10-K 1 form10-k_2001.txt MAIN DOCUMENT 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 ----------------------------------------------------------------------------- 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 ----------------------------------------------------------------------------- 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.