of Dollars -
Common Stock--No Par Value $ 660,123 $ 655,539
2001 2000
---------- ----------
Shares Authorized 75,000,000 75,000,000
Shares Outstanding 33,502,007 33,218,503
Accumulated Deficit (235,401) (283,370)
Accumulated Other Comprehensive Income - -
- ----------------------------------------------------------------------------
Total Common Stock Equity 424,722 372,169
- ----------------------------------------------------------------------------
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized,
None Outstanding - -
- ----------------------------------------------------------------------------
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 492,838 476,409
Springerville Coal Handling Facilities 156,427 159,944
Springerville Common Facilities 131,744 141,097
Irvington Unit 4 90,831 99,241
Other Leases 2,111 2,285
- ----------------------------------------------------------------------------
Total Capital Lease Obligations 873,951 878,976
Less Current Maturities (20,158) (21,147)
- ----------------------------------------------------------------------------
Total Long-Term Capital Lease Obligations 853,793 857,829
- ----------------------------------------------------------------------------
LONG-TERM DEBT
Interest
Issue Maturity Rate
- ----------------------------------------------------------------------------
First Mortgage Bonds
Corporate 2009 8.50% 27,754 27,900
Industrial Development
Revenue Bonds (IDBs) 2006 - 2008 6.10% to 7.50% 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
Other Long-Term Debt 979 -
- ----------------------------------------------------------------------------
Total Stated Principal Amount 1,133,228 1,134,120
Less Current Maturities* (330,424) (1,725)
- ----------------------------------------------------------------------------
Total Long-Term Debt 802,804 1,132,395
- ----------------------------------------------------------------------------
Total Capitalization $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. 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.
** Weighted average interest rates on variable rate tax-exempt debt (IDBs)
ranged from 1.40% to 5.02% during 2001 and 2000, and the average interest rate
on such debt was 2.67% in 2001 and 4.17% in 2000.
UniSource Energy also has stock options outstanding. See Note 13.
See Notes to Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Accumulated
Accumulated Other Total
Common Earnings Comprehensive Stockholders'
Stock (Deficit) Income (Loss) Equity
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Balances at December 31, 1998 $ 640,640 $(393,994) $ - $ 246,646
1999 Net Income - 79,107 - 79,107
Dividends Declared - (2,588) - (2,588)
107,567 Shares Issued under
Stock Compensation and
Purchase Plans 1,277 - - 1,277
16,439 Net 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 (75) - - (75)
799,540 Shares Issued for
Warrants and Stock Options 12,768 - - 12,768
- -------------------------------------------------------------------------------
Balances at December 31, 2000 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 2,210 - - 2,210
7,129 Net Shares Purchased by
Deferred Compensation Trust
Less Distributions (215) - - (215)
177,777 Shares Issued for
Stock Options 2,589 - - 2,589
- -------------------------------------------------------------------------------
Balances at December 31, 2001 $ 660,123 $(235,401) $ - $ 424,722
===============================================================================
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,
2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $ 670,117 $ 664,646 $ 629,900
Electric Wholesale Sales 761,255 359,814 171,219
Net Unrealized Loss on Forward Electric
Sales and Purchases (1,315) - -
Other Revenues 6,308 3,908 2,964
- -------------------------------------------------------------------------------
Total Operating Revenues 1,436,365 1,028,368 804,083
- -------------------------------------------------------------------------------
Operating Expenses
Fuel 258,761 239,939 194,205
Purchased Power 570,283 207,596 92,144
Coal Contract Amendment Fee - 13,231 -
Capital Lease Expense - - 85,320
Amortization of Springerville
Unit 1 Allowance - - (29,098)
Other Operations and Maintenance 158,118 162,322 142,915
Depreciation and Amortization 117,063 113,507 92,583
Amortization of Transition Recovery Asset 21,609 17,008 2,241
Taxes Other Than Income Taxes 45,047 49,445 47,789
- -------------------------------------------------------------------------------
Total Operating Expenses 1,170,881 803,048 628,099
- -------------------------------------------------------------------------------
Operating Income 265,484 225,320 175,984
- -------------------------------------------------------------------------------
Other Income
Interest Income 11,910 8,550 7,935
Interest Income - Note Receivable from
UniSource Energy 9,330 9,329 9,937
Other Income 2,499 820 2,602
- -------------------------------------------------------------------------------
Total Other Income 23,739 18,699 20,474
- -------------------------------------------------------------------------------
Interest Expense
Long-Term Debt 61,218 66,377 66,836
Interest on Capital Leases 90,348 92,658 16,241
Interest Imputed on Losses Recorded at
Present Value 820 198 29,159
Other Interest Expense 6,113 7,051 10,994
- -------------------------------------------------------------------------------
Total Interest Expense 158,499 166,284 123,230
- -------------------------------------------------------------------------------
Income Before Income Taxes, Extraordinary
Item and Cumulative Effect of Accounting
Change 130,724 77,735 73,228
Income Taxes 55,910 26,566 22,350
- -------------------------------------------------------------------------------
Income Before Extraordinary Item and
Cumulative Effect of Accounting Change 74,814 51,169 50,878
Extraordinary Item - Net of Tax - - 22,597
Cumulative Effect of Accounting Change
- Net of Tax 470 - -
- -------------------------------------------------------------------------------
Net Income $ 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,
2001 2000 1999
- ------------------------------------------------------------------------------
-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales $ 731,379 $ 716,955 $ 680,141
Cash Receipts from Electric Wholesale Sales 760,258 301,281 171,628
Fuel Costs Paid (262,283) (213,999) (183,093)
Purchased Power Costs Paid (544,472) (196,137) (93,258)
Wages Paid, Net of Amounts Capitalized (61,839) (54,469) (61,697)
Payment of Other Operations and
Maintenance Costs (98,628) (82,750) (89,020)
Capital Lease Interest Paid (79,663) (90,365) (82,414)
Interest Paid, Net of Amounts Capitalized (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 (38,950) (3,503) (22,156)
Transfer of Tax Settlement to Escrow Account - - (22,403)
Emission Allowance Inventory Purchases - - (13,666)
Other 703 92 1,292
- ------------------------------------------------------------------------------
Net Cash Flows - Operating Activities 261,169 234,190 139,957
- ------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (103,913) (98,063) (90,940)
Purchase of Springerville Lease Debt
and Equity (15,167) (25,070) (26,768)
Proceeds from the Sale of Real Estate 6,580 - -
Investments in and Loans to Equity
Investees - (2,000) -
Other (3,394) 3,797 2,288
- ------------------------------------------------------------------------------
Net Cash Flows - Investing Activities (115,894) (121,336) (115,420)
- ------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt - - 1,977
Payments to Retire Long-Term Debt (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) -
Payments to Retire Capital Lease Obligations (25,875) (38,855) (23,563)
Dividend Paid (50,000) (30,000) (34,000)
Other 3,439 6,427 2,940
- ------------------------------------------------------------------------------
Net Cash Flows - Financing Activities (74,307) (112,544) (54,371)
- ------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and
Cash Equivalents 70,968 310 (29,834)
Cash and Cash Equivalents, Beginning of Year 88,712 88,402 118,236
- ------------------------------------------------------------------------------
Cash and Cash Equivalents, End of Year $ 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,
2001 2000
- ----------------------------------------------------------------------------
-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service $ 2,498,046 $ 2,389,587
Utility Plant Under Capital Leases 741,446 741,446
Construction Work in Progress 70,992 94,789
- ----------------------------------------------------------------------------
Total Utility Plant 3,310,484 3,225,822
Less Accumulated Depreciation and Amortization (1,270,089) (1,186,035)
Less Accumulated Depreciation of Capital
Lease Assets (362,724) (333,497)
- ----------------------------------------------------------------------------
Total Utility Plant - Net 1,677,671 1,706,290
- ----------------------------------------------------------------------------
Investments and Other Property 105,875 92,334
- ----------------------------------------------------------------------------
Note Receivable from UniSource Energy 70,132 70,132
- ----------------------------------------------------------------------------
Current Assets
Cash and Cash Equivalents 159,680 88,712
Accounts Receivable 124,487 116,580
Materials and Fuel 43,682 43,847
Deferred Income Taxes - Current 4,603 10,662
Other 7,814 6,585
- ----------------------------------------------------------------------------
Total Current Assets 340,266 266,386
- ----------------------------------------------------------------------------
Regulatory and Other Assets
Transition Recovery Asset 331,674 353,283
Income Taxes Recoverable Through Future Revenues 64,239 73,459
Other Regulatory Assets 9,072 7,690
Other Assets 35,014 31,361
- ----------------------------------------------------------------------------
Total Regulatory and Other Assets 439,999 465,793
- ----------------------------------------------------------------------------
Total Assets $ 2,633,943 $ 2,600,935
============================================================================
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity $ 322,471 $ 295,660
Capital Lease Obligations 853,447 857,519
Long-Term Debt 801,924 1,132,395
- ----------------------------------------------------------------------------
Total Capitalization 1,977,842 2,285,574
- ----------------------------------------------------------------------------
Current Liabilities
Current Obligations Under Capital Leases 19,971 21,031
Current Maturities of Long-Term Debt 330,325 1,725
Accounts Payable 89,193 73,955
Interest Accrued 53,300 63,852
Taxes Accrued 23,015 25,485
Accrued Employee Expenses 13,078 14,152
Other 6,531 5,671
- ----------------------------------------------------------------------------
Total Current Liabilities 535,413 205,871
- ----------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 56,906 53,980
Other 63,782 55,510
- ----------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 120,688 109,490
- ----------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
- ----------------------------------------------------------------------------
Total Capitalization and Other Liabilities $ 2,633,943 $ 2,600,935
============================================================================
See Notes to Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
2001 2000
- ---------------------------------------------------------------------------
COMMON STOCK EQUITY - Thousands of Dollars -
Common Stock--No Par Value $ 653,250 $ 651,723
2001 2000
---------- ----------
Shares Authorized 75,000,000 75,000,000
Shares Outstanding* 32,139,554 32,139,434
Warrants Outstanding** 918,325 918,445
Capital Stock Expense (6,357) (6,357)
Accumulated Deficit (324,422) (349,706)
Accumulated Other Comprehensive Income - -
- ---------------------------------------------------------------------------
Total Common Stock Equity 322,471 295,660
- ---------------------------------------------------------------------------
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized,
None Outstanding - -
- ---------------------------------------------------------------------------
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 492,838 476,409
Springerville Coal Handling Facilities 156,427 159,944
Springerville Common Facilities 131,744 141,097
Irvington Unit 4 90,831 99,241
Other Leases 1,578 1,859
- ---------------------------------------------------------------------------
Total Capital Lease Obligations 873,418 878,550
Less Current Maturities (19,971) (21,031)
- ---------------------------------------------------------------------------
Total Long-Term Capital Lease Obligations 853,447 857,519
- ---------------------------------------------------------------------------
LONG-TERM DEBT
Interest
Issue Maturity Rate
- ---------------------------------------------------------------------------
First Mortgage Bonds
Corporate 2009 8.50% 27,754 27,900
Industrial Development
Revenue Bonds (IDBs) 2006 - 2008 6.10% to 7.50% 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 1,132,249 1,134,120
Less Current Maturities*** (330,325) (1,725)
- ---------------------------------------------------------------------------
Total Long-Term Debt 801,924 1,132,395
- ---------------------------------------------------------------------------
Total Capitalization $1,977,842 $2,285,574
===========================================================================
* UniSource Energy is the holder of all but 120 shares of TEP's outstanding
common stock.
** There are 4.6 million outstanding TEP warrants which entitle the holder of
five warrants to purchase one share of TEP common stock for $16.00. See Note 15.
*** 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. 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.
**** Weighted average interest rates on variable rate tax-exempt debt (IDBs)
ranged from 1.40% to 5.02% during 2001 and 2000, and the average interest rate
on such debt was 2.67% in 2001 and 4.17% in 2000.
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 $646,568 $(6,357) $(410,350) $ - $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
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
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 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 $653,250 $(6,357) $(324,422) $ - $322,471
===============================================================================
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. Approximately 60% of TEP's work force is subject
to a collective bargaining unit. The collective bargaining agreement in place
at December 31, 2001 terminates on January 6, 2003.
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. UniSource Energy paid TEP $9 million in each of 2001 and 2000
and $19 million in 1999 for the interest owed under this note.
UniSource Energy and TEP use the following two methods to report
investments in their subsidiaries or other companies:
- Consolidation: When we own a majority of the voting stock of a
subsidiary, we combine the accounts of the subsidiary with our accounts and
eliminate intercompany balances and transactions.
- The Equity Method: We use the equity method to report corporate joint
ventures, partnerships, and affiliated companies when we hold a 20% to 50%
voting interest or we have the ability to exercise significant influence over
the operating and financial policies of the investee company. Under the equity
method, we report:
- Our interest in the equity of an entity as an investment on our
balance sheet; and
- Our percentage share of the net income (loss) from the entity as Other
Income in our income statements. For investments where we provide all of the
financing, we recognize 100% of the losses.
USE OF ACCOUNTING ESTIMATES
Management makes estimates and assumptions when preparing financial
statements under Generally Accepted Accounting Principles (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 electricity 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
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's utility plant on our balance sheets at its original cost.
Utility plant includes:
- Material and labor,
- Contractor costs,
- Construction overhead costs (where applicable), and
- An Allowance for Funds Used During Construction (AFUDC) or capitalized
interest.
AFUDC reflects the cost of financing construction projects with borrowed
funds and equity funds. The component of AFUDC attributable to borrowed funds
is included as a reduction of Other Interest Expense on the income statement.
The equity component is included in Other Income. In 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. The capitalized interest on our generation-related
construction projects is included as a reduction of Other Interest Expense on
the income statement. The average capitalized interest rate applied to
generation-related construction expenditures was 4.93% and 5.58% in 2001 and
2000, respectively.
Depreciation
We compute depreciation for owned utility plant on a straight-line basis
at rates based on the economic lives of the assets. These rates are approved
by the ACC and averaged 3.88%, 3.85% and 3.68% in 2001, 2000 and 1999,
respectively. The economic lives for generation plant are based on remaining
lives. The economic 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 for 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 our 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.
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 Property line item. Properties and equipment are stated
at 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.
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 it is probable that the
project will be completed and we expect 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 determine that the project is impaired.
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 defer 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
amortize 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 over the remaining original life of the debt to
interest expense. Effective November 1, 1999, we recognize gains and losses
on reacquired debt associated with the generation portion of TEP's operations
as incurred. We reclassified any remaining generation-related unamortized
gains 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 amortize the gains and
losses on reacquired debt associated with TEP's regulated operations to
interest income or expense over the remaining life of the original debt.
ELECTRIC UTILITY OPERATING REVENUES
We record electric utility operating revenues when we deliver 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 record an expense and reduce accounts receivable by an Allowance for
Doubtful Accounts for revenue amounts that we estimate will become
uncollectible. The Allowance for Doubtful Accounts was $9 million and $10
million at December 31, 2001 and 2000, respectively. 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 million in 2001, $4 million in 2000 and $4 million in 1999.
Global Solar recognized total annual research and development expense of $7
million in 2001 and 2000 and $5 million in 1999. 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 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.
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 assets and
liabilities using income tax rates that are currently in effect.
We allocate income taxes to the subsidiaries based on their taxable
income and deductions used in the consolidated tax return.
EMISSION ALLOWANCES
Emission Allowances are issued by the Environmental Protection Agency
(EPA) and each permits emission of one ton of sulfur dioxide (SO2). These
allowances can be bought or sold. Prior to November 1, 1999, based on
expected future regulatory treatment, 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. See Note 10.
NEW ACCOUNTING STANDARDS
During 2001, the Financial Accounting Standards Board (FASB) 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.
- FAS 143, Accounting for Asset Retirement Obligations, which requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. 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
accreted to its present value, 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 upon settlement. We are required to comply with FAS 143 beginning
January 1, 2003. We are currently in the process of evaluating the impact of
FAS 143 on our financial statements.
- FAS 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, which provides guidance on the financial accounting 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 our financial
statements.
RECLASSIFICATIONS
We consolidated Income Taxes into a single line item, which is presented
below Income Before Income Taxes, Extraordinary Item 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. We have made other
reclassifications to the prior year financial statements for comparative
purposes. 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 approval 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 allow 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 Value in the
Interest Expense section in the income statements 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.
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 be 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 Total
Transition Costs Being Recovered through the Fixed CTC were amortized as
follows:
Years Ended December 31,
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
Amortization of Transition Recovery Asset
recorded on the income statement (21) (17)
Generation-Related Plant Asset Amortization (3) (3)
Excess Capacity Deferral Amortization
(off balance sheet) (9) (9)
- -------------------------------------------------------------------------------
Remaining Transition Recovery Asset to be
Recovered Through the Fixed CTC, end of year $ 386 $ 419
===============================================================================
Transition Recovery Asset Recorded on the
balance sheet, beginning of year $ 353 $ 370
Amortization of Transition Recovery Asset
recorded on the income statement (21) (17)
- -------------------------------------------------------------------------------
Remaining Transition Recovery Asset on the
balance sheet, end of year $ 332 $ 353
===============================================================================
The Generation-Related Plant Assets are included in Plant in Service on
the balance sheet. The unamortized balance of such generation-related costs
totaled $36 million at December 31, 2001. The Excess Capacity Deferrals are
not reflected on our balance sheet and relate 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 unamortized
balance of the off-balance sheet excess capacity deferral totaled $18 million
at December 31, 2001.
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 comes first.
REGULATORY ASSETS AT DECEMBER 31, 2001 AND 2000
The balances of regulatory assets at December 31, 2001 and 2000 are noted
in the table below. There are no remaining regulatory liabilities recorded on
the balance sheets at December 31, 2001 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
=====================================================================
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 our income statements:
Years Ended December 31,
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 21 17 2
Interest Expense
Long-Term Debt 1 2 3
Interest Imputed on Losses Recorded at Present Value - - 29
Income Taxes 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 our 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 OUR REGULATED BUSINESS
We continue to apply FAS 71 for the distribution and transmission
portions of TEP's business, our regulated operations. We periodically assess
whether we can continue to apply FAS 71. If we stopped applying FAS 71 to
TEP's remaining regulated operations, we would write off the related balances
of TEP's regulatory assets as a charge in our income statement. Based on the
balances of TEP's regulatory assets at December 31, 2001, if we had stopped
applying FAS 71 to TEP's remaining regulated operations, we would have
recorded an extraordinary loss, after-tax, of approximately $245 million.
While regulatory orders and market conditions may affect our cash flows, our
cash flows would not be affected if we stopped applying FAS 71 unless a
regulatory order limited our 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.
In a letter dated January 14, 2002, ACC Chairman William A. Mundell
suggested the following possible outcomes to the proceedings:
- Implementation of the Rules according to the existing schedule,
- Delayed 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, the ACC sent a list of questions related 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, may be set. We are uncertain what the outcome
of this proceeding will be.
NOTE 3. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
- ---------------------------------------------------------------------
In 1998, the FASB issued 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 for 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 in the daily or hourly markets at
fluctuating spot market prices and other non-firm energy sales.
(4) Sales of transmission service.
Based on our interpretation 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 other 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 as 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 adopting FAS 133 as of January 1,
2001, as follows. The financial statements for periods prior to 2001 do not
reflect 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 in the market price of gas related to approximately 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), a
wholly-owned subsidiary of Millennium, began operations and entered into swap
agreements and forward contracts relating to SO2 Emission Allowances. These
activities are considered to be trading activities. In 2001, we recorded a
pre-tax unrealized loss of less than $0.1 million related to MEG activities.
NEW ACCOUNTING GUIDANCE DURING 2001
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 requirements of FAS 133. We implemented this new guidance,
on a prospective basis, beginning July 1, 2001. As a result, we determined
the cash flow hedge items (certain forward contracts but not the gas swap
agreements) 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, 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.
On December 19, 2001, the FASB approved revisions to clarify the
qualifying criteria outlined 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.
NOTE 4. MILLENNIUM ENERGY BUSINESSES
- -------------------------------------
See Note 5 for selected financial data of Millennium.
ENERGY TECHNOLOGY INVESTMENTS
Millennium owns 67% of the following entities and their financial
statements are consolidated into the Millennium and UniSource Energy financial
statements. A privately held company owns the remaining 33%.
- Global Solar is a developer and manufacturer of flexible thin-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, Millennium owned 50% of Global Solar 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, minority interest
is not reflected in the financial statements and Millennium records 100% of
Global Solar's losses for accounting purposes. When Global Solar generates
net income, Millennium will recognize 100% of net income to the extent
Millennium's recognized losses are greater than Millennium's ownership
percentage of such losses.
- Infinite Power Solutions, Inc. is a developer of thin-film batteries
and was established in 2000. The other owner contributed certain assets and
proprietary and intellectual property relating to thin-film battery
technology.
In 2001 and 2000, Millennium provided $0.2 million and $15 million,
respectively, in equity funding to these entities. In 2001, 2000 and 1999,
Millennium provided net debt funding to these entities of approximately $20
million, $2 million 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.
- MicroSat Systems, Inc. (MicroSat) is a space systems company formed to
develop and commercialize small-scale satellites. Millennium currently owns
49% and provided $10 million in equity funding during 2001. The other owner
contributed development contracts and proprietary technologies.
- ITN Energy Systems, Inc. (ITN) was formed to provide research and
development and other services to affiliates, the Government and other third
parties. Millennium currently owns 49%. Millennium contributed $3 million of
equity and $1.6 million of debt to ITN during 2001. The other owner
contributed contracts and intellectual property.
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 of remaining cost share commitments under these
contracts at December 31, 2001.
We are currently evaluating and renegotiating our 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.
Millennium expects to fund the remaining balance under its current
commitments, approximately $14 million, to its various Energy Technology
Investments in 2002. We 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 recognize expense.
INTERNATIONAL POWER PROJECTS - NATIONS ENERGY CORPORATION
Nations Energy is a wholly-owned subsidiary of Millennium. Through its
subsidiaries, Nations has a 40% equity interest in a 43 MW power plant near
Panama City, Panama. 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. 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.
In 2001, Nations Energy recorded an after-tax gain of $5.6 million from
the sale of its 26% equity interest in a power project located in Curacao,
Netherland Antilles. Nations Energy received $5 million in cash proceeds, the
return of cash construction deposits and recorded an $8 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 net present value,
and 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 gain of approximately $3
million from the sale 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 2000
cash flow statement.
OTHER MILLENNIUM INVESTMENTS AND COMMITMENTS
In July 2000, Millennium made a $15 million capital commitment to a
limited partnership which will fund energy related investments. As of
December 31, 2001, Millennium has funded approximately $6 million under this
commitment, $4 million of which was funded in 2001. The remaining $9 million
is expected to be invested within three years. The limited partnership's
results of operation are recognized under the equity method based on our
ownership percentage. 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.
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.
NOTE 5. SEGMENT AND RELATED INFORMATION
- ----------------------------------------
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.
(2) Millennium holds interests in unregulated energy businesses (see Note
4).
(3) UED, established in 2001, engages in developing generating resources
and other project development activities. UED owns a 20 MW gas turbine under
lease to TEP. It is also responsible for developing Springerville Units 3 and
4 for the expansion of the Springerville Generating Station.
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 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
2001 TEP Millennium UED Adjustments Consolidated
- -------------------------------------------------------------------------------
-Millions of Dollars-
Income Statement
- ----------------
Operating Revenues
- External $1,436 $ 9 $ - $ - $1,445
- -------------------------------------------------------------------------------
Operating Revenues
- Intersegment - 13 2 (15) -
- -------------------------------------------------------------------------------
Depreciation and Amortization 117 3 - - 120
- -------------------------------------------------------------------------------
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 Investees - (18) - - (18)
- -------------------------------------------------------------------------------
Balance Sheet
- -------------
Total Assets 2,634 176 27 (102) 2,735
- -------------------------------------------------------------------------------
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
- -------------------------------------------------------------------------------
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 Investees (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,
2001 2000
-----------------------------------------------------------------------
-Millions of Dollars-
Plant in Service:
Generation Plant $ 1,133 $ 1,082
Transmission Plant 508 502
Distribution Plant 692 643
General Plant 120 118
Intangible Plant 44 44
Electric Plant Held for Future Use 1 1
-----------------------------------------------------------------------
Total Plant in Service $ 2,498 $ 2,390
=======================================================================
Utility Plant Under Capital Leases $ 741 $ 741
=======================================================================
All Utility Plant Under Capital Leases is used in TEP's generation
operations. See TEP Utility Plant and TEP Utility Plant Under Capital Leases
in Note 1 and Capital Lease Obligations in Note 7.
JOINTLY-OWNED FACILITIES
At December 31, 2001, TEP's interests in generating stations and
transmission systems that are jointly-owned with other utilities were as
follows:
Percent Plant Construction
Owned by In Work In Accumulated
TEP Service* Progress Depreciation
- -------------------------------------------------------------------------------
-Millions of Dollars-
San Juan Units 1 and 2 50.0% $ 289 $ 6 $ 226
Navajo Station Units 1,2 and 3 7.5 124 1 66
Four Corners Units 4 and 5 7.0 79 1 69
Transmission Facilities 7.5 to 95.0 224 - 145
- -------------------------------------------------------------------------------
Total $ 716 $ 8 $ 506
===============================================================================
* 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 our 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, TEP made the required sinking fund payments of $2 million on
its First Mortgage IDBs and redeemed $0.2 million of its 8.5% First Mortgage
Bonds. TEP did not issue any new bonds in 2001.
During 2000, TEP repaid as scheduled $47 million of its 12.22% Series
First Mortgage Bonds which matured on June 1. In addition, 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 MORTGAGE
TEP's first and second mortgage indentures are collateralized by a lien
on TEP's utility plant, with the exception of Springerville Unit 2. San
Carlos, a 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 AGREEMENT
TEP has a $441 million Credit Agreement which provides a $100 million
Revolving Credit Facility and a $341 million Letter of Credit Facility (LOC).
These credit facilities mature on December 30, 2002 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.
The Revolving Credit Facility can be used 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 rate that we pay is dependent, in part, 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.
The $341 million LOC Facility secures the payment of principal and
interest on $329 million of tax-exempt variable rate bonds (IDBs). The amount
of commitment fee on the LOC Facility depends on TEP's credit ratings. At
December 31, 2001, the commitment fee equaled 1.25% per year. 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.
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.
MATURITIES AND SINKING FUND REQUIREMENTS
TEP's long-term debt, including sinking funds, and lease obligations
mature on the following dates:
IDBs Scheduled
Supported by Long-Term Capital
Expiring Debt Lease
LOCs Retirements Obligations Total
------------------------------------------------------------------------
-Millions of Dollars-
2002 $ 329 $ 2 $ 90 $ 421
2003 - 2 123 125
2004 - 2 125 127
2005 - 2 125 127
2006 - 21 127 148
------------------------------------------------------------------------
Total 2002 - 2006 329 29 590 948
Thereafter - 775 1,125 1,900
Less: Imputed Interest - - (842) (842)
------------------------------------------------------------------------
Total $ 329 $ 804 $ 873 $2,006
========================================================================
In addition to the capital lease obligations above, we 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 us to repurchase the Springerville
Common Facilities 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.
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 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.
NOTE 8. FAIR VALUE OF UNISOURCE ENERGY FINANCIAL INSTRUMENTS
- -------------------------------------------------------------
The carrying values and fair value of TEP and Millennium's financial
instruments are as follows:
December 31,
2001 2000
- -------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- -------------------------------------------------------------------------------
-Millions of Dollars-
Millennium
Assets
Springerville Lease
Debt Securities (Included in
Investments and Other Property) $ - $ - $ 2 $ 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 - -
Liabilities
First Mortgage Bonds - Fixed Rate:
Corporate 28 28 28 29
Industrial Development Revenue
Bonds (IDBs) 58 59 60 60
First Collateral Trust Bonds 138 138 138 137
Second Mortgage Bonds - IDBs
(Variable Rate) 329 329 329 329
Unsecured IDBs - Fixed Rate 579 534 579 533
- -------------------------------------------------------------------------------
In 2000, Millennium purchased $27 million of 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.
TEP intends to hold the investment in Springerville Lease Debt Securities
to maturity ($42 million matures through January 1, 2009 and $29 million
matures through January 1, 2013). These Springerville Lease Debt Securities
are stated at amortized cost, which means the purchase cost has been adjusted
for the amortization of the premium and discount to maturity. We base 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. We determined the fair value of
TEP's 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. We used a rate consistent with market yields generally available
as of December 2001 for 2001 amounts and December 2000 for 2000 amounts for
bonds with similar characteristics with respect to credit rating, 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. DIVIDEND LIMITATIONS
- -----------------------------
UNISOURCE ENERGY
In February 2002, UniSource Energy declared a quarterly dividend to the
shareholders of $0.125 per share of UniSource Energy Common Stock. The
dividend, totaling approximately $4.0 million, will be paid on March 8, 2002
to common shareholders of record as of February 21, 2002. In 2001, UniSource
Energy paid quarterly dividends to the shareholders of $0.10 per share,
totaling approximately $13 million and $0.40 per share for the year. During
2000, UniSource Energy paid quarterly dividends to the shareholders of $0.08
per share, totaling $10 million and $0.32 per share 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, TEP, Millennium and UED.
TEP
TEP paid dividends of $50 million in 2001, $30 million in 2000, and $34
million in 1999. UniSource Energy is the primary holder of TEP's common
stock. TEP met the following requirements before paying these dividends:
- Bank Credit Agreement
TEP's bank Credit Agreement allows TEP to pay dividends as long as TEP
maintains compliance with the agreement and meets financial covenants.
- 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 2001, 2000 and 1999 dividends were paid
from current year earnings.
MILLENNIUM AND UED
Millennium did not pay any dividends to UniSource Energy in 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.
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.
TEP
At December 31, 2001, 4.6 million of TEP Warrants, which expire on
December 15, 2002, were outstanding. The 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. 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.
NOTE 17. SUPPLEMENTAL CASH FLOW INFORMATION
- --------------------------------------------
We 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,
2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Net Income $ 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 120,346 114,038 92,740
Coal Contract Amendment Fee - 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 21,609 17,008 2,302
Net Unrealized Loss on Forward Sales
and Purchases 564 - -
Amortization of Deferred Debt-Related
Costs included in Interest Expense 1,996 3,167 5,091
Deferred Contract Termination Fee - - 3,205
Unremitted Losses of
Unconsolidated Subsidiaries 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) - -
Other (8,963) 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)
Materials and Fuel 4,011 (2,280) (5,579)
Accounts Payable 17,626 37,655 36
Taxes Accrued (907) 4,908 (929)
Interest Accrued 10,191 2,543 (1,108)
Other Current Assets (14,094) (7,647) (4,988)
Other Current Liabilities (4,328) 5,891 (6,528)
Other Deferred Assets (2,149) 5,801 (2,961)
Other Deferred Liabilities 12,142 3,655 (5,685)
- -------------------------------------------------------------------------------
Net Cash Flows - Operating Activities $215,379 $215,034 $113,228
===============================================================================
TEP
------------------------------------
Years Ended December 31,
2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Net Income $ 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 117,063 113,507 92,583
Coal Contract Amendment Fee - 13,231 -
Deferred Income Taxes and Investment
Tax Credit 18,205 27,633 277
Lease Payments Deferred - - 28,318
Amortization of Transition Recovery Asset 21,609 17,008 2,302
Net Unrealized Loss on Forward Electric
Sales and Purchases 532 - -
Amortization of Deferred Debt-Related
Costs included in Interest Expense 1,996 3,167 5,091
Deferred Contract Termination Fee - - 3,205
Unremitted (Earnings) Losses of
Unconsolidated Subsidiaries 1,812 2,414 (471)
Emission Allowances - - (12,926)
Interest Accrued on Note Receivable from
UniSource Energy - - 9,329
Other 865 157 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)
Materials and Fuel 4,829 (1,812) (5,540)
Accounts Payable 15,238 36,981 (2)
Taxes Accrued (2,470) 7,218 (4,491)
Interest Accrued 10,191 2,543 (1,108)
Other Current Assets (1,229) (336) (3,366)
Other Current Liabilities (3,358) 973 (6,432)
Other Deferred Assets (3,857) 3,341 (2,961)
Other Deferred Liabilities 8,972 3,644 (5,699)
- -------------------------------------------------------------------------------
Net Cash Flows - Operating Activities $261,169 $234,190 $139,957
===============================================================================
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,
2001 2000 1999
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Capital Lease Obligations $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 are non-cash investing and financing activities of Millennium,
and therefore, are 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 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.
NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)
- ----------------------------------------------
UniSource Energy
------------------------------------------
First Second Third Fourth
- -------------------------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
2001
Operating Revenues $283,665 $406,615 $429,662 $324,766
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:
- ------------------------
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:
- --------------------------
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-
2001
Operating Revenues $281,800 $404,027 $427,483 $323,055
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 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:
TEP
- FIRST QUARTER 2001: TEP RECORDED A $0.5 MILLION UNREALIZED GAIN FOR THE
CUMULATIVE EFFECTS OF ADOPTING FAS 133 FOR ITS FORWARD WHOLESALE TRADING
ACTIVITY. SEE NOTE 3.
- SECOND QUARTER 2000: TEP RECOGNIZED A $6 MILLION TAX BENEFIT DUE TO THE
RESOLUTION OF VARIOUS TAX ITEMS. SEE NOTE 12.
- THIRD QUARTER 2000: 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 UNUSUAL 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 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 OF 2001, WE 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
------------------------------------------
First Second Third Fourth
- -------------------------------------------------------------------------------
-Thousands of Dollars-
2001
Operating Revenues - Historical $241,206 $406,615 $429,662 $324,766
Reclassification 42,459 - - -
Operating Revenues - Restated 283,665 406,615 429,662 324,766
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-
2001
Operating Revenues - Historical $239,341 $404,027 $427,483 $323,055
Reclassification 42,459 - - -
Operating Revenues - Restated 281,800 404,027 427,483 323,055
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
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 2002 Annual
Meeting of Shareholders, which will be filed with the SEC not later
than 120 days after December 31, 2001, 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 S. 58 CHAIRMAN, PRESIDENT AND CHIEF 1998
PIGNATELLI EXECUTIVE OFFICER
Mr. Pignatelli joined TEP as Senior Vice President in 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.
MICHAEL J. 37 SENIOR VICE PRESIDENT, STRATEGIC 1999
DECONCINI PLANNING AND INVESTMENTS
Mr. DeConcini joined TEP in 1988 and served in various 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, Strategic Planning and
Investments of UniSource Energy in October 2000.
DENNIS R. NELSON 51 SENIOR VICE PRESIDENT, 1998
GOVERNMENTAL AFFAIRS
Mr. Nelson joined TEP as a staff attorney in 1976. He was 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.
KAREN G. 47 VICE PRESIDENT, CONTROLLER AND 1998
KISSINGER PRINCIPAL ACCOUNTING OFFICER
Ms. Kissinger joined TEP as Vice President and Controller 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.
KEVIN P. LARSON 45 VICE PRESIDENT, CHIEF FINANCIAL 2000
OFFICER AND TREASURER
Mr. Larson joined TEP in 1985 and thereafter held various 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 COUNSEL 2000
JR. AND CORPORATE SECRETARY
Mr. Nitido joined TEP as a staff attorney in 1991. He 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.
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 S. 58 CHAIRMAN, PRESIDENT AND CHIEF 1994
PIGNATELLI EXECUTIVE OFFICER
See description shown under UniSource Energy Corporation above.
STEVEN J. GLASER 44 SENIOR VICE PRESIDENT AND CHIEF 1994
OPERATING OFFICER, TRANSMISSION &
DISTRIBUTION BUSINESS UNIT
Mr. Glaser joined TEP in 1990 as a Senior Attorney in 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.
THOMAS A. 55 VICE PRESIDENT, ENERGY RESOURCES 1985
DELAWDER BUSINESS UNIT
Mr. Delawder joined TEP in 1974 and thereafter served in 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.
THOMAS N. HANSEN 51 VICE PRESIDENT / TECHNICAL 1992
SERVICES ADVISOR
Mr. Hansen joined TEP in December 1992 as Vice President, 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.
KAREN G. 47 VICE PRESIDENT, CONTROLLER, AND 1991
KISSINGER CHIEF INFORMATION OFFICER
See description shown under UniSource Energy Corporation above.
KEVIN P. LARSON 45 VICE PRESIDENT, CHIEF FINANCIAL 1994
OFFICER AND TREASURER
See description shown under UniSource Energy Corporation above.
VINCENT NITIDO, 46 VICE PRESIDENT AND GENERAL 1998
JR. COUNSEL
See description shown under UniSource Energy Corporation above.
JAMES PYERS 60 VICE PRESIDENT, UTILITY 1998
DISTRIBUTION BUSINESS UNIT,
OPERATIONS
Mr. Pyers joined TEP in 1974 as a Supervisor. Thereafter, he 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.
CATHERINE 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.
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 2002 Annual
Meeting of Shareholders, which will be filed with the SEC not later
than 120 days after December 31, 2001, which information is
incorporated herein by reference.
ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- --------------------------------------------------------------------------------
GENERAL
-------
At February 25, 2002, UniSource Energy had outstanding
33,539,487 shares of Common Stock. As of February 25, 2002, the
number of shares of Common Stock beneficially owned by all
directors and officers of UniSource Energy as a group amounted to
2% of the outstanding Common Stock.
At February 25, 2002, 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 2002 Annual Meeting of
Shareholders, which will be filed with the SEC not later than 120
days after December 31, 2001, 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 2002 Annual Meeting of
Shareholders, which will be filed with the SEC not later than 120
days after December 31, 2001, 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 2002 Annual Meeting of Shareholders,
which will be filed with the SEC not later than 120 days after
December 31, 2001, which information is incorporated herein by
reference.
PART IV
ITEM 14. - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
Page
(a) 1. Consolidated Financial Statements as of ----
December 31, 2001 and 2000 and for Each
of the Three Years in the Period Ended
December 31, 2001.
UniSource Energy Corporation
----------------------------
Report of Independent Accountants 53
Consolidated Statements of Income 54
Consolidated Statements of Cash Flows 55
Consolidated Balance Sheets 56
Consolidated Statements of Capitalization 57
Consolidated Statements of Changes in
Stockholders' Equity 58
Notes to Consolidated Financial Statements 64
Tucson Electric Power Company
-----------------------------
Report of Independent Accountants 53
Consolidated Statements of Income 59
Consolidated Statements of Cash Flows 60
Consolidated Balance Sheets 61
Consolidated Statements of Capitalization 62
Consolidated Statements of Changes in
Stockholders' Equity 63
Notes to Consolidated Financial Statements 64
2. Financial Statement Schedules
Schedule II
Valuation and Qualifying Accounts 101
3. Exhibits.
Reference is made to the Exhibit Index commencing on page 111.
(b) Reports on Form 8-K.
None.
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, 2002 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, 2002 /s/ James S. Pignatelli*
-----------------------------------------
James S. Pignatelli
Chairman of the Board, President
and Principal Executive Officer
Date: March 7, 2002 /s/ Kevin P. Larson
-----------------------------------------
Kevin P. Larson
Principal Financial Officer
Date: March 7, 2002 /s/ Karen G. Kissinger*
-----------------------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 7, 2002 /s/ Lawrence J. Aldrich*
-----------------------------------------
Lawrence J. Aldrich
Director
Date: March 7, 2002 /s/ Larry W. Bickle*
-----------------------------------------
Larry W. Bickle
Director
Date: March 7, 2002 /s/ Elizabeth T. Bilby*
-----------------------------------------
Elizabeth T. Bilby
Director
Date: March 7, 2002 /s/ Harold W. Burlingame*
-----------------------------------------
Harold W. Burlingame
Director
Date: March 7, 2002 /s/ Jose L. Canchola*
-----------------------------------------
Jose L. Canchola
Director
Date: March 7, 2002 /s/ John L. Carter*
-----------------------------------------
John L. Carter
Director
Date: March 7, 2002 /s/ Daniel W. L. Fessler*
-----------------------------------------
Daniel W. L. Fessler
Director
Date: March 7, 2002 /s/ Kenneth Handy*
-----------------------------------------
Kenneth Handy
Director
Date: March 7, 2002 /s/ Warren Y. Jobe*
-----------------------------------------
Warren Y. Jobe
Director
Date: March 7, 2002 /s/ Martha R. Seger*
-----------------------------------------
Martha R. Seger
Director
Date: March 7, 2002 /s/ H. Wilson Sundt*
-----------------------------------------
H. Wilson Sundt
Director
Date: March 7, 2002 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, 2002 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, 2002 /s/ James S. Pignatelli*
-----------------------------------------
James S. Pignatelli
Chairman of the Board, President
and Principal Executive Officer
Date: March 7, 2002 /s/ Kevin P. Larson
-----------------------------------------
Kevin P. Larson
Principal Financial Officer
Date: March 7, 2002 /s/ Karen G. Kissinger*
-----------------------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 7, 2002 /s/ Lawrence J. Aldrich*
-----------------------------------------
Lawrence J. Aldrich
Director
Date: March 7, 2002 /s/ Elizabeth T. Bilby*
-----------------------------------------
Elizabeth T. Bilby
Director
Date: March 7, 2002 /s/ Harold W. Burlingame*
-----------------------------------------
Harold W. Burlingame
Director
Date: March 7, 2002 /s/ John L. Carter*
-----------------------------------------
John L. Carter
Director
Date: March 7, 2002 /s/ Daniel W. L. Fessler*
-----------------------------------------
Daniel W. L. Fessler
Director
Date: March 7, 2002 /s/ Kenneth Handy*
-----------------------------------------
Kenneth Handy
Director
Date: March 7, 2002 /s/ Warren Y. Jobe*
-----------------------------------------
Warren Y. Jobe
Director
Date: March 7, 2002 /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
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--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--
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--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--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--Exhibit 2(b)(1).)
*4(a)(2) -- First Supplemental Indenture, dated as of October
1, 1946. (Form S-7, File No. 2-59906--Exhibit 2(b)(2).)
*4(a)(3) -- Second Supplemental Indenture dated as of October
1, 1947. (Form S-7, File No. 2-59906--Exhibit 2(b)(3).)
*4(a)(4) -- Third Supplemental Indenture, dated as of April 1,
1949. (Form S-7, File No. 2-59906--Exhibit 2(b)(4).)
*4(a)(5) -- Fourth Supplemental Indenture, dated as of December
1, 1952. (Form S-7, File No. 2-59906--Exhibit 2(b)(5).)
*4(a)(6) -- Fifth Supplemental Indenture, dated as of January
1, 1955. (Form S-7, File No. 2-59906--Exhibit 2(b)(6).)
*4(a)(7) -- Sixth Supplemental Indenture, dated as of January
1, 1958. (Form S-7, File No. 2-59906--Exhibit 2(b)(7).)
*4(a)(8) -- Seventh Supplemental Indenture, dated as of
November 1, 1959. (Form S-7, File No. 2-59906--Exhibit
2(b)(8).)
*4(a)(9) -- Eighth Supplemental Indenture, dated as of November
1, 1961. (Form S-7, File No. 2-59906--Exhibit 2(b)(9).)
*4(a)(10) -- Ninth Supplemental Indenture, dated as of February
20, 1964. (Form S-7, File No. 2-59906--Exhibit 2(b)(10).)
*4(a)(11) -- Tenth Supplemental Indenture, dated as of February
1, 1965. (Form S-7, File No. 2-59906--Exhibit 2(b)(11).)
*4(a)(12) -- Eleventh Supplemental Indenture, dated as of
February 1, 1966. (Form S-7, File No. 2-59906--Exhibit
2(b)(12).)
*4(a)(13) -- Twelfth Supplemental Indenture, dated as of
November 1, 1969. (Form S-7, File No. 2-59906--Exhibit
2(b)(13).)
*4(a)(14) -- Thirteenth Supplemental Indenture, dated as of
January 20, 1970. (Form S-7, File No. 2-59906--Exhibit
2(b)(14).)
*4(a)(15) -- Fourteenth Supplemental Indenture, dated as of
September 1, 1971. (Form S-7, File No. 2-59906--Exhibit
2(b)(15).)
*4(a)(16) -- Fifteenth Supplemental Indenture, dated as of March
1, 1972. (Form S-7, File No. 2-59906--Exhibit 2(b)(16).)
*4(a)(17) -- Sixteenth Supplemental Indenture, dated as of May
1, 1973. (Form S-7, File No. 2-59906--Exhibit 2(b)(17).)
*4(a)(18) -- Seventeenth Supplemental Indenture, dated as of
November 1, 1975. (Form S-7, File No. 2-59906--Exhibit
2(b)(18).)
*4(a)(19) -- Eighteenth Supplemental Indenture, dated as of
November 1, 1975. (Form S-7, File No. 2-59906--Exhibit
2(b)(19).)
*4(a)(20) -- Nineteenth Supplemental Indenture, dated as of July
1, 1976. (Form S-7, File No. 2-59906--Exhibit 2(b)(20).)
*4(a)(21) -- Twentieth Supplemental Indenture, dated as of
October 1, 1977. (Form S-7, File No. 2-59906--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--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--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--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--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--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--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--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--Exhibit 4(a)(1).)
*4(a)(30) -- Twenty-ninth Supplemental Indenture, dated as of
December 1, 1992. (Form S-1, Registration No. 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--
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--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--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--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--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--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--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--Exhibit 4(a).)
*4(b)(4) -- City of Farmington, New Mexico Ordinance No. 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--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 quarter ended
September 30, 1982, File No. 1-5924--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 quarter
ended September 30, 1982, File No. 1-5924--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--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, Registration No. 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 year ended December 31,
1982, File No. 1-5924--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 year ended
December 31, 1982, File No. 1-5924--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, Registration No. 33-52860--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--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 year ended
December 31, 1983, File No. 1-5924--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 year
ended December 31, 1983, File No. 1-5924--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--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--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--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--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 year ended December 31, 1983,
File No. 1-5924--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 year ended
December 31, 1983, File No. 1-5924--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--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--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--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--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--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 year ended
December 31, 1983, File No. 1-5924--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--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--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--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--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--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--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--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--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--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--Exhibit
4(r)(1).)
*4(k)(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--Exhibit 4(r)(2).)
*4(k)(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--Exhibit
4(m)(3).)
*4(k)(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--Exhibit 4(c).)
*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 A (Tucson Electric Power Company Navajo Project).
(Form 10-Q for the quarter ended March 31, 1997, File No.
1-5924--Exhibit 4(c).)
*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 A (Tucson Electric Power Company Navajo
Project). (Form 10-Q for the quarter ended March 31,
1997, File No. 1-5924--Exhibit 4(d).)
*4(m)(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--Exhibit 4(e).)
*4(m)(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--Exhibit 4(f).)
*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 A (Tucson Electric Power Company
Project). (Form 10-Q for the quarter ended September 30,
1997, File No. 1-5924--Exhibit 4(a).)
*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 A (Tucson Electric Power Company Project). (Form
10-Q for the quarter ended September 30, 1997, File No. 1-
5924--Exhibit 4(b).)
*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 B (Tucson Electric Power Company
Project). (Form 10-Q for the quarter ended September 30,
1997, File No. 1-5924--Exhibit 4(c).)
*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 B (Tucson Electric Power Company Project). (Form
10-Q for the quarter ended September 30, 1997, File No. 1-
5924--Exhibit 4(d).)
*4(p)(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--Exhibit 4(e).)
*4(p)(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--Exhibit 4(f).)
*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 A (Tucson Electric Power Company
Project). (Form 10-Q for the quarter ended March 31,
1998, File No. 1-5924--Exhibit 4(a).)
*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 A (Tucson Electric Power Company Project).
(Form 10-Q for the quarter ended March 31, 1998, File No.
1-5924--Exhibit 4(b).)
*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 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--Exhibit 4(c).)
*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 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--Exhibit 4(d).)
*4(s)(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)(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--Exhibit 4(f).)
*4(t)(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 4(d).)
*4(u)(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--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--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--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. 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--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. 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 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-
K for the year ended December 31, 1986, File No. 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--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--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--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. Penney
Company, Inc. as Owner Participant. (Form 10-K for the
year ended December 31, 1986, File No. 1-5924--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--
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. Penney Company,
Inc., as Owner Participant. (Form 10-K for the year ended
December 31, 1986, File No. 1-5924--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--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--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. Penney Company, Inc. as
Owner Participant. (Form 10-K for the year ended December
31, 1988, File No. 1-5924--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, respectively (document filed relates to General
Foods Credit Corporation; documents relating to Harvey
Hubbel Financial, Inc. and J.C. Penney Company, Inc. are not
filed but are substantially similar). (Form S-4,
Registration No. 33-52860--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 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. 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--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--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. 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--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--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--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. 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--Exhibit 10(f)(22).)
*10(a)(23) -- Supplemental Tax Indemnity Agreement, dated July 1,
1986, between 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 10(e)(15).)
*10(a)(24) -- Supplemental General Indemnity Agreement, dated as
of July 1, 1986, among Valencia and TEP, as Indemnitors,
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--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.
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--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--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--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
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--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--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--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--Exhibit 10(g)(4).)
*10(b)(5) -- Lease Supplement No. 1, dated December 31, 1985, to
Lease greements, 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--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, Registration No. 33-55732--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--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--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--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--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--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--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--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--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--
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, respectively, together as Lessor. (Form 10-K for
the year ended December 31, 1987, File No. 1-5924--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--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--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--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 10K for the year ended December 31, 1991, File No. 1-
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--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--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). (Form 10-K for the year ended
December 31, 1991, File No. 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--
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--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, respectively, as Lessor. (Form S-1, Registration
No. 33-55732--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--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 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--Exhibit 10(u).)
*10(g) -- 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--Exhibit 10(v).)
*10(h) -- 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--Exhibit 10(w).)
*10(i) -- Restructuring Agreement, dated as of December 1,
1992, between TEP and Century Power Corporation. (Form S-
1, Registration No. 33-55732--Exhibit 10(x).)
*10(j) -- 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--Exhibit
10(y).)
*10(k)(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--Exhibit 10(t).)
*10(k)(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--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) -- 1994 Omnibus Stock and Incentive Plan of UniSource
Energy. (Form S-8 dated January 6, 1998, File No. 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) -- Management and Directors Deferred Compensation Plan
of UniSource Energy. (Form S-8 dated January 6, 1998,
File No. 333-43769.)
+*10(p) -- TEP Supplemental Retirement Account for Classified
Employees. (Form S-8 dated May 21, 1998, File No. 333-
53309.)
+*10(q) -- TEP Triple Investment Plan for Salaried Employees.
(Form S-8 dated May 21, 1998, File No. 333-53333.)
+*10(r) -- UniSource Energy Management and Directors Deferred
Compensation Plan. (Form S-8 dated May 21, 1998, File No.
333-53337.)
12 -- Computation of Ratio of Earnings to Fixed Charges--
TEP.
21 -- Subsidiaries of the Registrants.
23 -- Consents of experts.
24(a) -- Power of Attorney--UniSource Energy.
24(b) -- Power of Attorney--TEP.
(*) 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.