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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 owns substantially all of the common stock of Tucson Electric Power Company (TEP) and all of the common stock of UniSource Energy Services, Inc. (UES), 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 represented approximately 82% of UniSource Energy’s assets as of December 31, 2005. TEP generates, transmits and distributes electricity. TEP serves approximately 385,000 retail electric 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 U.S.

On August 11, 2003, UniSource Energy completed the purchase of the Arizona gas and electric system assets from Citizens Communications Company (Citizens) and established UES to hold such assets. UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UES has no significant operations of its own. UNS Gas is a gas distribution company serving 139,000 retail customers in Mohave, Yavapai, Coconino, and Navajo Counties in northern Arizona, as well as Santa Cruz County in southeast Arizona. UNS Electric is an electric transmission and distribution company serving approximately 89,000 retail customers in Mohave and Santa Cruz counties. The operating results of UNS Gas, UNS Electric and UES have been included in UniSource Energy’s consolidated financial statements since the acquisition date.

Millennium invests in unregulated businesses, including Global Solar Energy, Inc. (Global Solar), a developer and manufacturer of thin-film photovoltaic cells and modules. UED is facilitating the expansion of the Springerville Generating Station, but currently has no significant operations.

We conduct our business in four primary business segments - TEP’s Electric Utility segment, UNS Gas, UNS Electric and Global Solar.

References to “we” and “our” are to UniSource Energy and its subsidiaries, collectively.

BASIS OF PRESENTATION

We use the following accounting methods to report investments in subsidiaries or other companies:

·	Consolidation: The consolidation method is used where a majority of the voting stock of a subsidiary is held and control over the subsidiary is exercised. The accounts of the subsidiary are combined with the accounts of the parent and intercompany balances and transactions are eliminated.

The Equity Method: The equity method is used to report corporate joint ventures, partnerships, and affiliated company investments when the ability to exercise significant influence over the operating and financial policies of an investee company is demonstrated. Equity method investments appear on a single line item on the balance sheet and net income (loss) from the entity is reflected in Other Income on the income statements.

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Equity investments held by UniSource Energy as of December 31, 2005 include the following:

Investee	% of Common Stock Owned

UniSource Energy
Carboelectrica Sabinas, S. de R.L. de C.V.		50.0	%
Haddington Energy Partners II, LP		31.1	%
MicroSat Systems, Inc.		35.0	%
Valley Ventures III, LP		15.0	%
Infinite Power Solutions, Inc.		31.4	%

TEP
Inncom International, Inc.		16.7	%

The Cost Method: The cost method is used when not enough shares are owned to exercise significant influence over an investee company. Cost method investments appear on a single line item on the balance sheet and income from investee dividend distributions is reflected as Other Income on the income statements. At December 31, 2005, no investments were accounted for using the cost method.

USE OF ACCOUNTING ESTIMATES

Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the United States of America (GAAP). These estimates and assumptions affect:

·	A portion of the reported amounts of assets and liabilities at the dates of the financial statements;

·	Our disclosures regarding contingent assets and liabilities at the dates of the financial statements; and

·	A portion of the reported revenues and expenses during the financial statement reporting periods.

Because these estimates involve judgments, the actual amounts may differ from the estimates.

ACCOUNTING FOR RATE REGULATION

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) regulate portions of TEP’s, UNS Gas’ and UNS Electric’s utility accounting practices and 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 and UNS Electric’s rates for wholesale power sales and transmission services.

TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP. However, sometimes these principles, such as Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), require special accounting treatment for regulated companies to show the effect of regulation. For example, in setting TEP, UNS Gas and UNS Electric’s retail rates, the ACC may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that these expenses be charged to customers in the future. In this situation, FAS 71 requires that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until TEP, UNS Gas and UNS Electric are allowed to charge their customers. TEP, UNS Gas and UNS Electric then amortize these items as expense to the income statement as these 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.

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CASH AND CASH EQUIVALENTS

UniSource Energy and TEP define Cash and Cash Equivalents as cash (unrestricted demand deposits) and all highly liquid investments purchased with an original maturity of three months or less.

UTILITY PLANT

TEP reports its utility plant on its balance sheets at cost. UES reports the utility plant of its two operating companies, UNS Gas and UNS Electric, at cost. Utility plant includes:

·	Material and labor costs,

·	Contractor costs,

·	Construction overhead costs (where applicable), and

·	An Allowance for Funds Used During Construction (AFUDC) or capitalized interest during construction.

AFUDC reflects the cost of financing construction for transmission and distribution projects with borrowed and equity funds.

TEP imputed the cost of capital on transmission and distribution construction expenditures at an average of 8.20% in 2005, 8.67% in 2004 and 8.43% in 2003, to reflect the cost of using borrowed and equity funds to finance construction. The component of AFUDC attributable to borrowed funds is included as a reduction of Other Interest Expense on the income statement and totaled $1 million in 2005, 2004, and 2003. The equity component is included in Other Income and totaled $1 million in 2005, 2004, and 2003.

The interest capitalized during construction of TEP’s generation-related construction projects is included as a reduction of Other Interest Expense on the income statement and totaled $3 million in 2005 and $1 million in 2004, and 2003. The average capitalized interest rate during construction applied to generation-related construction expenditures was 4.78% in 2005, 4.33% in 2004, and 4.14% in 2003.

UES imputed the cost of capital on construction expenditures at an average of 7.83% in 2005 and 7.85% in 2004 for UNS Gas, and, at an average of 9.03% in 2005 and 8.73% in 2004 for UNS Electric. For the period August 11, 2003 through December 31, 2003, UES imputed the cost of capital on construction expenditures at an average of 7.85% for UNS Gas and 8.73% for UNS Electric. The component of AFUDC attributable to borrowed funds is included as a reduction of Other Interest Expense on the income statement and totaled $0.4 million in 2005, $0.5 million in 2004 and $0.2 million in 2003. The equity component is included in Other Income and totaled $0.4 million in 2005, $0.5 million in 2004 and $0.2 million in 2003.

Depreciation

TEP and UES compute depreciation for owned utility plant on a straight-line basis at rates based on the economic lives of the assets. See Note 7. The depreciation rates are approved by the ACC for all plant except TEP’s deregulated generation assets. The depreciable lives for TEP’s generation plant are based on remaining useful lives. Changes made to the depreciable lives of TEP’s generation plant are discussed in Note 7. The depreciation rates for generation plant reflect interim retirements. Interim retirements of generation plant, together with removal costs less salvage, are charged to accumulated depreciation. The costs of planned major maintenance activities are recorded 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 TEP’s generation plants. Minor replacements and repairs are expensed as incurred.

The depreciable lives for transmission, distribution, general and intangible plant are based on average lives. The rates reflect estimated removal costs, net of estimated salvage value for interim retirements. Retirements of transmission plant, distribution plant, general plant and intangible plant, together with the cost of removal less salvage, are charged to accumulated depreciation. Amounts collected through revenues for the net cost of removal of interim retirements for transmission, distribution, general and intangible plant which are not yet expended, are reflected as a regulatory liability.

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The average annual depreciation rates for TEP’s utility plant were 3.4% in 2005, 3.80% in 2004, and 3.78% in 2003. The average annual depreciation rates for UES’ utility plant were 3.15% in 2005 and 2.81% in 2004 for UNS Gas, and, were 4.68% in 2005 and 4.38% in 2004 for UNS Electric. The average annualized depreciation rates for UES’ utility plant for the period of August 11, 2003 through December 31, 2003 were 4.25% for UNS Electric and 2.67% for UNS Gas.

Computer Software Costs

TEP and UES capitalize all costs incurred to purchase computer software and amortize those costs over the estimated economic life of the product. Capitalized computer software costs would be immediately charged to expense if the software is determined to be no longer useful. TEP’s amortization of capitalized computer software costs was $8 million in 2005 and 2004 and was $6 million in 2003.

TEP Utility Plant under Capital Leases

TEP financed the following generation assets with capital leases:

·	Springerville Common Facilities,

·	Springerville Unit 1,

·	Springerville Coal Handling Facilities, and

·	Sundt Unit 4.

The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases. We describe the lease terms in TEP Capital Lease Obligations in Note 9.

	Years Ended December 31,
	2005		2004		2003
	-Millions of Dollars-
Lease Expense:
Interest Expense on Capital Leases	$	79	$	86	$	84
Amortization - Included in:
Operating Expenses - Fuel		5		4		4
Operating Expenses - Depreciation and Amortization		23		18		25
Total Lease Expense	$	107	$	108	$	113

GLOBAL SOLAR PROPERTIES AND EQUIPMENT

Global Solar’s properties and equipment are included, net of accumulated depreciation, in UniSource Energy’s balance sheets in the Investments and Other Property - Other line item. Properties and equipment are stated at original cost and are depreciated using the straight-line method over the estimated useful lives of the assets.

ASSET RETIREMENT OBLIGATIONS

FASB Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (FAS 143) requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), requires entities to record the fair value of a liability regarding a legal obligation to perform asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. We record a liability when we are able to reasonably estimate the fair value of any future obligation to retire as a result of an existing or enacted law, statute, ordinance or contract. We also record a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. When the liability is initially recorded, we capitalize a cost by increasing the carrying amount of the related long-lived asset. Over time, we adjust the liability to its present value by recognizing accretion expense as an operating expense in the income statement each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss if the actual costs differ from the recorded amount.

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Prior to adopting FAS 143, costs for final removal of all owned generation facilities were accrued as an additional component of depreciation expense. Under FAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost.

EVALUATION OF ASSETS FOR IMPAIRMENT

TEP, UNS Gas, UNS Electric and Millennium evaluate their Utility Plant and other long-lived assets for impairment whenever events or circumstances occur that may indicate the carrying value of the assets may be impaired. If the fair value of the asset determined based on the undiscounted expected future cash flows from the long-lived asset is less than the carrying value of the asset, an impairment would be recorded.

Millennium evaluates its investments for impairment at the end of each quarter. If the investment is considered impaired and that impairment is not considered to be temporary, an impairment loss would be recorded.

INVESTMENTS IN LEASE DEBT

TEP records investments in Springerville lease debt at amortized cost as held-to-maturity investments. Held-to-maturity investments are those investments that TEP has the ability and intent to hold until maturity.

TEP recognizes interest income on these investments. TEP's investments in lease debt are recorded in Investments in Lease Debt on the balance sheet and are reflected in investing activities on TEP's cash flow statements.

DEBT

We defer costs related to the issuance of 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 using the straight-line method, which approximates the effective interest method.

TEP recognizes gains and losses on reacquired debt associated with the generation portion of its operations as incurred. TEP defers and amortizes the gains and losses on reacquired debt associated with its regulated operations to interest income or interest expense over the remaining life of the original debt.

UTILITY OPERATING REVENUES

TEP and UES record utility operating revenues when services are provided or commodities are delivered to customers. Operating revenues include unbilled revenues which are earned (service has been provided) but not billed by the end of an accounting period.

Unbilled sales are estimated for the month by reviewing the meter reading schedules and determining the number of billed and unbilled kWhs or therms, as applicable, for each cycle. Current month estimated unbilled kWhs or therms are allocated by customer class. New unbilled revenue estimates are recorded and unbilled revenue estimates from the prior month are reversed.

An Allowance for Doubtful Accounts is recorded as an expense and reduces accounts receivable for revenue amounts that are estimated to become uncollectible. TEP and UES establish an allowance for doubtful accounts receivable based on historical experience and any specific customer collection issues identified. TEP’s Allowance for Doubtful Accounts was $15 million at December 31, 2005 and $14 million at December 31, 2004. See Note 12 for further discussion of TEP’s wholesale accounts receivable and allowances. UES’ Allowance for Doubtful Accounts was less than $1 million at December 31, 2005 and $2 million at December 31, 2004.

REVENUE FROM LONG-TERM RESEARCH AND DEVELOPMENT CONTRACTS

UniSource Energy's income statement includes Global Solar's long-term contract revenue in Other Operating Revenues. Global Solar recognized long-term contract revenue of less than $1 million in 2005 and 2004 and just over $1 million 2003. Global Solar and IPS recognized total research and development expense of $3 million in

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2005, $5 million in 2004 and $7 million in 2003. 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.

FUEL AND PURCHASED ENERGY COSTS

TEP

Fuel inventory, primarily coal, is recorded at weighted average cost. TEP uses full absorption costing. Under full absorption costing, all handling and procurement costs are included in the cost of the inventory. Examples of these costs are direct material, direct labor and overhead costs. TEP has long-term contracts for the purchase and transportation of coal with expiration dates from 2006 through 2020. The contracts require TEP to pay a take-or-pay fee if certain minimum quantities of coal are not purchased or transported. TEP expenses such fees as they are incurred. TEP recorded take-or-pay fees of less than $0.1 million in 2005 and 2004 and less than $1 million of take-or-pay fees in 2003. See Purchase and Transportation Commitments in Note 6, below. Fuel costs include coal mine reclamation expenses as they are charged to TEP on an ongoing basis.

UES

UNS Gas defers differences between actual gas purchase costs and the recovery of such costs in revenues under a Purchased Gas Adjustor (PGA) mechanism. The PGA mechanism is intended to address the volatility of natural gas prices and allows UNS Gas to recover its commodity costs through a price adjustor. The PGA charge may be changed monthly based on an ACC approved mechanism that compares the twelve-month rolling average gas cost to the base cost of gas, subject to limitations on how much the price per therm may change in a twelve month period. The difference between the actual cost of UNS Gas’ gas supplies and transportation contracts and that currently allowed by the ACC is deferred and recovered or repaid through the PGA mechanism. When under or over recovery trigger points are met, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a twelve month period. UNS Gas had an asset for under recovered purchased gas costs of $6 million at December 31, 2005 and $2 million at December 31, 2004 that is included in Regulatory and Other Assets - Other Regulatory Assets on UniSource Energy’s consolidated balance sheet. See Note 2 for further discussion about recent regulatory actions related to the PGA mechanism and requested recovery of the balance.

UNS Electric defers differences between purchased energy costs and the recovery of such costs in revenues. Future billings are adjusted for such deferrals through use of a Purchased Power and Fuel Adjustment Clause (PPFAC) approved by the ACC. The PPFAC allows for a revenue surcharge or credit (that adjusts the customer’s base rate for delivered purchased power) to collect or return under or over recovery of costs. UNS Electric had a liability for over recovered purchased power costs of $4 million at December 31, 2005 and $3 million at December 31, 2004 that is included in Deferred Credits and Other Liabilities - Other on UniSource Energy’s consolidated balance sheet. See Note 2.

INCOME TAXES

We are required by GAAP to report some of our assets and liabilities differently for our financial statements than we do for income tax purposes. The tax effects of differences in these items are reported as deferred income tax assets or liabilities in our balance sheets. We measure these tax assets and liabilities using income tax rates that are currently in effect. Federal Investment Tax Credits (ITC) as well as applicable state income tax credits are accounted for as a reduction of income tax expense in the year in which the credit arises.

We allocate income taxes to the subsidiaries based on their taxable income and deductions as reported in the consolidated and/or combined tax return filings.

EMISSIONS ALLOWANCES

Emissions Allowances are issued to qualifying utilities by the Environmental Protection Agency (EPA) based on past operational history. Each allowance permits emission of one ton of sulfur dioxide (SO₂) in its vintage year or a subsequent year. TEP receives an allotment of these allowances annually, but UNS Electric does not receive any since it has no coal-fired generation. When issued from the EPA, these allowances have no book value for

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accounting purposes but may be sold if TEP does not need them for operations. TEP also may purchase additional allowances if needed. See Note 6. In 2005, TEP sold 15,000 allowances that were in excess of those required for compliance to third parties at their fair market value of $13 million. In 2004, TEP sold 4,000 allowances at their fair market value of $3 million. TEP did not sell any excess allowances in 2003. The gains from these sales of excess allowances are reflected as a reduction of Other Operations and Maintenance expense on TEP’s income statement and are not recognized until title passes.

TEP has also committed to sell Emission Allowances with vintage years beyond 2005. At December 31, 2005, TEP had entered into agreements to sell a total of 20,000 allowances; 10,000 with a vintage year of 2006 and 10,000 with a vintage year of 2007.

DERIVATIVE FINANCIAL INSTRUMENTS

TEP uses derivative financial instruments including forward power sales and purchases and gas swaps to manage exposure to energy price risk. MEG enters into swap agreements, options and forward contracts relating to Emissions Allowances. TEP and MEG account for derivatives in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. TEP and MEG record derivative instruments at fair value recognizing unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month. Certain of TEP’s derivatives meet the criteria for cash flow hedge accounting. Refer to Note 5 for additional information.

TEP and MEG’s trading activities and TEP’s cash flow hedges are reported as follows:

	Financial Statement Line
	Net Unrealized Gains and Losses	Net Realized Gains and Losses
TEP Forward Power Sales - Cash Flow Hedges	Other Comprehensive Income	Electric Wholesale Sales
TEP Forward Power Purchases - Cash Flow Hedges	Other Comprehensive Income	Purchased Power
TEP Forward Power Sales	Electric Wholesale Sales	Electric Wholesale Sales
TEP Forward Power Purchases	Purchased Power	Purchased Power
TEP Gas Price Swaps - Cash Flow Hedges	Other Comprehensive Income	Fuel Expense
MEG Trading Activities	Other Operating Revenues	Other Operating Revenues

Although MEG’s realized gains and losses on trading activities are reported net on UniSource Energy’s income statement, the related cash receipts and cash payments are reported separately on UniSource Energy’s statement of cash flows.

TEP and MEG’s derivative assets and liabilities are reported as follows:

	Balance Sheet Line
	Assets	Liabilities
TEP - Current	Trading Assets	Trading Liabilities
TEP - Noncurrent	Other Assets	Other Liabilities
MEG - Current (including Emissions Allowance Inventory)	Trading Assets	Trading Liabilities
MEG - Noncurrent	Other Assets	Other Liabilities

SHARE-BASED COMPENSATION

UniSource Energy has two share-based compensation plans, the 1994 Outside Director Stock Option Plan (Directors’ Plan) and the 1994 Omnibus Stock and Incentive Plan (Omnibus Plan). During 2005, stock options were granted outside of these plans. See Note 16. We adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment (FAS 123(R)) effective January 1, 2005 and are applying its standards to new awards without restatement of prior periods. The adoption of FAS 123(R) did not have a significant impact on our financial statements because stock options issued under UniSource Energy’s Omnibus Plan vested upon the

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shareholder vote to approve the proposed acquisition of UniSource Energy. After February 4, 2004, no new awards were granted under the Omnibus Plan. Prior to January 1, 2005, we accounted for those plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (APB 25), and related interpretations and applied the disclosure only guidance in Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation.

All our stock options were granted with an exercise price equal to the market value of the stock at the date of the grant. Accordingly, prior to January 1, 2005, under the provisions of APB 25, no compensation expense was recorded for these awards. However, compensation expense was recognized for restricted stock, stock unit and performance share awards over the performance/vesting period. Beginning January 1, 2005, under the provisions of FAS 123(R), we began recognizing compensation expense over the vesting period for the fair value of new stock options granted. Compensation expense of less than $0.1 million was recognized for the options issued in 2005.

The following table illustrates the effect on UniSource Energy’s Net Income and earnings per share and TEP’s Net Income as if we had applied the fair value recognition provisions of FAS 123(R) to all share-based employee compensation awards during 2004 and 2003:

UniSource Energy:

		Years Ended December 31,
		2004			2003
		-Thousands of Dollars-
		(except per share data)
Net Income - As Reported	$	45,919		$	113,941
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		1,535			850
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,314	)		(1,840	)
Pro Forma Net Income	$	45,140		$	112,951

Earnings per Share:
Basic - As Reported	$	1.34		$	3.37
Basic - Pro Forma	$	1.31		$	3.34

Diluted - As Reported	$	1.31		$	3.32
Diluted - Pro Forma	$	1.29		$	3.29

TEP:

			Years Ended December 31,
			2004			2003
			-Thousands of Dollars-

Net Income - As Reported	$	46,127		$	128,913
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		1,355			787
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,116	)		(1,761	)
Pro Forma Net Income	$	45,366		$	127,939

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no stock options granted during 2004. For the options granted during 2003, refer to the following table for the weighted average assumptions that were used. Volatility is based on historical volatility of UniSource Energy stock. The expected life of options granted is computed using factors such as minimum vesting

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periods and average years to retirement of grantees, and represents the period of time that options granted are expected to be outstanding. The interest rate is based on the U.S. Treasury Strip rate with a maturity equal to the expected term of the option at the option grant date. The dividend yield is calculated based on the ratios of historic dividend payments to the stock prices on the date of those payments.

		2003
Expected life (years)		5
Interest rate		2.78	%
Volatility		23.38	%
Dividend yield		3.44	%
Weighted-average grant-date fair value of optionsgranted during the period	$	2.92

NEW ACCOUNTING STANDARDS

The FASB recently issued the following Statements of Financial Accounting Standards (FAS), FASB Interpretations (FIN), and FASB Staff Positions (FSP):

FAS 154, Accounting Changes and Error Corrections, issued May 2005, provides guidance on the accounting for and reporting of accounting changes and error corrections. FAS 154 requires retrospective application to prior periods for a voluntary change in accounting principle, unless it is impracticable to do so. FAS 154 also provides guidance related to the reporting of a change in accounting estimate, a change in reporting entity and the correction of an error. FAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, and is not expected to have a significant impact on our financial statements.

FAS 153, Exchanges of Nonmonetary Assets, issued December 2004, requires nonmonetary exchanges be accounted for at fair value, recognizing any gains or losses, if their fair value is determinable within reasonable limits and the transaction has commercial substance. A nonmonetary exchange has commercial substance if future cash flows of the entity are expected to change significantly as a result of the exchange. FAS 153 was effective for nonmonetary asset exchange transactions occurring after July 1, 2005, and did not have a significant impact on our financial statements.

FAS 151, Inventory Costs, issued November 2004, is an amendment of Accounting Research Bulletin (ARB) No. 43, Chapter 4, Inventory Pricing. FAS 151 clarifies that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials (spoilage) should be recognized as current-period charges. FAS 151 also requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. FAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, and is not expected to have a significant impact on our financial statements.

FSP FAS 115-1 and FAS 124-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments, issued November 2005, addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. FSP FAS 115-1 and FAS 124-1 are effective for reporting periods beginning after December 15, 2005. The adoption of FSP FAS 115-1 and FAS 124-1 is not expected to have a significant impact on our financial statements.

FSP FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards” provides a transition election related to accounting for the tax effects of share-based payment awards to employees. The adoption of FSP FAS 123(R)-3 in January 2006, is not expected to have a significant impact on our financial statements.

FSP FIN 46(R)-5, Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, issued March 2005, addresses whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (VIE) or potential VIE when specific conditions exist. The guidance in FSP FIN 46(R)-5 was effective April 1, 2005, and did not have a significant impact on our financial statements.

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FSP FAS 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, issued in December 2004, provides guidance on the application of FAS 109 to the provision within the American Jobs Creation Act of 2004 that provides a tax deduction, beginning in 2005, on qualified production activities, including a company’s electric generation activities. Under FSP FAS 109-1, recognition of the tax deduction on qualified production activities is ordinarily reported in the year it is earned. FSP FAS 109-1 did not have a significant impact on our financial statements.

In 2005, UniSource Energy applied early EITF Issue No. 04-10, Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds. EITF Issue No. 04-10 addresses the aggregation of segments that do not meet the quantitative thresholds under FAS Statement No. 131, Disclosures about Segments of an Enterprise and Related Information. Application of EITF Issue No. 04-10 did not have a significant impact on our financial statements.

RECLASSIFICATIONS

UniSource Energy and TEP have made reclassifications to the prior year financial statements and footnotes for comparative purposes. These reclassifications had no effect on Net Income.

NOTE 2. REGULATORY MATTERS

TEP RATES AND REGULATION

Upon approval of the TEP Settlement Agreement in 1999, TEP discontinued regulatory accounting under FAS 71 for its generation operations. TEP continues to report its transmission and distribution operations under FAS 71.

TEP Settlement Agreement

In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.

The Rules and the Settlement Agreement established:

·	a period from November 1999 through 2008, for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure;

·	the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (fixed CTC);

·	capped rates for TEP retail customers through 2008;

·	an ACC interim review of TEP retail rates in 2004;

·	unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services;

·	a process for alternative energy service providers (ESPs) to become licensed by the ACC to sell generation services at market prices to TEP retail customers;

·	access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs);

·	transmission and distribution services would remain subject to regulation on a cost of service basis; and

·	beginning in 2009, TEP’s generation would be market based and its retail customers would pay the market rate for generation services.

Recent Court Action

In January 2005, an Arizona Court of Appeals decision became final in which the Court held invalid certain portions of the ACC rules on retail competition and related market pricing. In February 2006, the ACC Staff requested that a proceeding be opened to address the issue of retail electric competition. We cannot predict what

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changes, if any, the ACC will make to the competition rules. Unless and until the ACC clarifies the competition rules and ESPs begin to offer to provide energy in TEP’s service area, it may not be possible for TEP’s retail customers to choose other energy providers. TEP has met all conditions required by the ACC to facilitate electric retail competition, including ACC approval of TEP’s direct access tariffs.

2004 General Rate Case Information

In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC. TEP’s filing does not propose any change in retail rates, and under the terms of the Settlement Agreement, no rate case filed by TEP through 2008 may result in a net rate increase. However, absent the restriction on raising rates, TEP believes that the data in its filing would justify an increase in retail rates of 16%.

The general rate case information uses a historical test year ended December 31, 2003 and establishes, based on TEP’s standard offer service, that TEP is experiencing a revenue deficiency of $111 million. The rate case information includes, among other things, Springerville Unit 1 costs and other generation costs including fuel costs in excess of those recovered through existing rates. The proposed weighted cost of capital for the test year ended December 31, 2003 is 8.78%, including an 11.5% return on equity (increased from 10.67% currently authorized). The rate case information uses a hypothetical 40% equity capitalization (excluding capital lease obligations) rather than the hypothetical 37.5% equity capitalization used in TEP’s last general rate case. As a result of the inter-company note repayment and the debt repurchases and redemptions made earlier this year, TEP’s equity capitalization (excluding capital lease obligations) at December 31, 2005 improved to 40.5%.

In June 2005, intervenor testimony in TEP’s 2004 rate review was due and several intervenors filed their respective testimony. None of the intervenor testimony filed proposed any increase or decrease to TEP’s rates. In July 2005, an ACC administrative law judge (ALJ) issued a procedural order suspending the remaining testimony filing deadlines and hearing in the 2004 rate review. The order indicated that the ALJ will evaluate the parties’ positions and the need for further proceedings.

Despite TEP’s position that it has a revenue deficiency and the intervenor testimony recommending no change in rates, the ACC could conclude during this 2004 rate review process that TEP should decrease rates; any such determination would be strongly opposed by TEP.

Declaratory Motion Filed with ACC

Given the recent court action described above - Factors Affecting Results of Operations, Competition - the ACC may revise its Rules and rate methodologies prior to January 2009. In an effort to resolve the uncertainty surrounding the methodology that will be applied to determine TEP's rates for generation service after December 31, 2008, TEP filed a motion with the ACC in May 2005 requesting that the ACC issue an order declaring its position regarding the rate treatment that will be afforded to TEP's generation assets after 2008.

TEP believes that any actions by the ACC should not deny TEP the economic benefits of the Settlement Agreement, and accordingly analyzed how the Settlement Agreement can be modified so as to: (i) preserve the intent of the parties; (ii) avoid a significant increase in rates in 2009; (iii) mitigate a negative financial impact on TEP; and (iv) provide all interested parties with certainty in the near future about TEP’s post-2008 rate structure.

Procedural orders issued by the ALJ did not rule on TEP’s May 2005 motion, but suggested that TEP file a motion to reopen the record approving the Settlement Agreement.

Motion to Amend the Settlement Agreement

In September 2005, TEP filed a motion and supporting testimony with the ACC to amend the Settlement Agreement. In the motion, TEP proposed the following amendments to extend the benefits and protections set forth in the Settlement Agreement and provide additional price stability for TEP customers:

(1)	The extension of the existing rate freeze at TEP’s current average retail base rate of 8.3 cents per kWh through December 31, 2010;

(2)	The retention of the current CTC amortization schedule;

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(3)	The agreement of TEP not to seek base rate treatment for certain generating assets in order to minimize the rates TEP’s customers will eventually pay once the rate freeze has expired; and

(4)

The implementation of an energy cost adjustment mechanism to protect TEP and its customers from energy market volatility, to be effective after December 31, 2008. TEP proposes the establishment of an incremental Energy Cost Adjustment Clause (ECAC). A base amount of retail energy consumption would be served at the existing fixed retail rates and the rate on the incremental amount of retail energy would be capped at an annual proxy set at forward power prices.

In October 2005, a number of participants in TEP’s rate proceedings, including the Staff of the ACC, filed responses to TEP’s motion. Those responses reflect differing interpretations of the Settlement Agreement which established TEP’s existing rate structure and generation service rates. Responses filed by ACC Staff and the Residential Utility Consumer Office disputed TEP’s assertion that the existing rate structure contemplates market-based rates for generation services after December 31, 2008.

TEP filed a reply in support of its motion. The reply stated that the public interest is best served by the ACC taking affirmative action to resolve the questions of how TEP’s rates will be determined after December 31, 2008, avoid significant rate increases for TEP customers, bolster wholesale electric generation and reduce customer risk and exposure to volatile energy costs.

In 2005, the ALJ held a procedural conference. The Chairman of the ACC submitted a letter in support of resolving the issues arising from the Settlement Agreement and the related effect on TEP’s rates. A number of the participants disagreed with aspects of TEP’s request. The ALJ took the motion under advisement.

On January 30, 2006, the ALJ issued a recommended opinion and order, which, if adopted by the ACC, would deny TEP’s motion to amend the Settlement Agreement. The recommended opinion and order acknowledged that there is a fundamental disagreement among the parties to the Settlement Agreement about what is to happen to the rates TEP charges for generation service after December 31, 2008, however concluded it is premature and not in the public interest to reopen the Settlement Agreement because the information necessary to evaluate the request does not yet exist. The recommended opinion and order also orders TEP to file a rate case no later than September 30, 2007, using a test year no earlier than December 31, 2006.

On February 8, 2006, TEP filed exceptions to the ALJ’s recommended opinion and order. In its filing, TEP stated it takes exception to the recommendation because it:

·	fails to resolve the uncertainty over how the ACC interprets the Settlement Agreement’s treatment of TEP’s generation rates beginning in 2009;

·	violates TEP’s right to due process by failing to take evidence on the need to immediately resolve the uncertain situation;

·	erroneously finds that TEP does not seek to charge market-based rates for generation in 2009; and

·	mistakenly directs TEP to file a rate case in 2007 as the procedure for resolving the uncertainty over 2009 generation rates, despite the fact that there is not certainty that the dispute can or will be resolved before 2009.

The ACC is expected to consider the ALJ’s recommended opinion and order in early 2006.

Transition Recovery Asset

TEP’s Transition Recovery Asset consists of generation-related regulatory assets and a portion of TEP’s generation plant asset costs. Transition costs being recovered through the Fixed CTC include: (1) the Transition Recovery Asset; (2) generation-related plant assets included in Plant in Service on the balance sheet; and (3) excess capacity deferrals related to operating and capital costs associated with Springerville Unit 2 which were amortized as an off-balance sheet regulatory asset through 2003. These transition costs were amortized as follows:

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	Years Ended December 31,
		2005			2004			2003
	-Millions of Dollars-
Amortization of Transition Costs Being Recovered through the Fixed CTC:
Transition Costs Being Recovered through the Fixed CTC, beginning of year	$	247		$	302		$	348
Amortization of Transition Recovery Asset Recorded on the Income Statement		(56	)		(50	)		(32	)
Amortization of Generation-Related Plant Assets		(6	)		(5	)		(5	)
Amortization of Excess Capacity Deferrals (off-balance sheet)		-			-			(9	)
Transition Costs Being Recovered through the Fixed CTC, end of year	$	185		$	247		$	302

The portion of the Transition Recovery Asset that is recorded on the balance sheet was amortized as follows:

	Years Ended December 31,
		2005			2004			2003
	-Millions of Dollars-
Amortization of Transition Recovery Asset Recorded on the Balance Sheet:
Transition Recovery Asset, beginning of year	$	224		$	274		$	306
Amortization of Transition Recovery Asset Recorded on the Income Statement		(56	)		(50	)		(32	)
Transition Recovery Asset, end of year	$	168		$	224		$	274

The remaining transition costs being recovered through the Fixed CTC differ from the Transition Recovery Asset recorded on the balance sheet as follows:

	December 31,
		2005			2004
	-Millions of Dollars-
Transition Costs Being Recovered through the Fixed CTC, end of year	$	185		$	247
Unamortized Generation-Related Plant Assets		(17	)		(23	)
Transition Recovery Asset, end of year	$	168		$	224

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 occurs first.

OTHER REGULATORY ASSETS AND LIABILITIES

In addition to the Transition Recovery Asset related to TEP’s generation assets, the following regulatory assets and liabilities are being recovered through TEP’s transmission and distribution businesses:

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	December 31,
		2005		2004
	-Millions of Dollars-
Other Regulatory Assets
Income Taxes Recoverable through Future Revenues	$	40	$	45
Current Regulatory Assets		10		10
Other Regulatory Assets		21		14
Total Regulatory Assets	$	71	$	69
Other Regulatory Liabilities
Net Cost of Removal for Interim Retirements	$	75	$	67

Regulatory assets of approximately $31 million are not presently included in rate base and consequently are not earning a return on investment. These regulatory assets are being recovered through cost of service or are authorized to be collected in future base rates. Current regulatory assets of $10 million are related to differences between expenses recorded on the accrual basis for GAAP accounting and on a pay-as-you-go basis for regulatory accounting. The remaining recovery period generally ranges from 1 to 1.5 years. Regulatory compliance costs of $13 million require specific rate action and the recovery period will be determined in the next rate case with the ACC. The remaining $8 million represents unamortized loss on reacquired debt that is not included in rate base, but the amortization of these costs is included in the ratemaking calculation of the cost of debt, which is a component of the cost of capital (rate of return). The unamortized loss on reacquired debt is amortized over the life of the underlying debt issue. All regulatory assets are probable of recovery.

See Note 3 for a discussion of the amounts included in Other Regulatory Liabilities.

INCOME STATEMENT IMPACT OF APPLYING FAS 71

The amortization of TEP’s regulatory assets had the following effect on UniSource Energy’s and TEP’s income statements:

	Years Ended December 31,
		2005		2004		2003
	-Millions of Dollars-
Operating Expenses
Amortization of Transition Recovery Asset	$	56	$	50	$	32
Interest Expense
Long-Term Debt		2		-		-
Income Taxes		5		5		7
Total	$	63	$	55	$	39

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 reclassification of TEP’s generation-related regulatory assets to the Transition Recovery Asset shortened the amortization period for these assets to nine years.

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF FAS 71

TEP continues to apply FAS 71 to its regulated operations, which include the transmission and distribution portions of its business. TEP regularly assesses whether it can continue to apply FAS 71 to these operations. If TEP stopped applying FAS 71 to its remaining regulated operations, it would write off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement. Based on the regulatory asset balances, net of regulatory liabilities, at December 31, 2005, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $98

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million. While regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if it stopped applying FAS 71 unless a regulatory order limited its ability to recover the cost of its regulatory assets.

UNS GAS RATES AND REGULATION

Rates and Regulation

UNS Gas is regulated by the ACC with respect to retail gas rates, the issuance of securities, and transactions with affiliated parties. UNS Gas’ retail gas rates include a monthly customer charge, a base rate charge for delivery services and the cost of gas (expressed in cents per therm), and a PGA mechanism.

Concurrent with the closing of the acquisition, a retail rate increases for customers of UNS Gas went into effect in August 2003. The rate increase was approved by the ACC in July 2003, when it approved the acquisition and the terms of the April 2003 settlement agreement (UES Settlement Agreement) among UniSource Energy, Citizens, and the ACC Staff.

The related ACC order and the UES Settlement Agreement include the following terms related to UNS Gas rates:

·	An increase in retail delivery base rates, effective August 11, 2003, equivalent to a 20.9% overall increase over 2001 test year retail revenues through a base rate increase.

·	Fair value rate base of $142 million and allowed rate of return of 7.49%, based on a cost of capital of 9.05%, derived from a cost of equity of 11.00% and a cost of debt of 7.75% (based on a capital structure of 60% debt and 40% equity).

·	The existing PGA rate may not change more than $0.15 per therm through July 2004. Thereafter, the PGA rate may not change more than $0.10 per therm.

Under the terms of the ACC order, UNS Gas may not file a general rate increase until July 2006 and any resulting rate increase shall not become effective prior to August 1, 2007.

The UES Settlement Agreement also limits dividends payable by UNS Gas to UniSource Energy to 75% of earnings until the ratio of common equity to total capitalization reaches 40%. The ratio of common equity to total capitalization for UNS Gas is 44% at December 31, 2005.

Recent Regulatory Action

The following table shows the balance of purchased gas costs:

	December 31
		2005			2004
	-Millions of Dollars-
Under Recovered Purchased Gas Costs - Regulatory Basis as Billed	$	16		$	9
Under Recovered Purchased Gas Costs - Unbilled Revenue		(10	)		(7	)
Under Recovered Purchased Gas Costs (PGA) Included on the Balance Sheet	$	6		$	2

In August 2005, UNS Gas filed a request with the ACC to approve an increase in the PGA surcharge from $0.03 per therm to $0.27 per therm to be effective October 1, 2005. An increase was necessary to allow for the recovery of the existing PGA bank balance and recover projected costs of gas during the winter season.

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On October 19, 2005, the ACC approved the following PGA surcharges:

Surcharge Amount Per Therm		Period In Effect
$0.15		November 2005 - February 2006
$0.25		March 2006 - April 2006
$0.30		May 2006 - June 2006
$0.35		July 2006 - September 2006
$0.25		October 2006 - November 2006
$0.20		December 2006 - February 2007
$0.25		March 2007 - April 2007

Currently, this PGA surcharge is predicted to stem the growth of the PGA bank balance. However, if gas prices increase, the PGA bank balance may continue to grow despite this surcharge. Sources to fund the growing balance could include an additional surcharge, draws on the revolving credit facility, additional credit lines or the investment of additional capital by UniSource Energy. Based on market prices for gas at February 3, 2006, which range from $7 to $9 per MMBtu through the end of 2006, the PGA bank balance is expected to be $11 million by March 31, 2006 and $5 million by December 31, 2006. Changes in the market price for gas could significantly change the PGA bank balance in the future. The PGA bank balance was $16 million at December 31, 2005.

Regulatory Assets and Liabilities

In addition to the Under Recovered Purchase Gas Costs balance, UNS Gas has recorded regulatory liabilities for the Net Cost of Removal for Interim Retirements from its distribution and general plant of $3 million as of December 31, 2005 and $2 million as of December 31, 2004.

Income Statement Impact of Applying FAS 71

If UNS Gas had not applied FAS 71, net income would have been $2 million less in 2005 and $1 million higher in 2004, primarily as a result of gas costs being expensed rather than deferred as a regulatory asset.

Future Implications of Discontinuing Application of FAS 71

UNS Gas’s regulatory liabilities exceeded its regulatory assets by $3 million at December 31, 2005. At December 31, 2004, UNS Gas’s regulatory liabilities exceeded its regulatory assets by $1 million. UNS Gas regularly assesses whether it can continue to apply FAS 71 to its operations. If UNS Gas stopped applying FAS 71 to its regulated operations, UNS Gas would write off the related balance of its regulatory assets as an expense and would write off its regulatory liabilities as income on its income statement. Based on the regulatory asset and liability balances, if UNS Gas had stopped applying FAS 71 to its regulated operations, UNS Gas would have recorded an extraordinary after-tax loss of $2 million at December 31, 2005. UNS Gas’s cash flows would not be affected if it stopped applying FAS 71 unless a regulatory order limited its ability to recover the cost of its regulatory assets.

UNS ELECTRIC RATES AND REGULATION

Rates and Regulation

UNS Electric is regulated by the ACC with respect to retail electric rates, the issuance of securities, and transactions with affiliated parties, and by the FERC with respect to wholesale power contracts and interstate transmission service.

Concurrent with the closing of the acquisition, a retail rate increase for customers of UNS Electric went into effect on August 11, 2003. The rate increase was approved by the ACC on July 3, 2003, when it approved the acquisition and the terms of the April 1, 2003 settlement agreement (UES Settlement Agreement) among UniSource Energy, Citizens, and the ACC Staff.

The ACC order and UES Settlement Agreement include the following terms related to UNS Electric rates:

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A 22% overall increase in retail rates effective August 11, 2003 from the rates previously in effect for Citizens. This reflects the implementation of a PPFAC of $0.01825 per kWh, which combined with the current base purchased power rate of $0.05194 per kWh, results in a new PPFAC rate of $0.07019. This allows UNS Electric to fully recover the cost of purchased power under its current contract with its sole energy supplier, Pinnacle West Capital Corporation (PWCC).

·	UNS Electric must attempt to renegotiate the PWCC purchase power contract, and any savings that result from a renegotiated contract must be allocated in a ratio of 90% to ratepayers and 10% to shareholders.

Under the terms of the ACC order, UNS Electric may not file a general rate increase until July 2006 and any resulting rate increase shall not become effective prior to August 1, 2007.

The UES Settlement Agreement also limits dividends payable by UNS Electric to UniSource Energy to 75% of earnings until the ratio of common equity to total capitalization reaches 40%. The ratio of common equity to total capitalization for UNS Electric was 45% at December 31, 2005.

Regulatory Assets and Liabilities

UNS Electric’s regulatory liabilities were as follows:

	December 31,
		2005		2004
	-Millions of Dollars-
Current Regulatory Liabilities
Deferred Environmental Portfolio Surcharge	$	2	$	1
Other Regulatory Liabilities
Over Recovered Purchase Power Costs		4		3
Net Cost of Removal for Interim Retirements		1		1
Total Regulatory Liabilities	$	7	$	5

As of December 31, 2005, UNS Electric has $6 million of regulatory liabilities that are not included in rate base.

Income Statement Impact of Applying FAS 71

If UNS Electric had not applied FAS 71, net income would have been $1 million higher in 2005 and $2 million higher in 2004, primarily as a result of power costs being expensed rather than deferred as a regulatory liability.

Future Implications of Discontinuing Application of FAS 71

UNS Electric regularly assesses whether it can continue to apply FAS 71 to its operations. If UNS Electric stopped applying FAS 71 to its regulated operations, it would write off the related balances of their regulatory assets as an expense and would write off its regulatory liabilities as income on their income statement. Based on the regulatory asset and liability balances, if UNS Electric had stopped applying FAS 71 to its regulated operations, it would have recorded an extraordinary after-tax gain of $4 million at December 31, 2005. UNS Electric’s cash flows would not be affected if it stopped applying FAS 71 unless a regulatory order limited its ability to recover the cost of its regulatory assets.

NOTE 3. ACCOUNTING CHANGE: ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

As of December 31, 2005, TEP implemented FIN 47. The implementation of FIN 47 required TEP to update an existing inventory, originally created for the implementation of FAS 143, and to determine which, if any, of the conditional asset retirement obligations could be reasonably estimated. The significant conditional asset retirement obligations identified include the removal and disposal of asbestos at the Sundt Generating Station and

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remediation of the evaporative ponds upon decommissioning of our generating stations and the disposal of equipment contaminated with polychlorinated biphenlys (PCBs) in our distribution system.

The ability to reasonably estimate conditional asset retirement obligations was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of TEP’s conditional asset retirement obligations. In determining whether its conditional asset retirement obligations could be reasonably estimated, management considered TEP’s past practices, industry practices, management’s intent and the estimated economic life of the assets. The fair value of the conditional asset retirement obligations were then estimated using an expected present value technique.

TEP measured the conditional asset retirement obligations at fair value using the methodology prescribed by FIN 47. The transition provisions of FIN 47 required TEP to apply this measurement back to the historical periods in which the conditional asset retirement obligations were incurred, resulting in a re-measurement of these obligations at the latter of the date that the related assets were placed into service or the date that the applicable law or environmental regulation became effective. The fair values of the conditional asset retirement obligations were then estimated using a probability-weighted, discounted cash flow model with multiple scenarios, if applicable. The present value of future estimated cash flows was calculated using a credit-adjusted, risk-free rate in order to determine the fair value of the conditional asset retirement obligations at the time of implementation of FIN 47.

Upon implementation of FIN 47, we recorded an asset retirement obligation of $16 million at its net present value of $3 million, increased depreciable assets by an immaterial amount for asset retirement costs and recognized the cumulative effect of accounting change as a loss of less than $1 million net of tax.

The following table illustrates on a pro forma basis the amount of the asset retirement obligation as if FAS 143 had been applied during 2004 and 2003. These pro forma amounts are estimated based upon the information, assumptions, and interest rates used to measure the liability for conditional asset retirement obligations recognized upon implementation of FIN 47 as of December 31, 2005.

	Years Ended December 31,
		2005		2004		2003
		Actual		Pro Forma		Pro Forma
	-Thousands of Dollars-
Asset Retirement Obligation, beginning of year	$	2,454	$	2,277	$	2,113
Accretion Expense		190		177		164
Asset Retirement Obligation, end of year	$	2,644	$	2,454	$	2,277

The following tables illustrate on a pro forma basis the effect on UniSource Energy’s net income and earnings per share and TEP’s net income as if FIN 47 had been in effect for all income statement periods presented:

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UniSource Energy:

	Years Ended December 31,
	2004		2003
	-Thousands of Dollars-
	(except per share data)
Net Income - As Reported	$	45,919		$	113,941
Adjustment to accrued expense (net of tax) as if FIN 47 had been applied effective January 1, 2003		(107	)		(99	)
Pro Forma Net Income	$	45,812		$	113,842
Basic Earnings per Share:
As Reported	$	1.34		$	3.37
Adjustment to accrued expense (net of tax) as if FIN 47 had been applied effective January 1, 2003		-			-
Pro Forma	$	1.34		$	3.37
Diluted Earnings per Share:
As Reported	$	1.31		$	3.32
Adjustment to accrued expense (net of tax) as if FIN 47 had been applied effective January 1, 2003		-			-
Pro Forma	$	1.31		$	3.32

TEP:

	Years Ended December 31,
	2004		2003
	-Thousands of Dollars-

Net Income - As Reported	$	46,127		$	128,913
Adjustment to accrued expense (net of tax) as if FIN 47 had been applied effective January 1, 2003		(107	)		(99	)
Pro Forma Net Income	$	46,020		$	128,814

TEP has identified legal obligations to retire generation plant assets specified in land leases for its jointly-owned Navajo and Four Corners Generating Stations. The land on which these stations reside is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. TEP also has certain environmental obligations at the San Juan Generating Station (San Juan). TEP has estimated that its share of the cost to remove the Navajo and Four Corners facilities and to settle the San Juan environmental obligations will be approximately $38 million at the date of retirement. No other legal obligations to retire generation plant assets were identified. As of December 31, 2002, TEP had accrued $113 million for the final decommissioning of its generating facilities. As discussed below, this amount was reversed for 2002 and included as part of the cumulative effect of accounting change adjustment when FAS 143 was adopted on January 1, 2003.

On November 12, 2004, TEP, Phelps Dodge Energy Services, LLC and PNM Resources, Inc. each purchased from Duke Energy North America, LLC a one-third interest in a limited liability company which owns the partially constructed natural gas-fired Luna Energy Facility (Luna) in southern New Mexico. Luna is designed as a 570-MW combined cycle plant and is expected to be operational by the summer of 2006. The new owners assumed asset retirement obligations to remove certain piping and evaporation ponds and to restore the ground to its original condition. TEP has estimated its share to settle the obligations will be approximately $2 million at the date of retirement.

TEP and UES have various transmission and distribution lines that operate under land leases and rights of way that contain end dates and restorative clauses. TEP and UES operate their transmission and distribution

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systems as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, TEP and UES are not recognizing the costs of final removal of the transmission and distribution lines in their financial statements. As of December 31, 2005, TEP had accrued $75 million and UES had accrued $4 million for the net cost of removal for interim retirements from its transmission, distribution and general plant. As of December 31, 2004, TEP had accrued $67 million and UES had accrued $2 million for these removal costs. These amounts are reflected in the financial statements as a regulatory liability.

Upon implementation of FAS 143 on January 1, 2003, TEP recorded an asset retirement obligation of $38 million at its net present value of $1.1 million, increased depreciable assets by $0.1 million for asset retirement costs, reversed $112.8 million of costs previously accrued for final removal from accumulated depreciation, reversed previously recorded deferred tax assets of $44.2 million and recognized the cumulative effect of accounting change as a gain of $111.7 million ($67.5 million net of tax). The implementation of FAS 143 also resulted in a $6 million reduction of current depreciation expense charged throughout the year because asset retirement costs are no longer recorded as a component of depreciation expense.

Asset retirement obligation amounts are subject to various assumptions and determinations, such as determining whether a conditional or legal obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and the credit-adjusted risk-free interest rates to be used to discount future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations.

If TEP retires any asset at the end of its useful life, without a legal obligation to do so, it will record retirement costs at that time as incurred or accrued. TEP does not believe that the implementation of FAS 143 will result in any change in retail rates since all matters relating to the rate-making treatment of TEP’s generating assets were determined pursuant to the TEP Settlement Agreement.

NOTE 4. SEGMENT AND RELATED INFORMATION

Based on the way we organize our operations and evaluate performance, we have four reportable segments:

(1)	TEP, a vertically integrated electric utility business, is UniSource Energy’s largest subsidiary.

(2)	UNS Gas is a regulated gas distribution business. Results from UNS Gas are for the calendar years ended December 31, 2005 and 2004 and for the period from August 11, 2003 through December 31, 2003 (see Note 1).

(3)	UNS Electric is a regulated electric distribution utility business. Results from UNS Electric are for the calendar years ended December 31, 2005 and 2004 and for the period from August 11, 2003 through December 31, 2003 (see Note 1).

(4)	Global Solar, a developer and manufacturer of light-weight thin-film photovoltaic cells and panels, is the largest investment held by Millennium.

The UniSource Energy, UES and Millennium holding companies, UED, and several other subsidiaries and equity investments, which are not considered reportable segments, are included in All Other. Through affiliates, Millennium holds investments in several unregulated energy and emerging technology companies. UED, a wholly-owned subsidiary of UniSource Energy, developed generating resources and performed other project development activities, including the expansion of the Springerville Generating Station.

Significant revenues and expenses included in All Other include the following:

·	In 2005, Millennium recorded its share of income related to a gain on the sale of an investment by one of its investees. Millennium also recognized an impairment loss in 2005 related to the sale of one of its investments in January 2006.

·	In 2004, Millennium recorded its share of income and losses related to gains and losses on sales of investments by its investees.

·	In 2004, UED recognized an impairment loss on the entire $2 million balance of a note receivable.

·	In 2003, UED received a development fee (including accrued interest on development funds advanced) of $11 million in connection with expansion of the Springerville Generating Station. See Note 13.

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Significant reconciling adjustments consist of the elimination of intercompany activity and balances. Global Solar recorded revenue from transactions with TEP of less than $1 million in 2005, $4 million in 2004 and $8 million in 2003. Millennium’s other subsidiaries also recorded revenue from transactions with TEP of $12 million in 2005, $13 million in 2004 and $8 million in 2003. TEP’s related expense is reported in Other Operations and Maintenance expense on its income statement. Global Solar’s and Millennium’s revenue and TEP’s related expense are eliminated in UniSource Energy consolidation. Other significant reconciling adjustments include the elimination of investments in subsidiaries held by UniSource Energy, the intercompany note between UniSource Energy and TEP, the related interest income and expense on the note and reclassifications of deferred tax assets and liabilities. UniSource Energy repaid the intercompany note in 2005. See Note 9.

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. Our portion of the net income (loss) of the entities in which TEP and Millennium own a 20-50% interest or have the ability to exercise significant influence is shown below in Net Income (Loss) from Equity Method Entities.

We disclose selected financial data for our reportable segments in the following tables:

	Reportable Segments
2005		TEP			UNS Gas			UNS Electric			Global Solar			All Other			Reconciling Adjustments			UniSource Energy
Income Statement	-Millions of Dollars-
Operating Revenues - External	$	935		$	138		$	150		$	5		$	2		$	-		$	1,230
Operating Revenues - Intersegment		2			-			-			-			13			(15	)		-
Depreciation and Amortization		115			7			10			3			1			-			136
Amortization of Transition Recovery Asset		56			-			-			-			-			-			56
Interest Income		21			-			-			-			-			(1	)		20
Net Income from Equity Method Entities		-			-			-			-			2			-			2
Interest Expense		140			6			5			1			10			(2	)		160
Income Tax Expense (Benefit)		34			3			3			(5	)		(2	)		-			33
Net Income (Loss)		48			5			5			(7	)		(5	)		-			46
Cash Flow Statement
Net Cash Flows - Operating Activities		243			14			21			(5	)		3			-			276
Net Cash Flows - Investing Activities - Capital Expenditures		(150	)		(23	)		(30	)		-			-			-			(203	)
Net Cash Flows - Investing Activities - Investments in and Loans to Equity Method Entities		-			-			-			-			(5	)		-			(5	)
Net Cash Flows - Investing Activities - Other		21			-			-			-			17			-			38
Net Cash Flows - Financing Activities		(174	)		15			8			5			32			(1	)		(115	)
Balance Sheet
Total Assets		2,575			233			161			20			1,012			(874	)		3,127
Investments in Equity Method Entities		2			-			-			-			25			-			27

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2004
Income Statement
Operating Revenues - External	$	887		$	129		$	144		$	5		$	4		$	-		$	1,169
Operating Revenues - Intersegment		2			-			-			4			14			(20	)		-
Depreciation and Amortization		117			5			9			3			1			-			135
Amortization of Transition Recovery Asset		50			-			-			-			-			-			50
Interest Income		29			-			-			-			-			(9	)		20
Net Income from Equity Method Entities		-			-			-			-			6			-			6
Interest Expense		157			6			5			-			9			(9	)		168
Income Tax Expense (Benefit)		35			4			3			(4	)		(4	)		-			34
Net Income (Loss)		46			6			4			(5	)		(5	)		-			46
Cash Flow Statement
Net Cash Flows - Operating Activities		275			21			19			(10	)		7			(5	)		307
Net Cash Flows - Investing Activities - Capital Expenditures		(130	)		(19	)		(19	)		-			-			1			(167	)
Net Cash Flows - Investing Activities - Investments in and Loans to Equity Method Entities		-			-			-			-			(4	)		-			(4	)
Net Cash Flows - Investing Activities - Other		4			-			-			-			11			-			15
Net Cash Flows - Financing Activities		(101	)		(1	)		(2	)		9			(7	)		4			(98	)
Balance Sheet
Total Assets		2,742			201			135			20			930			(852	)		3,176
Investments in Equity Method Entities		2			-			-			-			34			-			36

2003
Income Statement
Operating Revenues - External	$	851		$	47		$	56		$	2		$	17		$	-		$	973
Operating Revenues - Intersegment		1			-			-			8			9			(18	)		-
Depreciation and Amortization		121			2			3			3			2			-			131
Amortization of Transition Recovery Asset		32			-			-			-			-			-			32
Interest Income		31			-			-			-			-			(11	)		20
Net Loss from Equity Method Entities		-			-			-			-			(3	)		-			(3	)
Interest Expense		161			2			2			1			12			(11	)		167
Income Tax Expense (Benefit)		21			1			1			(5	)		(6	)		-			12
Net Income (Loss)		129			1			2			(7	)		(11	)		-			114
Cash Flow Statement
Net Cash Flows - Operating Activities		261			5			8			(13	)		2			-			263
Net Cash Flows - Investing Activities - Capital Expenditures		(122	)		(9	)		(5	)		(2	)		1			-			(137	)
Net Cash Flows - Investing Activities - Investments in and Loans to Equity Method Entities		-			-			-			-			(2	)		-			(2	)
Net Cash Flows - Investing Activities - Other		11			(137	)		(84	)		-			(2	)		-			(212	)
Net Cash Flows - Financing Activities		(141	)		149			93			16			(19	)		-			98
Balance Sheet
Total Assets		2,767			185			125			26			845			(825	)		3,123
Investments in Equity Method Entities		5			-			-			-			31			-			36

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NOTE 5. ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES

TEP enters into forward contracts to purchase or sell a specified amount of capacity or energy at a specified price over a given period of time, within established limits to take advantage of favorable market opportunities and reduce exposure to energy price risk resulting from generation and procurement of power. In general, TEP enters into forward power purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward power sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. In addition, TEP has a natural gas supply agreement under which it purchases all of its gas requirements at spot market prices from Southwest Gas Corporation (SWG). In an effort to minimize price risk on these purchases, TEP enters into price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices.

All of TEP’s forward power sale contracts and forward power purchase contracts meet the definition of a derivative. A portion of TEP’s forward power contracts are considered to be normal purchases and sales and, therefore, are not required to be marked to market. However, some of TEP’s forward power contracts and all of the gas swap agreements are considered to be derivatives, which are required to be marked to market each reporting period. Certain of these forward power contracts, as well as the gas swaps, are accounted for as cash flow hedges. Unrealized gains and losses resulting from the change in the fair value of derivatives that meet the criteria for cash flow hedge accounting are recorded in Other Comprehensive Income, a component of Common Stock Equity, rather than in current earnings. The unrealized gains and losses are reclassified into earnings when the related transactions settle or terminate. The change in fair value of forward power contracts considered derivatives that are not accounted for as cash flow hedges is recorded in Net Income. There were no gains or losses recognized in Net Income related to hedge ineffectiveness because all cash flow hedges are considered to be effective.

The unrealized gains and losses that TEP reclassified into earnings from Other Comprehensive Income were $6 million in 2005, less than $1 million in 2004 and in 2003.

TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, 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.

UNS Gas and UNS Electric do not currently have any contracts that are required to be marked to market. UNS Gas does have a natural gas supply and management agreement under which it purchases substantially all of its gas requirements at market prices from BP Energy Company (BP). However, the contract terms allow UNS Gas to lock in fixed prices on a portion of its gas purchases by entering into fixed price forward contracts with BP at various times during the year. This enables UNS Gas to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% and not more than 80% of the expected monthly gas consumption prior to entering into the month. These forward contracts, as well as the main gas supply contract, meet the definition of normal purchases and therefore are not required to be marked to market.

MEG, a wholly-owned subsidiary of Millennium, enters into swap agreements, options and forward contracts relating to Emissions Allowances. MEG marks its trading contracts to market by recording unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month.

The market prices used to determine fair values for TEP and MEG’s derivative instruments are estimated based on various factors including broker quotes, exchange prices, over the counter prices and time value.

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The net pre-tax gains and losses from TEP and MEG’s derivative activities were as follows:

	Years Ended December 31,
	2005				2004			2003
	-Millions of Dollars-
TEP:
Net Unrealized Loss on Forward Power Sales - Cash Flow Hedges		$	(1	)	$	-	$	-
Net Realized Loss on Forward Power Sales - Cash Flow Hedges			(1	)		-		-
Net Unrealized Gain (Loss) on Forward Power Sales			1			2		(1	)
Net Unrealized Loss on Forward Power Purchases			(2	)		-		-
Net Unrealized Gain on Gas Price Swaps			11			3		-
Net Realized Gain on Gas Price Swaps			7			-		-
MEG:
Net (Loss) Gain from Trading Activities			(1	)		1		1

The fair value of TEP and MEG’s derivative assets and liabilities were as follows:

	December 31,
		2005			2004
	-Millions of Dollars-
TEP:
Derivative Assets - Current	$	12		$	2
Derivative Assets - Noncurrent		4			1
Derivative Liabilities - Current		3			-
Derivative Liabilities - Noncurrent		1			-
MEG:
Trading Assets - Current		24			71
Trading Assets - Noncurrent		14			6
Trading Liabilities - Current		(24	)		(65	)
Trading Liabilities - Noncurrent		(1	)		-

Beginning January 1, 2004, the settlement of forward purchase and sales contracts that do not result in physical delivery are recorded net as a component of Electric Wholesale Sales in TEP’s income statement. During 2005, $15 million in sales were netted against $16 million in purchases and in 2004, $5 million in sales were netted against $5 million in purchases.

In accordance with UniSource Energy’s intention to cease making capital contributions to Millennium, Millennium has significantly reduced the holdings and activity of MEG. MEG is in the process of winding down its activities and will not engage in any significant new activities after 2005.

CONCENTRATION OF CREDIT RISK

As of December 31, 2005, TEP had total credit exposure of $41 million related to its wholesale marketing and gas hedging activities, of which two counterparties composed greater than 10% of the total credit exposure. As of December 31, 2005, MEG had total credit exposure related to its trading activities of $14 million and was concentrated primarily with one counterparty. As of December 31, 2005, UNS Gas had a total credit exposure related to its gas supply contracts of $9 million, primarily related to its relationship with one counterparty. Counterparty credit exposure is calculated by adding any outstanding receivables (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts.

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NOTE 6. COMMITMENTS AND CONTINGENCIES

TEP COMMITMENTS

Purchase and Transportation Commitments

In 2003, the ACC issued the Track B Order which defined the competitive bidding process TEP must use to obtain capacity and energy requirements beyond what is supplied by TEP’s existing resources for the period 2003 through 2006. TEP estimated this to be approximately 0.5% of its retail load in the first year and gradually increasing over the period. This order further required TEP to bid out short-term energy purchases that it estimated it will make in the 2003 to 2006 period. The order does not require TEP to purchase any power that it deems to be uneconomical, unreasonable or unreliable. The Track B Order did not address TEP’s purchased power or asset acquisitions occurring subsequent to the 2003 competitive solicitation. In 2003, TEP entered into two power purchase agreements for the period 2003 through 2006 as listed below:

·	PPL Energy Plus, LLC supplied 37 MW from June 2003 through December 2003 and supplies 75 MW from January 2004 through December 2006, under a unit contingent contract. PPL assigned this contract to Arizona Public Service (APS) in May 2005 when APS purchased the Sundance generating units from PPL.

·	Panda Gila River generating station supplied 50 MW on-peak from June through September, from 2003 through 2005, under a unit contingent contract between TEP and Panda Gila River, L.P.

TEP made payments under these contracts of $18 million in 2005, $14 million in 2004, and $8 million in 2003.

TEP has several long-term contracts for the purchase and transportation of coal with expiration dates from 2006 through 2020. 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 or liquidated damages if certain minimum quantities of coal are not purchased and/or transported. TEP’s present fuel requirements are in excess of the take-or-pay minimums. At times, TEP has purchased coal from other suppliers, resulting in take-or-pay minimum charges, but a lower overall cost of fuel. TEP made payments under these contracts of $175 million in 2005 and 2004 and $167 million in 2003.

TEP has a Gas Procurement Agreement with Southwest Gas Corporation that expires in June 2006. TEP has been negotiating with SWG for a new supply agreement but the uncertainty of the changes on the El Paso Natural Gas (EPNG) pipeline in EPNG’s current rate proceeding has prevented TEP and SWG from agreeing to any long-term supply agreement. TEP has negotiated interim supply terms with SWG starting January 1, 2006 that do not have a minimum volume obligation. This arrangement goes from month to month until terminated by either party with a 30 day notice. TEP made total payments for commodity and transportation under this contract of $43 million in 2005 and $34 million in 2004 and 2003.

In November 2005, TEP entered into a natural gas Transportation Supply Agreement (TSA) with EPNG to fuel TEP’s portion of the Luna facility. The TSA provides 30,000 MMBtu of capacity from May through September, and 24,000 MMBtu of capacity from October to April. The contract begins in February 2006 and has an initial term of three years.

At December 31, 2005, TEP estimates that future minimum payments under the contracts for purchased power, coal, and gas referred to above are as follows:

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		Minimum
		Purchase
		Obligations
		-Millions of Dollars-

2006	$	107
2007		82
2008		82
2009		79
2010		79
Total 2006 - 2010		429
Thereafter		282
Total	$	711

Operating Leases

TEP, Millennium, UES and UED have entered into operating leases, primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates. UniSource Energy’s consolidated operating lease expense was $2 million in 2005 and $3 million in each of 2004 and 2003. TEP’s operating lease expense was $1 million in 2005 and 2004 and $2 million in 2003. UniSource Energy and TEP’s estimated future minimum payments under non-cancelable operating leases at December 31, 2005 are as follows:

		UniSource Energy		TEP
	-Millions of Dollars-

2006	$	2	$	1
2007		2		1
2008		2		1
2009		1		1
2010		1		-
Total 2006 - 2010		8		4
Thereafter		3		-
Total	$	11	$	4

Environmental Regulation

The 1990 Federal Clean Air Act Amendments call for reductions of SO₂ and nitrogen oxide (NOx) emissions in two phases. TEP is subject only to Phase II of the SO₂and NOx emissions reductions which was effective January 1, 2000. All of TEP’s generating facilities (except existing internal combustion turbines) are affected. TEP capitalized less than $1 million in 2005, $9 million in 2004, and $11 million in 2003 in construction costs to comply with environmental requirements and expects to capitalize $3 million in 2006 and $10 million in 2007. These amounts exclude the upgraded emissions control equipment at the Springerville Generating Station that was paid for by the Unit 3 project and recorded at zero basis by TEP. See Note 13. In addition, TEP recorded expenses of $11 million in 2005, $9 million in 2004 and $8 million in 2003 related to environmental compliance, including the cost of lime used to scrub the stacks. TEP expects environmental expenses to be $11 million in 2006 and 2007.

In 1993, TEP’s generating units affected by Phase II were allocated SO₂ Emissions Allowances based on past operational history. Beginning in the year 2000, Phase II generating units were required to hold Emissions Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years. TEP had sufficient Emissions Allowances to comply with the Phase II SO₂regulations for compliance year 2005. However, due to potential changes in the legislation affecting SO₂ Emission Allowances allocation, TEP may have to purchase additional Emissions Allowances for future compliance years 2010 or beyond.

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The EPA has issued a determination that coal and oil-fired electric utility steam generating units must control their mercury emissions. On March 15, 2005, the EPA adopted regulations relating to mercury emissions under Section 111 of the Clean Air Act. Additional rule-making procedures will take place at the state level prior to implementation of the new regulations. TEP is analyzing the potential impact of the regulations on its operations. Until these state procedures are adopted, TEP can not determine if it will be significantly affected. If TEP is not allocated sufficient allowances for its current emissions, it may have to purchase additional allowances on the market, or implement additional controls to reduce emissions. 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.

Income Tax Assessments

In 2004, the Company settled the audit of state income tax returns for the period 1990 - 2000 with the Arizona Department of Revenue. As a result, UniSource Energy and TEP recorded $1 million of income. Expense of $1 million had been recorded at TEP and Nations Energy in 2003 when the preliminary audit report was received. No additional tax assessments were levied in 2004. See Recent IRS Action in Note 14.

Sales Tax Assessments

In 2004, the City of Tucson issued its assessment for the 1998 - 2001 sales tax audit. After reviewing the audit findings, as well as assessing their impact on years subsequent to the audit period, TEP recorded a combined $1 million of sales tax and interest expense. The audit was settled during the first quarter of 2005.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of a 62-mile transmission line from Tucson to Nogales, Arizona. This project was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales, Arizona.

In 2002, the ACC approved the location and construction of the proposed 345-kV line along the Western Corridor route subject to a number of conditions, including obtaining all required permits from state and federal agencies. TEP is currently seeking approvals for the project from the Department of Energy (DOE), the US Forest Service, the Bureau of Land Management, and the International Boundary and Water Commission.

The DOE has completed a Final Environmental Impact Statement (EIS) for the project in which it would accept any of the routes in the EIS but, the U.S. Forest Service has indicated the Central route as its preferred alternative, rather than the Western Corridor route.

Based on the alternative proposals and passage of time since it approved the location of the line, the ACC, in January 2005, ordered TEP to review the status of electric service reliability in Nogales, Arizona and the need for the 345-kV line. The ACC also indicated that it would review any new information regarding the location of the proposed transmission line. In December 2005, an Administrative Law Judge (ALJ) for the ACC issued a recommended opinion and order reaffirming the ACC’s original position requiring the construction of the Tucson to Nogales transmission line. After a hearing on the issue, the ACC directed the ALJ to amend the recommendation to direct the Line Siting Committee of the ACC to gather facts related to options for improving service reliability in Nogales, Arizona. TEP expects the ACC to address the ALJ’s amended recommended opinion and order in the first half of 2006.

Through December 31, 2005, approximately $11 million in land acquisition, engineering and environmental expenses have been capitalized related to this project. If TEP does not receive the required approvals, it may be required to expense $9 million of costs that have been capitalized related to the project.

UES COMMITMENTS

UNS Gas has firm transportation agreements with El Paso Natural Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its load requirements. The EPNG and Transwestern contracts expire in August 2011 and January 2007, respectively. EPNG provides gas transportation service under a converted full requirements contract in which UNS Gas pays a fixed reservation charge. In July

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2003, FERC required the conversion of UNS Gas' full requirements status under the EPNG agreement to contract demand starting on September 1, 2003. Upon conversion to contract demand status, UNS Gas now has specific volume limits in each month and specific receipt point rights from the available supply basins (San Juan and Permian). These changes reduced the amount of less expensive San Juan gas available to UNS Gas. The impact, however, is not expected to be material. The annual cost of the EPNG capacity after conversion to contract demand did not change. EPNG filed a rate case in 2005 with new, higher rates to be effective January 2006, subject to refund. Beginning in January 2006, UNS Gas’ volumes average 1,050,000 therms per day in the winter months (November through March) and 310,000 therms per day in the summer months (April through October). The minimum expected annual payment is $7 million based on EPNG’s filed rates. UNS Gas made payments under these contracts of $7 million in 2005 and 2004 and $2 million from August 11, 2003 through December 31, 2003.

UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. UNS Electric’s transmission capacity agreements with WAPA provide for annual rate adjustments and expire in February 2008 and June 2011. The contract that expires in 2008 also contains a capacity adjustment clause. UNS Electric made payments under these contracts of $7 million in 2005, $6 million in 2004 and $2 million from August 11, 2003 through December 31, 2003.

At December 31, 2005, UES estimates its future minimum payments under these contracts to be:

		Minimum
		Purchase
		Obligations
		-Millions of Dollars-

2006	$	18
2007		14
2008		9
2009		9
2010		8
Total 2006 - 2010		58
Thereafter		8
Total	$	66

In February 2006, UNS Gas extended its firm transportation contract with Transwestern through February 2012; the minimum expected annual payment is $2 million from the end of the current contract until contract expiration.

See Note 9 for a description of UES’ long-term debt.

MILLENNIUM COMMITMENTS

Millennium has been authorized to fund its subsidiaries up to an additional $5 million over three years for capital and operations.

TEP CONTINGENCIES

Litigation and Claims Related to San Juan Generating Station

Public Service Company of New Mexico (PNM), operator of San Juan, and the coal supplier to San Juan have been participating in sessions sponsored by the Environmental Protection Agency (EPA) to consider rulemaking for the disposal of coal combustion products because of claims by third parties that San Juan has contaminated water resources in the region as a result of disposing of fly ash in the surface mine pits adjacent to the generating station. In November 2004, a contractor for the EPA released a non-binding preliminary determination that any contamination at San Juan cannot be conclusively attributed to the disposal of fly ash; however, the EPA has not made a final determination. TEP owns 50% of San Juan Units 1 and 2, which equates

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to 19.8% of the total San Juan Generating Station. TEP does not believe that this issue will have a material adverse impact on TEP or its operations.

Litigation and Claims Related to Navajo Generating Station

On October 15, 2004, Peabody Western Coal Company (Peabody), the coal supplier to the Navajo Generating Station, filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP, for reimbursement of royalties and other costs and breach of the coal supply agreement. The case was removed to Federal District Court Eastern District of Missouri on February 10, 2005. Peabody subsequently filed a motion to remand to superior court. Because TEP owns 7.5% of the Navajo Generating Station, its share of the current claimed damages would be approximately $35 million. TEP believes these claims are without merit and intends to continue to contest them.

Postretirement and Pension Benefit Costs at Navajo Generating Station

In 1996, Peabody filed a lawsuit in Maricopa County Superior Court against the participants at Navajo Generating Station, including TEP, for postretirement benefit costs payable to the coal supplier’s employees under the coal supply agreements. The Navajo participants and Peabody have agreed to stay the discovery process in this litigation to allow the parties additional time to negotiate a potential settlement. To the extent that amounts become estimable and payment probable, TEP will record a liability for additional postretirement benefit costs at the Navajo Generating Station. TEP does not expect any settlement to be material to TEP.

TEP has previously settled claims for postretirement benefit costs with the coal suppliers at Springerville Generating Station and Four Corners Generating Station. The cost of postretirement benefits is included in the cost of coal to San Juan.

Environmental Reclamation at Remote Generating Stations

TEP currently pays on-going reclamation costs related to the coal mines which supply the remote generating stations, and it is probable that TEP will have to pay a portion of final reclamation costs upon mine closure. When a reasonable estimate of final reclamation costs is available, the liability is recognized as a cost of coal over the remaining term of the respective coal supply agreement. TEP estimates its undiscounted final reclamation liability to be $41 million, and the present value of TEP’s liability for final reclamation approximates $11 million at the expiration dates of the coal supply agreements. At December 31, 2005 and 2004, TEP had recorded $2 million and $1 million, respectively, of its post-term reclamation liability, which is included in Other Liabilities in the balance sheets.

Amounts recorded for final reclamation are subject to various assumptions and determinations, such as estimating the costs of reclamation, estimating when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for post-term reclamation. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year since recognition occurs over the remaining lives of its coal supply agreements.

RESOLUTION OF SPRINGERVILLE GENERATING STATION COMPLAINT

Environmental activist groups have expressed concerns regarding the construction of any new units at the Springerville Generating Station. In January 2003, environmental activist groups appealed an ACC Order affirming the ACC’s approval of the expansion at the Springerville Generating Station to the Superior Court of the State of Arizona. On October 22, 2003, the Superior Court affirmed the ACC’s issuance of the Certificate of Environmental Compatibility for Springerville Generating Station. The environmental activist groups appealed the Superior Court decision on December 30, 2003 and filed an amended notice of appeal on January 2, 2004 with the Arizona Court of Appeals. In February 2005, the Arizona Court of Appeals upheld the lower court’s ruling affirming the ACC’s approval of the expansion at Springerville Generating Station. In February 2005, the Grand Canyon Trust (GCT), one of the environmental activist groups with this appeal, and TEP reached a settlement under which the GCT agreed to drop all claims against TEP regarding Springerville Generating Station. As part of the settlement, TEP must implement new emission limits at units 1 and 2 of 0.27 lbs per MMbtu for SO₂ and 0.22 lbs per MMbtu for NOx both on a 12 month rolling average. In addition, TEP agreed to an 85% removal rate for SO₂ based on a 90

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day rolling average. The upgrades to units 1 and 2, that have been implemented as part of the plant expansion to include units 3 and 4, were already capable of achieving these reductions. The Supreme Court of Arizona denied the other environmental activist group’s petition for review on June 28, 2005.

GUARANTEES AND INDEMNITIES

In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis. The most significant of these guarantees are:

·	UES’ guarantee of $160 million of aggregate principal amount of senior unsecured notes issued by UNS Gas and UNS Electric to purchase the Citizens Arizona gas and electric utility assets,

·	UES’ guarantee of a $40 million unsecured revolving credit agreement for UNS Gas and UNS Electric,

·	UniSource Energy’s guarantee of approximately $8 million in natural gas transportation and supply payments in addition to building and equipment lease payments for UNS Gas, UNS Electric, and subsidiaries of Millennium, and

·	Millennium’s guarantee of approximately $1 million in building lease payments for a subsidiary at December 31, 2005. Millennium terminated this guarantee on January 12, 2006.

To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in UniSource Energy’s consolidated balance sheets.

In addition, UniSource Energy and its subsidiaries have indemnified the purchasers of interests in certain investments from additional taxes due for years prior to the sale of such investments. The terms of the indemnifications provide for no limitation on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations. We have not made any payments under the terms of these indemnifications to date.

We believe that the likelihood UniSource Energy, UES, or Millennium would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.

NOTE 7. UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

The following table shows Utility Plant in Service by company and major class at December 31:

				2005						2004
			- Millions of Dollars -
		TEP		UES		UniSource Energy		TEP		UES		UniSource Energy
Plant in Service:
Electric Generation Plant	$	1,233	$	5	$	1,238	$	1,206	$	5	$	1,211
Electric Transmission Plant		543		15		558		539		13		552
Electric Distribution Plant		883		92		975		823		74		897
Gas Distribution Plant		-		151		151		-		135		135
Gas Transmission Plant		-		18		18		-		12		12
General Plant		140		16		156		146		14		160
Intangible Plant		58		8		66		56		7		63
Electric Plant Held for Future Use		5		1		6		2		1		3
Total Plant in Service	$	2,862	$	306	$	3,168	$	2,772	$	261	$	3,033

Utility Plant under Capital Leases	$	723	$	1	$	724	$	723	$	1	$	724

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Intangible Plant primarily represents computer software costs. TEP’s unamortized computer software costs were $18 million as of December 31, 2005 and $24 million as of December 31, 2004. UES’ unamortized computer software costs were $4 million as of December 31, 2005 and $2 million as of December 31, 2004.

All TEP Utility Plant under Capital Leases is used in TEP’s generation operations.

The depreciable lives currently used by TEP are as follows:

Major Class of Utility Plant in Service	Depreciable Lives

Electric Generation Plant	23-70 years
Electric Transmission Plant	10-50 years
Electric Distribution Plant	24-60 years
General Plant	5-45 years
Intangible Plant	3-10 years

During the second quarter 2005, a study requested by the participants in the San Juan Generating Station (San Juan) was completed which indicated San Juan’s economic useful life had changed from previous estimates. As a result of the study and other analysis performed, TEP lengthened the estimated useful life of San Juan from 40 to 60 years beginning April 1, 2005. The annual impact of this change in the estimated useful life is a reduction in depreciation expense of $6 million.

During the first quarter of 2004, TEP engaged an independent third party to review the economic estimated useful lives of its owned generating assets in Springerville, Arizona. TEP then hired a different independent third party to perform a depreciation study for its generation assets, taking into consideration the newly determined economic useful life for the Springerville assets, and changes in generation plant life information used by the operators and other participants of the joint power plants in which TEP participates. As a result of these analyses, in July 2004, TEP lengthened the useful lives of various generation assets for periods ranging from 11 to 22 years. Consequently, depreciation rates and the corresponding depreciation expense have been revised to reflect the life extensions. The annual impact of these changes in depreciation rates is a reduction in depreciation expense of $9 million.

See TEP Utility Plant in Note 1 and TEP Capital Lease Obligations in Note 9.

The depreciable lives currently used by UES are as follows:

Major Class of Utility Plant in Service	Depreciable Lives

Electric Generation Plant	23-40 years
Electric Transmission Plant	11-45 years
Electric Distribution Plant	14-26 years
Gas Distribution Plant	17-48 years
Gas Transmission Plant	37-55 years
General Plant	3-33 years

JOINTLY-OWNED FACILITIES

At December 31, 2005, TEP’s interests in generating stations and transmission systems that are jointly-owned with other utilities were as follows:

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	Percent Owned by TEP			Plant in Service *		Construction Work in Progress		Accumulated Depreciation
	-Millions of Dollars-
San Juan Units 1 and 2	50.0	%	$	303	$	3	$	215
Navajo Station Units 1, 2 and 3	7.5			131		3		72
Four Corners Units 4 and 5	7.0			82		-		65
Transmission Facilities	7.5 to 95.0			226		-		154
Luna Energy Facility	33.3			-		36		-
Total			$	742	$	42	$	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 6 for commitments related to TEP’s jointly-owned facilities.

In November 2004, TEP, Phelps Dodge Energy Services, LLC and PNM Resources, Inc. (PNMR) each purchased from Duke Energy North America, LLC a one-third interest in a limited liability company which owned the partially constructed natural gas-fired Luna Energy Facility (Luna). In February 2005, most of the assets of the limited liability company were transferred to the new owners so that each owner directly owns a one-third interest in the plant. Luna is designed as a 570-MW combined cycle plant in southern New Mexico and is expected to be operational by the summer of 2006. Luna is expected to provide TEP with 190 MW of power to serve its wholesale and retail customers. PNM, an affiliate of PNMR, is overseeing the completion of construction and will oversee the operation of Luna.

TEP paid $13 million for its one-third interest in Luna. In 2005, TEP spent $22 million for its one-third share of the costs to complete construction of Luna and purchase necessary inventory items and expects to spend an additional $14 million in 2006. TEP anticipates that internal cash flows will fund its share of the costs related to the plant.

NOTE 8. CREDIT FACILITIES

UNISOURCE ENERGY CREDIT AGREEMENT

In April 2005, UniSource Energy entered into a $105 million five-year credit agreement with a group of lenders (UniSource Credit Agreement) which expires on April 15, 2010. The UniSource Credit Agreement includes a $90 million term loan facility and a $15 million revolving credit facility. Quarterly principal payments of $1 million are due beginning June 30, 2005, with the balance due at maturity. At December 31, 2005, there was $86 million outstanding under the term loan facility at an interest rate of 6.24%. As of December 31, 2005, there were no borrowings outstanding under the revolving credit facility.

We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at LIBOR plus 1.75% or the agent bank’s reference rate plus 0.75%. We paid a commitment fee of 0.50% on the unused portion of the term loan until it was fully drawn in June 2005, and pay a commitment fee of 0.50% on the unused portion of the revolving credit facility.

The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, sales of assets, and certain investments and acquisitions. We must also meet: (1) a minimum cash flow to debt service coverage ratio for UniSource Energy on a standalone basis and (2) a maximum leverage ratio on a consolidated basis. We may pay dividends if, after giving effect to the dividend payment, we have more than $15 million of unrestricted cash and unused revolving credit. As of December 31, 2005, we were in compliance with the terms of the UniSource Credit Agreement.

If an event of default occurs, the UniSource Credit Agreement may become immediately due and payable. An event of default includes failure to make required payments under the UniSource Credit Agreement, failure of

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UniSource Energy or certain subsidiaries to make payments or default on debt greater than $20 million, or certain bankruptcy events at UniSource Energy or certain subsidiaries.

TEP CREDIT AGREEMENT

In May 2005, TEP entered into a new $401 million Credit Agreement (TEP Credit Agreement) to replace its previous $401 million credit agreement. The TEP Credit Agreement includes a $60 million revolving credit facility and a $341 million letter of credit facility to support $329 million of tax-exempt variable rate bonds. The TEP Credit Agreement expires in May 2010 and is secured by $401 million of 1992 Mortgage Bonds.

The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leasebacks agreements. The TEP Credit Agreement also requires TEP to meet a minimum cash coverage ratio and a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UniSource Energy. Certain regulatory actions may cause a decrease in the amount that may be borrowed. As of December 31, 2005, TEP was in compliance with the terms of the TEP Credit Agreement.

If an event of default occurs, the TEP Credit Agreement may become immediately due and payable. An event of default includes failure to make required payments under the TEP Credit Agreement; change in control, as defined; failure of TEP or certain subsidiaries to make payments or default on debt greater than $20 million; or certain bankruptcy events at TEP or certain subsidiaries.

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. Letter of credit fees are 0.875% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.875% per annum. TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.875% or at the agent bank’s reference rate. TEP also pays a commitment fee of 0.20% on the unused portion of the revolving credit facility.

As of December 31, 2005, TEP had no outstanding borrowings under its Revolving Credit Facility. On January 3, 2006, TEP borrowed $50 million under its Revolving Credit Facility. As of March 3, 2006, TEP had $40 million outstanding under its Revolving Credit Facility.

UNS GAS/UNS ELECTRIC REVOLVER

In April 2005, UNS Gas and UNS Electric entered into a $40 million three-year unsecured revolving credit agreement due in April 2008, with a group of lenders (the UNS Gas/UNS Electric Revolver). Either borrower may borrow up to a maximum of $30 million; however, the total combined amount borrowed cannot exceed $40 million.

UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Electric/UNS Gas Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric.

The borrowers have the option of paying interest at LIBOR plus 1.50% or at the agent bank’s reference rate plus 0.50%. UNS Gas and UNS Electric also pay a commitment fee of 0.45% on the unused portion of the revolving credit facility.

The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, mergers and sales of assets. The UNS Gas/UNS Electric Revolver also contains a maximum leverage ratio and a minimum cash flow to interest coverage ratio for each borrower. As of December 31, 2005, UNS Gas and UNS Electric were each in compliance with the terms of the UNS Gas/UNS Electric Revolver.

If an event of default occurs, the UNS Gas/UNS Electric Revolver may become immediately due and payable. An event of default includes failure to make required payments under the UNS Gas/UNS Electric Revolver; certain change in control transactions, certain bankruptcy events of UNS Gas or UNS Electric, or failure of UES, UNS Gas or UNS Electric to make payments or default on debt greater than $4 million.

As of December 31, 2005, UNS Gas had no borrowings outstanding and UNS Electric had $5 million of borrowings outstanding under the UNS Gas/UNS Electric Revolver. As of March 3, 2006, UNS Gas had $5 million outstanding, and UNS Electric had $10 million outstanding under the UNS Gas/UNS Electric Revolver.

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NOTE 9. DEBT AND CAPITAL LEASE OBLIGATIONS

Long-term debt matures more than one year from the date of the financial statements. UniSource Energy and TEP’s long-term debt is summarized in the statements of capitalization.

UNISOURCE ENERGY DEBT

Convertible Senior Notes

In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due 2035. The Convertible Senior Notes are unsecured and are not guaranteed by TEP or any other UniSource Energy subsidiary. Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances.

Beginning on March 5, 2010, UniSource Energy will have the option to redeem the Convertible Senior Notes, in whole or in part, for cash, at a price equal to 100% of the principal amount plus accrued interest. Holders of the Convertible Senior Notes may require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain change of control transactions occur, or our common stock is no longer listed on a national securities exchange. The repurchase price will be 100% of the principal amount of the Convertible Senior Notes plus accrued interest.

Certain of the Convertible Senior Notes features are considered to be embedded derivatives. Based on current accounting requirements, we have concluded that the embedded derivatives either do not have any value or they are not required to be separated from the debt and accounted for separately.

In March 2005, UniSource Energy used $106 million of the net proceeds from this offering to repay the $95 million promissory note to TEP plus accrued interest of $11 million. TEP used these funds, along with borrowings under its revolving credit facility to repurchase and redeem $225 million of fixed rate tax-exempt borrowings. See TEP Debt - Bond Repurchase and Redemptions, below.

Intercompany Notes Payable

In 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 in a transaction which resulted in UniSource Energy becoming a holding company with TEP as its subsidiary. Following the share exchange, TEP transferred the stock of Millennium to UniSource Energy for a $95 million promissory note due in 2008. On March 1, 2005, UniSource Energy used $106 million of the $146 million of net proceeds from the convertible debt offering, see above, to repay the $95 million promissory note to TEP plus accrued interest of $11 million. Approximately $25 million of this note represented a gain to TEP. TEP did not record this gain in income. Instead, this gain was reflected as an increase in TEP’s common stock equity when UniSource Energy repaid the note.

In January 2005, UNS Gas established a short-term inter-company promissory note to UniSource Energy that allowed UNS Gas to borrow up to $10 million for general corporate purposes. In March 2005, UniSource Energy contributed an additional $6 million in equity to UNS Gas and an additional $4 million in equity to UNS Electric, and UNS Gas repaid the $6 million outstanding on this note from the proceeds of the $6 million equity contribution. In December 2005, UniSource Energy made a $10 million capital contribution to UNS Gas.

TEP DEBT

Bond Repurchase and Redemptions

TEP made a sinking fund payment of $1 million on its 1941 Mortgage IDBs in January 2005.

In March 2005, TEP redeemed at par the remaining $31 million of its 6.1% 1941 Mortgage IDBs, which were due in 2008, as well as the remaining $21 million of its 7.5% 1941 Mortgage IDBs, which were due in 2006. TEP recorded an expense of $0.1 million for debt costs that were capitalized and being amortized through 2008. On June 10, 2005, TEP satisfied and discharged the 1941 Mortgage.

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In May 2005, TEP purchased $147 million of its 1997 Pima Series B and $74 million of its 1997 Pima Series C fixed-rate tax-exempt bonds (Repurchased Bonds) at a price of $101.50 per $100 principal amount and redeemed at par the remaining $4 million of bonds outstanding under those series. TEP does not currently plan on canceling the Repurchased Bonds which will remain outstanding under their respective indentures; however, the Repurchased Bonds will not be presented in our financial statements. TEP recognized a loss of approximately $3 million on the Repurchased Bonds associated with the generation portion of its business. In addition, TEP capitalized approximately $3 million of costs for Repurchased Bonds associated with its regulated operations and will amortize the cost over the remaining life of the bonds. TEP may choose to cancel or resell the Repurchased Bonds to third parties in the future.

As a result of the capital contribution, intercompany note repayment, and the bond purchases and redemptions, TEP’s ratio of equity to total capitalization (excluding capital leases) improved to 40.5% as of December 31, 2005, which meets an ACC requirement and allows TEP to dividend up to 100% of its current year Net Income to UniSource Energy.

TEP made the required sinking fund payments of $2 million on its 1941 Mortgage IDBs in each of 2004 and 2003. TEP redeemed the remaining $27 million of its 8.5% 1941 Mortgage Bonds in 2004. TEP paid a premium of $0.4 million related to the 2004 redemption. A portion of this premium was expensed immediately, while the remainder is being amortized over the original life of the bonds. TEP did not issue any new bonds in 2004.

First and Second Mortgage Indentures

In June 2005, TEP terminated its 1941 Mortgage (previously known as its First Mortgage). TEP’s remaining mortgage is its 1992 Mortgage (previously known as its Second Mortgage).

TEP's indenture creates liens on and security interests in most of TEP's utility plant assets, with the exception of Springerville Unit 2. San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title to Springerville Unit 2. Utility Plant under Capital Leases is not subject to such liens or available to TEP creditors, other than the lessors. The net book value of TEP's utility plant subject to the lien of the indenture was approximately $1 billion at December 31, 2005.

TEP CAPITAL LEASE OBLIGATIONS

The terms of TEP’s capital leases are as follows:

·	The Sundt 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 December 2017 for one lease and January 2021 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.

On or before each lease expiration date, TEP will determine if it will purchase the assets at the value stipulated in the lease or renegotiate the lease term. In some of the leases, the stipulated value is a fixed amount, and in others it is at fair market value.

In January 2006, TEP made the following scheduled lease payments: Sundt Lease $9 million; Springerville Common Facilities Leases $2 million; Springerville Unit 1 Leases $69 million; and Springerville Coal Handling Facilities Leases $6 million.

Springerville Lease Debt

TEP held an investment in Springerville Unit 1 lease debt totaling $91 million at December 31, 2005 and $98 million at December 31, 2004. TEP purchased an additional $4 million of Springerville Unit 1 lease debt in 2004,

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but made no comparable purchases in 2005. TEP received $7 million in principal payments related to this investment in each of 2005 and 2004.

TEP also held an investment in Springerville Coal Handling Facilities lease debt totaling $65 million at December 31, 2005 and $73 million at December 31, 2004. TEP received principal payments related to this investment of $7 million in 2005 and $5 million in 2004.

In the fourth quarter of 2004, TEP determined that one of its capital lease assets and the corresponding obligation were overstated. To reduce the obligation, an adjustment of $20 million was recorded.

In 1985, TEP sold and leased back its undivided one-half ownership interest in the common facilities at the Springerville Generating Station. Under the terms of the Springerville Common Facilities Leases, TEP must periodically arrange for refinancing or refunding of the secured notes underlying the leases prior to the named date in order to avoid a special event of loss. The special event of loss date is currently set at June 30, 2006. Interest on the debt is payable at LIBOR plus 4.00%. The LIBOR rate is reset every six months and the average rate in effect on December 31, 2005 was 3.68%, which resulted in a total average interest rate on the lease debt of 7.68% at year end.

UNS GAS AND UNS ELECTRIC LONG-TERM DEBT

Senior Unsecured Notes

On August 11, 2003, UNS Gas and UNS Electric issued a total of $160 million of aggregate principal amount of senior unsecured notes in a private placement. Proceeds from the note issuance were paid to Citizens to purchase the Arizona gas and electric system assets. UNS Gas issued $50 million of 6.23% notes due August 11, 2011 and $50 million of 6.23% notes due August 11, 2015. UNS Electric issued $60 million of 7.61% notes due August 11, 2008. All three series of notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity U.S. Treasury security yield plus 50 basis points. UNS Gas and UNS Electric incurred a total of $2 million in debt costs related to the issuance of the notes. These costs were deferred and are being amortized over the life of the notes. The notes are guaranteed by UES.

The note purchase agreements for both UNS Gas and UNS Electric contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, incurrence of indebtedness, and minimum net worth. For purposes of these notes, net worth equals common stock equity less amounts attributable to minority interests and intangible assets not recoverable through rates. The actual and required minimum net worth levels at December 31, 2005 were as follows:

The incurrence of indebtedness covenant requires each of UNS Gas and UNS Electric to meet certain tests before an additional dollar of indebtedness may be incurred. These tests include (a) a ratio of Consolidated Long-Term Debt to Consolidated Total Capitalization of no greater than 0.65 to 1.00, and (b) an Interest Coverage Ratio (a measure of cash flow to cover interest expense) of at least 2.50 to 1.00. However, UNS Gas and UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $7 million in the case of UNS Gas, and $5 million in the case of UNS Electric. Neither UNS Gas nor UNS Electric, may declare or make distributions or dividends (restricted payments) on their common stock unless (a) immediately after giving effect to such action no default or event of default would exist under such company's note purchase agreement and (b) immediately after giving effect to such action, such company would be permitted to incur an additional dollar of indebtedness under the debt incurrence test for such company. As of December 31, 2005, UNS Gas and UNS Electric were in compliance with the terms of the note purchase agreements.

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MATURITIES AND SINKING FUND REQUIREMENTS

Long-term debt, including sinking funds, term loan payments, and capital lease obligations mature on the following dates:

	TEP IDBs		TEP Scheduled		TEP Capital
	Supported		Debt		Lease			TEP			UNS		UNS		UniSource
	by LOCs		Retirements		Obligations			Total			Gas		Electric		Energy		Total
- Millions of Dollars -
2006	$	-	$	-	$	124		$	124		$	-	$	-	$	5	$	129
2007		-		-		127			127			-		-		5		132
2008		-		138		120			258			-		60		5		323
2009		-		-		66			66			-		-		5		71
2010		329		-		93			422			-		-		66		488
Total 2006 - 2010		329		138		530			997			-		60		86		1,143
Thereafter		-		354		678			1,032			100		-		150		1,282
Less: Imputed Interest		-		-		(494	)		(494	)		-		-		-		(494	)
Total	$	329	$	492	$	714		$	1,535		$	100	$	60	$	236	$	1,931

Amounts payable by UniSource Energy represent quarterly principal payments due on the term loan facility discussed in Note 8. TEP’s tax-exempt variable rate bonds (IDBs) in the amount of $329 million are backed by LOCs issued pursuant to TEP’s Credit Agreement which expires in May 2010. The IDBs mature between 2018 and 2022. TEP’s obligations under the Credit Agreement are collateralized with the 1992 Mortgage Bonds.

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NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying values and fair values of our financial instruments are as follows:

	December 31,
	2005				2004
	Carrying Value		Fair Value		Carrying Value		Fair Value
	-Millions of Dollars-
Assets:
TEP Springerville Lease Debt Securities (included in Investments and Other Property)	$	156	$	165	$	171	$	182
Liabilities:
UNS Convertible Senior Notes:		150		152		-		-
UNS Credit Agreement - Term Loan		86		86		-		-
TEP 1941 Mortgage Bonds - IDBs (Fixed Rate)		-		-		53		53
TEP 1992 Mortgage Bonds:
IDBs (Variable Rate)		329		329		329		329
Collateral Trust Bonds		138		146		138		153
TEP Unsecured IDBs - Fixed Rate		354		361		579		568
UNS Gas Senior Unsecured Notes		100		105		100		108
UNS Electric Senior Unsecured Notes		60		62		60		64

See Note 9 for a description of TEP’s investment in Springerville Lease Debt. TEP intends to hold the $156 million investment in Springerville Lease Debt Securities to maturity ($39 million matures through January 1, 2009, $73 million matures through July 1, 2011, and $59 million matures through January 1, 2013). This investment is stated at amortized cost, which means the purchase cost has been adjusted for the amortization of the premium and discount to maturity. TEP determined the fair value of this investment by calculating the present value of the cash flows of each note, using a discount rate consistent with market yields generally available as of December 31, 2005 and December 31, 2004 for bonds with similar characteristics with respect to credit rating and time-to-maturity. The use of different market assumptions and/or estimation methodologies may yield different estimated fair value amounts.

TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of their fair value. TEP determined the fair value of its taxable fixed rate obligations including the Collateral Trust Bonds by calculating the present value of the cash flows of each fixed rate obligation. TEP used a rate consistent with market yields generally available as of December 31, 2005 and December 31, 2004 for bonds with similar characteristics with respect to credit rating and time-to-maturity. The use of different market assumptions and/or estimation methodologies may yield different estimated fair value amounts. TEP based the fair value of its tax-exempt fixed rate obligations including the 1941 Mortgage IDBs and the Unsecured IDBs on quoted market prices for the same or similar debt. Quoted market prices were also used to value the UNS Convertible Senior Notes at December 31, 2005.

As of December 31, 2005, UNS Gas and UNS Electric determined the fair value of the $160 million of senior unsecured notes by calculating the present value of the cash flows of each note, using a discount rate consistent with market yields generally available as of December 31, 2005 for bonds with similar characteristics with respect to credit rating and time-to-maturity. 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.

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NOTE 11. STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UniSource Energy

In February 2006, UniSource Energy declared a first quarter dividend to shareholders of $0.21 per share of UniSource Energy Common Stock. The dividend, totaling approximately $7 million, will be paid on March 15, 2006 to common shareholders of record as of February 21, 2006. In 2005, UniSource Energy paid quarterly dividends to the shareholders of $0.19 per share, for a total of $0.76 per share, or $26 million for the year. In 2004, UniSource Energy paid quarterly dividends to the shareholders of $0.16 per share, for a total of $0.64 per share, or $22 million, for the year. During 2003, UniSource Energy paid quarterly dividends to the shareholders of $0.15 per share, for a total of $0.60 per share, or $20 million, for the year.

Our ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium and UED, as well as compliance with various debt covenant requirements. As of December, 31, 2005, we were in compliance with the terms of all such debt covenant requirements.

TEP

In May 2005, UniSource Energy made a $110 million capital contribution to TEP.

TEP paid dividends of $46 million in 2005, $32 million in 2004, and $80 million in 2003. UniSource Energy is the primary holder of TEP’s common stock. TEP met the requirements discussed below before paying these dividends.

Bank Credit Agreement

TEP’s new Credit Agreement as of May 2005 allows TEP to pay dividends as long as TEP maintains compliance with the agreement and certain 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. The UES Settlement Agreement, as approved by the ACC, modifies this dividend limitation so that it will remain in place until TEP’s common equity equals 40% of total capitalization (excluding capital lease obligations). As of December 31, 2005, TEP met this ratio requirement.

Federal Power Act

This Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP’s 2005, 2004 and 2003 dividends were paid from current year earnings.

UES

UES’ ability to pay dividends is limited by restrictions placed on its subsidiaries, UNS Gas and UNS Electric. As discussed in Note 2, the UES Settlement Agreement limits dividends payable by both UNS Gas and UNS Electric to UniSource Energy to 75% of earnings until the ratio of common equity to total capitalization reaches 40%. As of December 31, 2005, both UNS Electric and UNS Gas met this ratio requirement. As of December 31, 2004, UNS Electric met this ratio requirement. Additionally, the terms of the senior unsecured note agreements entered into by both UNS Gas and UNS Electric contain dividend restrictions. See Note 9. UES did not pay any dividends to UniSource Energy in 2005 or 2004.

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Millennium and UED

Millennium did not pay any dividends to UniSource Energy in 2005, 2004 or 2003. UED did not pay any dividends to UniSource Energy in 2005 or 2004. UED paid a dividend to UniSource Energy of $50 million in 2003. Millennium and UED have no dividend restrictions.

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 12. TEP WHOLESALE ACCOUNTS RECEIVABLE AND ALLOWANCES

TEP’s Accounts Receivable from Electric Wholesale Sales, included in Trade Accounts Receivable on the balance sheet, totaled $30 million at December 31, 2005 and $22 million at December 31, 2004, net of allowances. TEP’s Allowance for Doubtful Accounts on the balance sheet includes $13 million at December 31, 2005 and December 31, 2004 related to sales to the California Power Exchange (CPX) and the California Independent System Operator (CISO) in 2001 and 2000.

TEP’s collection shortfall from the CPX and the CISO was approximately $9 million for sales made in 2000 and $7 million for sales made in 2001. Since that time, the FERC staff has proposed various methodologies for calculating amounts of refunds/offsets applicable to wholesale sales made into the CISO’s spot markets from October 2000 to June 2001. Based upon a FERC order in March 2003 (as reaffirmed by the FERC on October 16, 2003), TEP estimated that it would receive approximately $6 million of its $16 million receivable. In May 2004, the FERC issued two separate orders addressing numerous issues in the refund calculation and the fuel cost allowance calculation (an offset to the refund obligation). Based on these new orders, TEP increased its reserve for sales to the CPX and the CISO by $3 million by recording a reduction of wholesale revenues.

There are several other outstanding legal issues, complaints and lawsuits concerning the California energy crisis related to the FERC, wholesale power suppliers, Southern California Edison Company, Pacific Gas and Electric Company, the CPX and the CISO. We cannot predict the outcome of these issues or lawsuits. We believe, however, that TEP is adequately reserved for its transactions with the CPX and the CISO.

NOTE 13. SPRINGERVILLE EXPANSION

On October 21, 2003 (the Closing Date), UED, TEP, Tri-State Generation and Transmission Association, Inc. (Tri-State) and Salt River Project Agricultural Improvement and Power District (SRP) entered into an Amended and Restated Joint Development Agreement, which provides for the development of two 400 MW coal-fired units at TEP’s existing Springerville Generating Station by parties other than TEP.

On the Closing Date, TEP transferred the right to construct Unit 3, together with associated rights, to Tri-State. Tri-State completed financing of Unit 3 on that date and immediately began construction. Once the unit is completed, Tri-State will lease 100% of Unit 3 through a 34-year leveraged lease agreement with GE Structured Finance and will take 300 MW of the 400 MW capacity.

Under the Joint Development Agreement, SRP will purchase 100 MW of Unit 3’s capacity from Tri-State under a 30-year power purchase agreement and will have the right to construct and own Unit 4 at a later date. If SRP decides to construct Unit 4, TEP and Tri-State may be required to find a replacement purchaser for SRP’s

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100 MW power purchase obligation from Unit 3. If TEP and Tri-State are unable to find a replacement purchaser, TEP would then purchase 100 MW of output from Unit 4, beginning with its commercial operation.

TEP executed contracts to provide operating, maintenance and other services to Units 3 and 4. TEP also agreed to purchase up to 100 MW of Tri-State system capacity for no more than five years from the time Unit 3 begins commercial operation, which we expect to occur in the third quarter of 2006. TEP benefited from upgraded emissions control equipment for Units 1 and 2 and other facilities at the Springerville Generating Station that were paid for by the Unit 3 project.

On the Closing Date, UED received reimbursement of all project development costs which it incurred in connection with Units 3 and 4 of approximately $29 million, plus a development fee (including accrued interest on development funds advanced) of $11 million. We recognized the development fee as income in the fourth quarter of 2003.

NOTE 14. INCOME AND OTHER TAXES

INCOME TAXES

We record deferred tax liabilities for amounts that will increase income taxes on future tax returns. We record deferred tax assets for amounts that could be used to reduce income taxes on future tax returns. We record a Deferred Tax Assets Valuation Allowance for the amount of Deferred Tax Assets that we may not be able to use on future tax returns. We estimate the valuation allowance based on our interpretation of the tax rules, prior tax audits, tax planning strategies, scheduled reversal of deferred tax liabilities, and projected future taxable income.

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Deferred tax assets (liabilities) consist of the following:

	UniSource Energy						TEP
	December 31,						December 31,
	2005			2004			2005			2004
	-Millions of Dollars-
Gross Deferred Income Tax Liabilities
Plant - Net	$	(435	)	$	(481	)	$	(424	)	$	(473	)
Income Taxes Recoverable Through Future
Revenues Regulatory Asset		(16	)		(18	)		(16	)		(18	)
Transition Recovery Asset		(66	)		(89	)		(66	)		(89	)
Derivative Financial Instruments		(5	)		(2	)		(5	)		(2	)
Pensions		(10	)		(9	)		(10	)		(9	)
Capitalized Repairs		(11	)		(6	)		(11	)		(6	)
Unbilled Revenue		(6	)		-			(6	)		-
Other		(26	)		(15	)		(14	)		(9	)
Gross Deferred Income Tax Liability		(575	)		(620	)		(552	)		(606	)

Gross Deferred Income Tax Assets
Capital Lease Obligations		297			314			297			314
Net Operating Loss Carryforwards (NOL)		7			7			-			-
Investment Tax Credit Carryforwards		-			5			-			5
Alternative Minimum Tax Credit (AMT)		77			100			62			92
Accrued Postretirement Benefits		21			19			21			19
Emission Allowance Inventory		13			14			13			14
Coal Contract Termination Fees		12			14			12			14
Springerville Coal Handling Facility		5			6			5			6
Reserve for Uncollectible Accounts		1			6			1			6
Unregulated Investment Losses		23			30			-			1
Minimum Pension Liability		9			7			9			7
Vacation & Sick Accrual		3			3			3			3
Customer Advances		8			5			3			3
Other		20			20			17			17
Gross Deferred Income Tax Asset		496			550			443			501
Deferred Tax Assets Valuation Allowance		(7	)		(8	)		-			(1	)
Net Deferred Income Tax Liability	$	(86	)	$	(78	)	$	(109	)	$	(106	)

The net deferred income tax liability is included in the balance sheets in the following accounts:

	UniSource Energy						TEP
	December 31,						December 31,
	2005			2004			2005			2004
	-Millions of Dollars-

Deferred Income Taxes - Current Assets	$	9		$	24		$	11		$	24
Deferred Income Taxes - Noncurrent Liabilities		(95	)		(102	)		(120	)		(130	)
Net Deferred Income Tax Liability	$	(86	)	$	(78	)	$	(109	)	$	(106	)

The valuation allowance of $7 million at December 31, 2005 and $8 million at December 31, 2004, which reduces the Deferred Tax Asset balance, relates to Net Operating Loss (NOL) and Investment Tax Credit (ITC) carryforward amounts. The decrease of $1 million is related to TEP’s use of ITC carryforward. The $7 million valuation allowance at December 31, 2005, relates to losses generated by the Millennium entities. In the future, if UniSource Energy and the Millennium entities determine that all or a portion of the losses may be used on tax returns, then UniSource Energy and the Millennium entities would reduce the valuation allowance and recognize

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benefit of up to $7 million. The primary factor that could cause the Millennium entities to recognize a tax benefit would be a change in expected future taxable income.

In 2004, the Deferred Tax Asset Valuation Allowance increased by $1 million relating to ITC carryforwards at TEP which might have expired unused.

In 2003, the Deferred Tax Assets Valuation Allowance decreased $15 million due primarily to TEP’s expectation of using a portion of its NOL and ITC carryforward amounts. This resulted in the reduction of Income Tax Expense for the year ended December 31, 2003.

As of December 31, 2005 UniSource Energy’s deferred income tax assets include $9 million related to unregulated investment losses of Millennium. These losses have not been reflected on UniSource Energy consolidated income tax returns. If UniSource Energy were unable to recognize such losses through its consolidated income tax return in the forseeable future, UniSource Energy would be required to write off these deferred tax assets. Millennium restructured its ownership in one of these investments, TFB, Inc. (TFB), in 2005. As a result of this restructuring, Millennium liquidated TFB for tax purposes resulting in a taxable loss that will be reflected on UniSource Energy’s consolidated income tax return for 2005. Millennium is in the process of restructuring its ownership in Corporacion Panamena de Energia, S.A. (COPESA) and expects to dispose of its stock interest in the foreseeable future.

TEP had a net intercompany tax payable to affiliates of $4 million at December 31, 2005 and $4 million at December 31, 2004. These amounts are included in TEP’s intercompany accounts on its balance sheet.

In 2004, UniSource Energy recognized $1 million of tax benefit as a result of the settlement of a state income tax audit. This amount is included in the income tax expense (benefit) tables below.

In 2003, UniSource Energy recognized $1 million of tax and interest expense in anticipation of settlement of state income tax audits and settlement of a state sales tax audit. The income taxes are included in the expense (benefit) tables below.

In 2005, the tax effect of the exercise of certain employee stock options that are recognized differently for financial reporting and tax purposes was not recorded as a timing difference, but rather was credited to shareholder’s equity. This resulted in a $2 million increase to the capital of UniSource Energy.

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Income tax expense (benefit) included in the income statements consists of the following:

	UniSource Energy									TEP
	Years Ended December 31,
	2005			2004			2003			2005			2004			2003
	-Millions of Dollars-
Current Tax Expense
Federal	$	16		$	21		$	11		$	16		$	28		$	14
State		9			7			5			11			8			7
Total		25			28			16			27			36			21
Deferred Tax Expense (Benefit)
Federal		13			7			12			13			-			16
State		(4	)		(2	)		(1	)		(5	)		(2	)		(1	)
Total		9			5			11			8			(2	)		15
Increase (Reduction) in Valuation Allowance		(1	)		1			(15	)		(1	)		1			(15	)
Total Federal and State Income Tax Expense Before Cumulative Effect of Accounting Change		33			34			12			34			35			21
Tax on Cumulative Effect of Accounting Change (See Note 3)		-			-			44			-			-			44
Total Federal and State Income Tax Expense Including Cumulative Effect of Accounting Change	$	33		$	34		$	56		$	34		$	35		$	65

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,
	2005			2004			2003			2005			2004			2003
	-Millions of Dollars-

Federal Income Tax Expense at Statutory Rate	$	28		$	28		$	21		$	29		$	28		$	29
State Income Tax Expense, Net of Federal Deduction		4			4			3			4			4			4
Depreciation Differences (Flow Through Basis)		3			3			4			3			3			4
Federal/State Credits		(1	)		(1	)		(2	)		(1	)		(1	)		(2	)
Increase (Reduction) in Valuation Allowance		(1	)		1			(15	)		(1	)		1			(15	)
Other		-			(1	)		1			-			-			1
Total Federal and State Income Tax Expense Before Cumulative Effect of Accounting Change	$	33		$	34		$	12		$	34		$	35		$	21

The Total Federal and State Income Tax Expense in the tables above is included on UniSource Energy and TEP’s income statements.

At December 31, 2005, UniSource Energy and TEP had, for federal and state income tax filing purposes, the following carryforward amounts:

	UniSource Energy				TEP
	Amount		Expiring		Amount		Expiring
	-Millions of Dollars-		Year		-Millions of Dollars-		Year
Net Operating Losses	$	18		2021-2022	$	-		-
AMT Credit		77		-		62		-

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The $18 million in NOL carryforwards at UniSource Energy is subject to limitation due to a reorganization of certain Millennium entities in December 2002. The future utilization of these losses is dependant upon the generation of sufficient future taxable income at the separate company level.

OTHER TAX MATTERS

On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets. The new accounting method was also used on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.

In August 2005, the Internal Revenue Service issued a ruling which draws into question the ability of electric and gas utilities to use the new accounting method. TEP believes the IRS position is without merit, and intends to vigorously pursue this issue. However, if the IRS were to prevail and disallow the change in its entirety TEP, UNS Gas and UNS Electric could be required to pay up to $19 million, $1 million and $1 million, respectively, in taxes and interest in the first half of 2006. Such payment would not affect total tax expense.

OTHER TAXES

TEP and UES act as conduits or collection agents for excise tax (sales tax) as well as franchise fees and regulatory assessments. They record liabilities payable to governmental agencies when they bill their customers for these amounts. Neither the amounts billed nor payable are reflected in the income statement.

NOTE 15. EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

TEP and UES maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees. Benefits are based on years of service and the employee's average compensation. TEP and UES fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by IRS benefit or compensation limitations.

OTHER POSTRETIREMENT BENEFIT PLANS

TEP provides limited 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 or an affiliate.

TEP amended its other postretirement benefit plan to cap Medicare supplement payments for all current retirees under age 65 and all classified employees retiring after December 31, 2002 and eliminate post-65 medical benefits for all salaried employees retiring after January 1, 2002. These amendments required TEP to recalculate benefits related to participants’ past service. TEP is amortizing the change in the benefit cost from these plan amendments on a straight-line basis over 10 years.

UniSource Energy acquired the Arizona gas and electric system assets from Citizens on August 11, 2003, assuming a $2 million liability for postretirement medical benefits for current retirees and a small group of active employees. The majority of UES employees do not currently participate in the postretirement medical plan.

The ACC allows TEP and UES to recover postretirement costs through rates only as benefit payments are made to or on behalf of retirees. The postretirement benefits are currently funded entirely on a pay-as-you-go basis. Under current accounting guidance, TEP and UES 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.

FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (FSP 106-2), provides guidance related to

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accounting for the federal subsidy available to certain employers providing retirees with prescription drug benefits. For public companies, FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004. Adoption of FSP 106-2 did not have a significant impact on our postretirement benefit costs or cash flows because prescription drug coverage is only available to a limited number of UniSource Energy retirees who are Medicare eligible.

The actuarial present values of all pension benefit obligations and other postretirement benefit plans were measured at December 1. The tables below include both TEP and UES plans. Amounts included for UES plans are not significant. The change in benefit obligation and plan assets and reconciliation of the funded status are as follows:

		Pension Benefits						Other Postretirement Benefits
		Years Ended December 31,
		2005			2004			2005			2004
		-Millions of Dollars-
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	188		$	162		$	70		$	68
Actuarial (Gain) Loss		9			16			(4	)		(1	)
Interest Cost		11			10			4			3
Service Cost		6			6			2			2
Benefits Paid		(6	)		(6	)		(2	)		(2	)
Benefit Obligation at End of Year		208			188			70			70

Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		136			124			-			-
Actual Return on Plan Assets		12			12			-			-
Benefits Paid		(6	)		(6	)		(2	)		(2	)
Employer Contributions		7			6			2			2
Fair Value of Plan Assets at End of Year		149			136			-			-

Reconciliation of Funded Status to Balance Sheet
Funded Status (Difference between Benefit
Obligation and Fair Value of Plan Assets)		(59	)		(52	)		(70	)		(70	)
Contributions After Measurement Date		5			-			-			-
Unrecognized Net Loss		55			50			24			30
Unrecognized Prior Service Cost (Benefit)		10			13			(8	)		(10	)
Net Amount Recognized in the Balance Sheets	$	11		$	11		$	(54	)	$	(50	)

Amounts Recognized in the Balance Sheets
Consist of:
Prepaid Pension Costs Included in Other Assets	$	18		$	17		$	-		$	-
Accrued Benefit Liability Included in Other Liabilities		(37	)		(35	)		(54	)		(50	)
Intangible Asset Included in Other Assets		6			9			-			-
Accumulated Other Comprehensive Income		24			20			-			-
Net Amount Recognized	$	11		$	11		$	(54	)	$	(50	)

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The accumulated benefit obligation (ABO) for all defined benefit pension plans was $173 million and $154 million at December 31, 2005 and 2004, respectively. The ABO was impacted by changes in actuarial assumptions including a reduction in the discount rate.

	December 31,
	2005		2004
	-Millions of Dollars-
Information for Pension Plans with an Accumulated
Benefit Obligation in Excess of Plan Assets:
Projected Benefit Obligation at End of Year	$	208	$	188
Accumulated Benefit Obligation at End of Year		173		154
Fair Value of Plan Assets at End of Year	$	149	$	136

The components of net periodic benefit costs are as follows:

	Pension Benefits									Other Postretirement Benefits
	Years Ended December 31,
	2005			2004			2003			2005			2004			2003
	-Millions of Dollars-
Components of Net Periodic Cost
Service Cost	$	7		$	6		$	5		$	2		$	2		$	2
Interest Cost		11			10			9			4			3			4
Expected Return on Plan Assets		(11	)		(10	)		(9	)		-			-			-
Prior Service Cost Amortization		2			2			2			(1	)		(1	)		(1	)
Recognized Actuarial Loss		3			2			2			2			2			2
Net Periodic Benefits Cost (Benefit)	$	12		$	10		$	9		$	7		$	6		$	7

For all pension plans, prior service costs are amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan.

Additional Information

Pension Benefits

Other Postretirement Benefits

Years Ended December 31,

2005

2004

2005

2004

-Millions of Dollars-

Minimum Pension Liability Included in

Other Comprehensive Income

N/A

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 1,
Discount Rate		5.80	%		6.00 - 6.10	%		5.80	%		5.90	%
Rate of Compensation Increase		3.00 - 5.00	%		3.00 - 5.00	%		-			-

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	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate		6.00 - 6.10	%		6.25	%		5.90	%		5.50	%
Rate of Compensation Increase		3.00 - 5.00	%		3.00 - 5.00	%		-			-
Expected Return on Plan Assets		8.50	%		8.75	%		-			-

Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. We estimated the expected return on plan assets based on a review of the plans’ asset allocations and consultations with a third-party investment consultant and the plans’ actuary considering market and economic indicators, historical market returns, correlations and volatility, central banks’ and government treasury departments’ forecasts and objectives, and recent professional or academic research. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.

	December 31,
	2005			2004
Assumed Health Care Cost Trend Rates
Health Care Cost Trend Rate Assumed for Next Year		10.00	%		11.00	%
Ultimate Health Care Cost Trend Rate Assumed		5.00	%		5.00	%
Year that the Rate Reaches the Ultimate Trend Rate		2013			2013

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2005 amounts:

	One-Percentage-Point Increase		One-Percentage-Point Decrease
		-Millions of Dollars-
Effect on Total of Service and Interest Cost Components	$ 1		$ -
Effect on Postretirement Benefit Obligation	$ 5		$ (4)

Pension Plan Assets

TEP and UES calculate the market-related value of plan assets using the fair value of plan assets on the measurement date. The UES pension plan was initially funded during 2004. TEP and UES’ pension plan asset allocations at December 31, 2005 and TEP’s pension plan asset allocations at December 31, 2004, by asset category are as follows:

	Plan Assets
	December 31,
	2005			2004
Asset Category
Equity Securities		68.00	%		68.25	%
Debt Securities		21.30	%		18.23	%
Real Estate		9.60	%		13.52	%
Other		1.10	%		-
Total		100.00	%		100.00	%

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TEP’s investment policy for the pension plans targets a range of exposure to the various asset classes surrounding the following allocations: equity securities 65%, debt securities 23% and real estate 12%. TEP rebalances the portfolio periodically when the portfolio allocation is not within the desired range of exposure. The plan seeks to provide returns in excess of the portfolio benchmark. The portfolio benchmark consists of the following indices: 55% Russell 3000; 10% MSCI EAFE; 23% Lehman Aggregate; and 12% NCREIF. A third party investment consultant tracks the plan’s portfolio relative to the benchmark and provides quarterly investment reviews which consist of a performance and risk assessment on all investment managers and on the portfolio.

Certain managers within the plan use, or have authorization to use, derivative financial instruments for risk management purposes or as a part of their investment strategy. Currency hedges have also been used for defensive purposes. Leverage is used by real estate managers but is limited by investment policy.

The policy for the UES pension plan is to provide exposures to equity and debt securities by investing in a balanced fund. As of December 31, 2005, the fund had approximately 63% of its assets invested in stocks and 37% in fixed income securities. The fund will hold no more than 75% of its total assets in stocks.

Pension Plan Contributions

TEP and UES expect to contribute $8 million and $1 million, respectively, to the pension plans in 2006.

Estimated Future Benefit Payments

The following benefit payments, which reflect future service, as appropriate, are expected to be paid:

	Pension Benefits		Other Benefits
	-Millions of Dollars-
2006	$	5	$	4
2007		6		4
2008		7		5
2009		8		5
2010		9		6
Years 2011-2015		64		34

DEFINED CONTRIBUTION PLANS

TEP and UES sponsor defined contribution savings plans that are offered to all eligible employees. Certain affiliate employees are also eligible to participate. The plans are qualified 401(k) plans under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Participants direct the investment of contributions to certain funds in their account. Matching contributions to participant accounts are made under these plans. Matching contributions to these plans were approximately $4 million in 2005 and 2004 and $3 million in 2003.

NOTE 16. SHARE-BASED COMPENSATION PLANS

At December 31, 2005, we had stock options, stock units and restricted stock grants outstanding as discussed below. Effective January 1, 2005, we adopted the new accounting guidance for share-based compensation. Prior to January 1, 2005, we accounted for those plans under the recognition and measurement principles of APB 25. See Note 1.

The Directors’ Plan provides for annual awards of non-qualified stock options and restricted shares or stock units to each eligible director. Under the Directors’ Plan, we are authorized to grant up to a total of 324,000 shares. The Omnibus Plan, which expired on February 3, 2004, allowed the Compensation Committee, a committee of

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non-employee directors, to grant the following types of awards to each eligible employee: stock options; stock appreciation rights; restricted stock; stock units; performance shares; and dividend equivalents. A total of 4.1 million shares were previously available under the Omnibus Plan provisions.

The terminated acquisition agreement between UniSource Energy and Saguaro Utility Group L.P. limited the amount of capital stock that UniSource Energy could issue under its stock plans in 2004. Additionally, both plans contain “Change in Control” provisions that provide for accelerated vesting of awards when certain conditions are met. A March 29, 2004 shareholder vote to approve the proposed merger triggered 100% vesting of all awards under the Omnibus Plan. The provision in the Directors’ Plan did not take effect as it requires consummation of a merger to accelerate vesting.

STOCK OPTIONS

In 2005, the Board of Directors granted options on 50,000 shares of UniSource Energy Common Stock as an employment inducement award to a new executive officer. The award was granted on the same basis as grants under the Omnibus Plan. The fair value of the option grant was estimated on the date of grant using the Black-Scholes option pricing model that uses the assumptions noted in the following table. Volatility is based on historical volatility of UniSource Energy stock. The expected life of options granted is derived from the simplified method provided by the Commission’s Office of the Chief Accountant and Division of Corporate Finance in Staff Accounting Bulletin No. 107, Share-Based Payment, and represents the period of time that options granted are expected to be outstanding. The interest rate is based on the U.S. Treasury Strip rate with a maturity equal to the expected term of the option at the option grant date. The dividend yield is calculated based on an average of the ratios of the last 3 dividend payments to the stock prices on the date of those payments.


Expected life (years)		6
Interest rate		4.00	%
Volatility		22.94	%
Dividend yield		2.54	%
Weighted-average grant-date fair value of option granted during the period	$	7.39

There were no additional stock options granted during 2005 and 2004. We granted stock options to key TEP and Millennium employees and members of the Board of Directors during 2003. Stock option awards vest over three years, become exercisable in one-third increments on each anniversary date of the grant and expire on the tenth anniversary of the grant. Historically, we have issued new shares to satisfy share option exercises.

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A summary of the stock option activity of the Directors’ Plan and Omnibus Plan is as follows:

	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Options Outstanding,
Beginning of Year		2,076,055		$	16.19		2,478,551		$	16.04		2,572,551		$	15.77
Granted		50,000		$	33.55		-			-		120,236		$	17.77
Exercised		(581,549	)	$	16.18		(400,003	)	$	15.29		(199,400	)	$	13.72
Forfeited		(7,465	)	$	17.87		(2,493	)	$	13.66		(14,836	)	$	14.20
Options Outstanding,
End of Year		1,537,041		$	16.75		2,076,055		$	16.19		2,478,551		$	16.04

Options Exercisable,
End of Year		1,479,569		$	16.18		2,053,784		$	16.17		1,676,803		$	15.27

Exercise Price Range of Options Outstanding at December 31, 2005: $11.00 to $33.55
Weighted Average Remaining Contractual Life at December 31, 2005:						4.97 years
Weighted Average Remaining Contractual Life of Fully Vested Shares at December 31, 2005:						4.94 years

Compensation expense of less than $0.1 million was recognized for the options issued in 2005. As discussed in Note 1, prior to January 1, 2005, we applied APB 25 in accounting for our stock option plans. We did not recognize any compensation expense for these options because our stock options were granted with an exercise price equal to the market value of the stock at the grant date. We previously adopted the disclosure-only provisions of FAS 123. We present, in Note 1, the effect on net income and earnings per share as if the company had applied the fair value recognition provisions of FAS 123.

Stock options awarded on January 1, 2002 accrue dividend equivalents that are paid in cash on the earlier of the date of exercise of the underlying option or the date the option expires. Compensation expense is recognized as dividends are declared. In 2005, 2004 and 2003, we recognized compensation expense of less than $1 million for dividend equivalents on stock option grants. No compensation costs associated with these awards were capitalized during the years ended December 31, 2005, 2004, and 2003.

A summary of the status of nonvested stock options as of December 31, 2005, and changes during the year then ended, is presented below:

Nonvested Shares	Shares			Weighted-Average Grant-Date Fair Value
Nonvested at January 1, 2005		22,271		$	3.31
Granted		50,000		$	7.39
Vested		(14,799	)	$	3.39
Forfeited		-			-
Nonvested at December 31, 2005		57,472		$	6.84

As of December 31, 2005, total unrecognized compensation cost related to nonvested stock options granted under the Plan was $0.3 million. That cost is expected to be recognized over a weighted-average period of 3 years. The total fair value of shares vested was less than $0.1 million during the year ended December 31, 2005 and was approximately $2 million during both of the years ended December 31, 2004 and 2003.

The actual tax benefit realized from the exercise of share-based payment arrangements totaled $3 million for 2005 and $1 million for both 2004 and 2003.

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RESTRICTED STOCK AND STOCK UNITS

In 2005, we granted restricted stock awards to directors totaling 15,465 shares at a grant date weighted-average fair value of $28.45 per share. In 2004 and 2003, we granted restricted stock awards to directors totaling 6,480 shares and 5,157 shares, respectively. The grant date fair value of the shares was $24.68 per share in 2004 and $17.44 per share in 2003. Directors may elect to receive stock units in lieu of restricted shares. Restricted shares or stock units granted prior to February 2005 become 100% vested on the third anniversary of the grant date. Restricted shares or stock units granted after February 1, 2005 become 100% vested on the first anniversary of the grant date. Compensation expense equal to the fair market value on the date of the award is recognized over the vesting period.

There were 1,012 stock unit awards granted to directors at a grant date weighted-average fair value of $32.36 during the year ended December 31, 2005. There were no stock unit awards granted during the year ended December 31, 2004. Fully vested but undistributed stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. Compensation expense is recognized when dividends are paid.

A summary of the status of nonvested restricted stock awards and stock unit awards as of December 31, 2005, and changes during the year then ended, is presented below:

Nonvested Units	Units			Weighted-Average Grant-Date Fair Value
Nonvested at January 1, 2005		9,154		$	22.56
Granted		16,477		$	28.69
Vested		(4,509	)	$	24.26
Forfeited		-			-
Nonvested at December 31, 2005		21,122		$	26.98

We recorded compensation expense for the awards described above of less than $1 million in 2005, 2004 and 2003. As of December 31, 2005, total unrecognized compensation cost related to nonvested restricted stock awards and stock unit awards granted was $0.3 million. That cost is expected to be recognized over the weighted-average period of approximately 1 year. The total fair value of restricted stock awards and stock unit awards vested during the years ended December 31, 2005 and 2004 was approximately $0.1 million and during the year ended December 31, 2003 was approximately $1 million.

PERFORMANCE SHARES

In May 2003, the Board of Directors approved a grant of performance shares to key employees under the Omnibus Plan. The shares were to be awarded at the end of a three-year performance period based on goal attainment. The grant date fair value was $17.84 per share. Compensation expense was initially recorded over the performance period based on the anticipated number and market value of shares to be awarded. As a result of the shareholder vote to approve the proposed merger, 53,566 performance shares vested and were distributed. Compensation expense of $2 million was recorded in 2004 and $1 million was recorded in 2003 for this award.

NOTE 17. 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. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options, contingently issuable shares under equity-based awards or common shares that would result from the conversion of convertible notes. The numerator in calculating diluted earnings per share is Net Income adjusted for the interest on convertible notes (net of tax) that would not be paid if the notes were converted to common shares.

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The following table shows the effects of potential dilutive common stock on the weighted average number of shares:

	Years Ended December 31,
	2005		2004		2003
	-In Thousands-
Numerator
Net Income	$	46,144	$	45,919	$	113,941
Income from Assumed Conversion of Convertible Senior Notes		3,654		-		-
Adjusted Numerator	$	49,798	$	45,919	$	113,941

Denominator:
Weighted-average Shares of Common Stock Outstanding		34,798		34,380		33,828
Effect of Diluted Securities
Convertible Senior Notes		3,345		-		-
Options and Stock Issuable under Employee Benefit Plans and the Directors’ Plan		708		661		511
Total Shares		38,851		35,041		34,339

There were no antidilutive options outstanding during the years ended December 31, 2005 or 2004. Options to purchase an average of 274,000 shares of Common Stock were outstanding during 2003 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.

NOTE 18. RELATED PARTIES

UniSource Energy incurs corporate costs that are allocated to TEP and its other affiliates. Certain corporate costs are directly assigned to TEP. Other corporate costs are allocated based on a weighted-average residual allocation factor. Management believes this method of allocation is reasonable and approximates the cost that TEP and its other affiliates would have incurred as stand-alone entities. Charges allocated to TEP were $5 million in 2005, $12 million in 2004 and $5 million in 2003.

TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UniSource Energy, UNS Gas and UNS Electric as well as to UniSource Energy’s non-utility businesses. Costs are directly assigned to the benefiting entity where possible. Common costs are allocated on a transaction-oriented basis. Management believes this method of allocation is reasonable. The charges by TEP were $8 million in 2005, $7 million in 2004 and $5 million in 2003.

Southwest Energy Solutions, Inc. (SES), a subsidiary of Millennium, provides a supplemental workforce for TEP. Types of services provided for TEP are dusk to dawn lighting, facilities maintenance, meter reading, solar work, transmission and distribution, and general supplemental support. SES bills TEP for providing these services. Management believes that the charges for services are reasonable and approximate the cost that TEP would have incurred if it performed these services directly. The charges to TEP for these services were $12 million in 2005, $13 million in 2004 and $8 million in 2003.

Haddington Energy Partners II, LP (Haddington) funds energy-related investments. A member of the UniSource Energy Board of Directors has an investment in Haddington and is a managing director of the general partner of the limited partnership. Millennium owns 31% of Haddington and accounts for this investment under the equity method.

Valley Ventures III, LP (Valley Ventures) is a venture capital fund that invests in information technology, microelectronics and biotechnology, primarily within the southwestern U.S. Another member of the UniSource Energy Board of Directors was a general partner of the company that manages the fund until January 1, 2006, at which time the Board member terminated his role and interest as a general partner but maintained a non-voting financial interest in the company. Millennium owns 15% of the fund and accounts for this investment under the

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equity method due to an ability to exercise significant influence over the fund based on the related party disclosure above.

Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas) is a Mexican limited liability company created to develop up to 800 megawatts (MW) of coal-fired generation in the Sabinas region of Coahuila, Mexico. Millennium owns 50% of Sabinas. Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and affiliates own the remaining 50%. UniSource Energy’s Chairman, President and Chief Executive Officer is a member of the board of directors of AHMSA. As of December 31, 2005, Millennium’s investment in Sabinas is approximately $14 million.

NOTE 19. SUBSEQUENT EVENT

In January 2006, UniSource Energy’s Board of Directors approved a plan to dispose of its investment in Global Solar to a third party. The sale is expected to be closed in the first half of 2006.

Listed below are the major classes of assets and liabilities as of December 31, 2005 related to the sale of Global Solar:

Assets	-Millions of Dollars-
Property, Plant and Equipment, net	$	10
Inventory		4
Income Tax Receivable - Current		4
Goodwill		3
Other Assets		2
Total Assets	$	23

Liabilities
Long-Term Debt	$	10
Other		5
Total Liabilities		15

Stockholder’s Equity
Investment in Global Solar		8
Total Liabilities & Stockholder’s Equity	$	23

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NOTE 20. SUPPLEMENTAL CASH FLOW INFORMATION

A reconciliation of net income to net cash flows from operating activities follows:

	UniSource Energy
	Years Ended December 31,
	2005			2004			2003
	-Thousands of Dollars-
Net Income	$	46,144		$	45,919		$	113,941
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Cumulative Effect of Accounting Change-Net of Tax		626			-			(67,471	)
Depreciation and Amortization Expense		135,556			135,315			130,643
Depreciation Recorded to Fuel and Other O&M Expense		6,496			6,175			6,230
Amortization of Transition Recovery Asset		56,418			50,153			31,752
Net Unrealized (Gain) Loss on TEP Forward Electric Sales		(604	)		(1,509	)		761
Net Unrealized Loss (Gain) on TEP Forward Electric Purchases		1,863			250			(378	)
Net Unrealized Gain on MEG Trading Activities		(10,764	)		(551	)		(1,046	)
Amortization of Deferred Debt-Related Costs included in
Interest Expense		4,730			3,423			2,972
Loss on Reacquired Debt		5,261			1,990			-
Provision for Bad Debts		2,696			2,821			4,820
Deferred Income Taxes		7,851			5,303			(3,002	)
(Gain) Loss from Equity Method Investment Entities		(2,387	)		(7,326	)		2,984
Gain on Sale of Real Estate		-			(725	)		(467	)
Other		(13,930	)		(10,981	)		46,052
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		894			(13,927	)		(18,622	)
Materials and Fuel Inventory		(7,604	)		(3,926	)		(7,412	)
Accounts Payable		5,034			29,531			(7,944	)
Interest Accrued		8,282			9,890			13,151
Taxes Accrued		11,612			15,684			10,353
Other Current Assets		53,621			(49,781	)		(7,011	)
Other Current Liabilities		(43,406	)		53,396			12,688
Other Deferred Credits and Other Liabilities		8,021			18,815			17,442
Deposit - 1992 Mortgage Indenture		-			17,040			(17,040	)
Net Cash Flows - Operating Activities	$	276,410		$	306,979		$	263,396

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	TEP
	Years Ended December 31,
	2005			2004			2003
	-Thousands of Dollars-

Net Income	$	48,267		$	46,127		$	128,913
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Cumulative Effect of Accounting Change-Net of Tax		626			-			(67,471	)
Depreciation and Amortization Expense		114,704			117,109			121,037
Depreciation Recorded to Fuel and Other O&M Expense		6,417			6,175			6,230
Amortization of Transition Recovery Asset		56,418			50,153			31,752
Net Unrealized (Gain) Loss on Forward Electric Sales		(604	)		(1,509	)		761
Net Unrealized Loss (Gain) on Forward Electric Purchases		1,863			250			(378	)
Amortization of Deferred Debt-Related Costs included in
Interest Expense		3,687			3,114			2,921
Loss on Reacquired Debt		5,261			1,990			-
Provision for Bad Debts		1,964			1,691			4,460
Deferred Income Taxes		6,555			(1,011	)		1,136
(Gains) Losses from Equity Method Investment Entities		(338	)		(168	)		(142	)
Interest Accrued on Note Receivable from UniSource Energy		(1,684	)		(9,329	)		(10,242	)
Gain on Sale of Real Estate		-			(725	)		(467	)
Other		(10,932	)		(3,219	)		15,927
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(6,779	)		(23,774	)		(8,717	)
Materials and Fuel Inventory		(6,608	)		(1,100	)		(5,607	)
Accounts Payable		3,804			24,958			8,225
Interest Accrued		5,295			10,264			9,005
Interest Received from UniSource Energy		11,013			-			19,571
Income Taxes Payable		(704	)		6,728			(3,274	)
Taxes Accrued		137			13,303			4,555
Other Current Assets		(676	)		(5,328	)		581
Other Current Liabilities		(1,835	)		4,790			1,468
Other Deferred Credits and Other Liabilities		7,162			17,622			17,785
Deposit - 1992 Mortgage Indenture		-			17,040			(17,040	)
Net Cash Flows - Operating Activities	$	243,013		$	275,151		$	260,989

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,
	2005		2004		2003
	-Thousands of Dollars-

Capital Lease Obligations	$	12,720	$	12,273	$	10,731
Preliminary Engineering Fees		3,691		-		-

The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments in 2005, 2004, and 2003.

The non-cash preliminary engineering fees represent costs incurred related to potential capital projects that are recorded in other assets and subsequently reclassified to construction work in progress upon affirmation the capital project will be undertaken.

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On August 11, 2003, UniSource Energy acquired the Arizona gas and electric system assets from Citizens for $223 million, comprised of the base purchase price plus other operating capital adjustments and transaction costs. In conjunction with the acquisition, liabilities were assumed as follows:

	-Thousands of Dollars -

Fair Value of Assets Acquired	$	262,044
Liabilities Assumed		38,648
Assets/Liabilities Purchased	$	223,396

Cash Paid for Citizens Assets	$	218,558
Transaction Costs		4,838
Total Purchase Price	$	223,396

NOTE 21. QUARTERLY FINANCIAL DATA (UNAUDITED)

Our quarterly financial information has not been audited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature with peak sales periods for TEP and UNS Electric generally occurring during the summer months and peak sales periods for UNS Gas generally occurring during the winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

	UniSource Energy
	First			Second		Third		Fourth
	-Thousands of Dollars- (except per share data)
2005

Operating Revenue	$	260,929		$	300,592	$	349,252	$	318,762
Operating Income		29,929			54,594		59,508		66,927
Income (Loss) Before Cumulative Effect of Accounting Change		(3,783	)		9,468		18,397		22,688
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(626	)
Net Income		(3,783	)		9,468		18,397		22,062
Basic EPS
Income (Loss) Before Cumulative Effect of Accounting Change		(0.11	)		0.27		0.53		0.65
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(0.02	)
Net Income		(0.11	)		0.27		0.53		0.63
Diluted EPS
Income (Loss) Before Cumulative Effect of Accounting Change		(0.11	)		0.27		0.49		0.60
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(0.02	)
Net Income		(0.11	)		0.27		0.49		0.58

2004

Operating Revenue	$	270,084		$	290,081	$	335,309	$	273,504
Operating Income		42,710			61,571		75,461		39,648
Net Income		6,421			12,801		23,799		2,898
Basic EPS		0.19			0.37		0.69		0.08
Diluted EPS		0.18			0.37		0.68		0.08

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	TEP
	First			Second		Third		Fourth
	-Thousands of Dollars-
2005

Operating Revenue	$	181,906		$	236,879	$	282,234	$	236,451
Operating Income		23,121			54,125		58,874		63,221

Interest Income - Note Receivable from UniSource Energy		1,684			-		-		-

Income (Loss) Before Cumulative Effect of Accounting Change		(4,690	)		12,148		20,364		21,071
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(626	)
Net Income		(4,690	)		12,148		20,364		20,445

2004

Operating Revenues	$	186,974	$	233,742	$	272,085	$	196,497
Operating Income		35,688		62,269		74,531		34,196

Interest Income - Note Receivable from UniSource Energy		2,320		2,319		2,345		2,345

Net Income		794		18,017		26,222		1,094

EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.

The principal unusual items for TEP and UniSource Energy include:

TEP and UniSource Energy

·	Fourth Quarter 2005: TEP recognized a pre-tax gain of $6 million, which is recorded as an offset to Other Operations and Maintenance expense, for its sale of 5,000 excess SO₂ allowances.

Third Quarter 2005: TEP recognized a pre-tax gain of $4 million, which is recorded as an offset to Other Operations and Maintenance expense, for its sale of 5,000 excess SO₂allowances. TEP recognized a $1 million income tax benefit due to anticipated use of previously reserved ITC carryforwards.

Fourth Quarter 2004: UniSource Energy recorded a $7 million pre-tax acquisition termination fee of which 77% was allocated to TEP. UniSource Energy recognized a current income tax benefit of $1 million as a result of deducting certain acquisition-related legal and advisory fees that had previously been treated as permanently nondeductible expenses, 77% of which was recognized by TEP. TEP recognized a $1 million income tax expense due to the uncertainty of future use of certain ITC carryforwards. See Note 14.

UniSource Energy

Fourth Quarter 2005: MEH recognized a $4 million pre-tax gain from the sale of WHP, a Haddington investment and MEH recognized a $2 million impairment loss upon sale of its MicroSat investment. UES collected $1 million of previously fully reserved accounts receivable related to amounts owed from Citizens in relation to the 2003 Citizens purchase. UES recognized a $1 million pre-tax gain in non-operating income for this collection.

·	First Quarter 2004: MEH recognized a $3 million after-tax gain from the sale of Sago Energy, LP’s operating subsidiaries, a Haddington investment.

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UniSource Energy

Schedule II - Valuation and Qualifying Accounts

Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
Year Ended December 31,	-Millions of Dollars-

Deferred Tax Assets Valuation Allowance ⁽¹⁾
2005	$	8	$	-	$	1	$	7
2004		7		1		-		8
2003		22		-		15		7

Allowance for Doubtful Accounts ⁽²⁾
2005	$	17	$	3	$	5	$	15
2004		12		7		2		17
2003		9		5		2		12

⁽¹⁾The deferred tax assets valuation allowance reduces the deferred tax asset balance. It relates to NOL and ITC carryforward amounts. The decrease in 2005 of $1 million is related to TEP’s anticipated utilization of ITC carryforward. Of the $7 million valuation allowance at December 31, 2005, $7 million relates to losses generated by the Millennium entities. UniSource, TEP and Subsidiaries charged $1 million to income in 2004 related to TEP’s ITC carryforwards that may expire prior to utilization. UniSource, TEP and Subsidiaries reduced the deferred tax asset valuation allowance in 2003 primarily based on guidance issued by the Internal Revenue Service in September, 2003 (see Note 14 of Notes to Consolidated Financial Statements).

⁽²⁾TEP and UES record additions to the Allowance for Doubtful accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Balances related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001. See Note 12 of Notes to Consolidated Financial Statements.

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TEP

Schedule II - Valuation and Qualifying Accounts

Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
Year Ended December 31,	-Millions of Dollars-

Deferred Tax Assets Valuation Allowance ⁽¹⁾
2005	$	1	$	-	$	1	$	-
2004		-		1		-		1
2003		15		-		15		-

Allowance for Doubtful Accounts ⁽²⁾
2005	$	14	$	2	$	1	$	15
2004		11		5		2		14
2003		9		5		3		11

⁽¹⁾The deferred tax assets valuation allowance reduces the deferred tax asset balance. It relates to NOL and ITC carryforward amounts. The 2005 reduction of $1 million related to TEP’s anticipated utilization of ITC carryforwards. TEP charged $1 million to income in 2004 related to ITC carryforwards that may expire prior to utilization. TEP reduced the deferred tax assets valuation in 2003 primarily based on guidance issued by the Internal Revenue Service in September, 2003 (see Note 14 of Notes to Consolidated Financial Statements).

⁽²⁾TEP recorded $7 million of expenses 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. In the first quarter of 2003, TEP increased its reserve for sales to the CPX and the CISO by $2 million by recording a reduction of wholesale revenues. In the second quarter of 2004, TEP increased its reserve for sales to the CPX and the CISO by an additional $3 million based on new FERC orders.Deductions principally reflect amounts charged off as uncollectible, less amounts recovered (see Note 12 of Notes to Consolidated Financial Statements). No large or unusual allowances were recorded or written off during the year ended December 31, 2005.

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Reference is made to the Exhibit Index commencing on page 150.

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SIGNATURES

Pursuant to the requirements of Section 13 and 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 3, 2006	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior 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 3, 2006		/s/ James S. Pignatelli*
		James S. Pignatelli
		Chairman of the Board, President and Principal Executive Officer


Date: March 3, 2006		/s/ Kevin P. Larson
		Kevin P. Larson
		Principal Financial Officer


Date: March 3, 2006		/s/ Karen G. Kissinger*
		Karen G. Kissinger
		Principal Accounting Officer


Date: March 3, 2006		/s/ Lawrence J. Aldrich*
		Lawrence J. Aldrich
		Director


Date: March 3, 2006		/s/ Barbara Baumann*
		Barbara Baumann
		Director


Date: March 3, 2006		/s/ Larry W. Bickle*
		Larry W. Bickle
		Director


Date: March 3, 2006		/s/ Elizabeth T. Bilby*
		Elizabeth T. Bilby
		Director


Date: March 3, 2006		/s/ Harold W. Burlingame*
		Harold W. Burlingame
		Director


Date: March 3, 2006		/s/ John L. Carter*
		John L. Carter
		Director

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Date: March 3, 2006		/s/ Robert A. Elliott*
		Robert A. Elliott
		Director


Date: March 3, 2006		/s/ Daniel W.L. Fessler*
		Daniel W.L. Fessler


Date: March 3, 2006		/s/ Kenneth Handy*
		Kenneth Handy
		Director


Date: March 3, 2006		/s/ Warren Y. Jobe*
		Warren Y. Jobe
		Director


Date: March 3, 2006		/s/ Joaquin Ruiz*
		Joaquin Ruiz
		Director


Date: March 3, 2006	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

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SIGNATURES


	TUCSON ELECTRIC POWER COMPANY

Date: March 3, 2006	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Principal Financial Officer


Date: March 3, 2006		/s/ James S. Pignatelli*
		James S. Pignatelli
		Chairman of the Board, President and Principal Executive Officer


Date: March 3, 2006		/s/ Kevin P. Larson
		Kevin P. Larson
		Principal Financial Officer


Date: March 3, 2006		/s/ Karen G. Kissinger*
		Karen G. Kissinger
		Principal Accounting Officer


Date: March 3, 2006		/s/ Lawrence J. Aldrich*
		Lawrence J. Aldrich
		Director


Date: March 3, 2006		/s/ Barbara Baumann*
		Barbara Baumann
		Director


Date: March 3, 2006		/s/ Larry W. Bickle*
		Larry W. Bickle
		Director


Date: March 3, 2006		/s/ Elizabeth T. Bilby*
		Elizabeth T. Bilby
		Director


Date: March 3, 2006		/s/ Harold W. Burlingame*
		Harold W. Burlingame
		Director


Date: March 3, 2006		/s/ John L. Carter*
		John L. Carter
		Director

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Date: March 3, 2006		/s/ Robert A. Elliott*
		Robert A. Elliott
		Director


Date: March 3, 2006		/s/ Daniel W.L. Fessler*
		Daniel W.L. Fessler


Date: March 3, 2006		/s/ Kenneth Handy*
		Kenneth Handy
		Director


Date: March 3, 2006		/s/ Warren Y. Jobe*
		Warren Y. Jobe
		Director


Date: March 3, 2006		/s/ Joaquin Ruiz*
		Joaquin Ruiz
		Director


Date: March 3, 2006	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

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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 our 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)	--	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(a)(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(a)(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(a)(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(b)(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 Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(a).)
*4(b)(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 Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(b).)
*4(b)(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 Sundt Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(3).)
*4(b)(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 Sundt Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(4).)
*4(c)(1)	--	Loan Agreement, dated as of December 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(1).)

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*4(c)(2)	--	Indenture of Trust dated as of December 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(2).)
*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 Projects). (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(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 Projects). (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(4).)
*4(d)(1)	--	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(I)(1).)
*4(d)(2)	--	Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File no. 1-5924 -- Exhibit 4(I)(2).)
*4(d)(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(d)(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(d)(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(d)(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(e)(1)	--	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(1).)
*4(e)(2)	--	Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds. 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(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 Developmental 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(I)(3).)

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*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 B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(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 B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(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 B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(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 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(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 C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(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 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(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 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(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 C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(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 C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(6).)
*4(g)	--	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(h)(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(h)(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,

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		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(h)(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(h)(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(i)(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(i)(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(i)(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(i)(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(i)(5)	--	Supplemental Indenture No. 4 creating a series of bonds designated Second Mortgage Bonds, Collateral Series C, dated as of November 1, 2002. (Form 8-K dated November 27, 2002, File Nos. 1-05924 and 1-13739 -- Exhibit 99.2.)
*4(i)(6)	--	Supplemental Indenture No. 5 creating a series of bonds designated Second Mortgage Bonds, Collateral Series D, dated as of March 1, 2004. (Form 8-K dated March 31, 2004, File Nos. 1-05924 and 1-13739 -- Exhibit 10 (b).)
*4(i)(7)	--	Supplemental Indenture No. 6 creating a series of bonds designated Second Mortgage Bonds, Collateral Series E, dated as of May 1, 2005. (Form 10-Q for the quarter ended March 31, 2005, File Nos. 1-5924 and 1-13739 - Exhibit 4(b).)
*4(j)(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(j)(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(k)(1)	--	Loan Agreement, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series 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(k)(2)	--	Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(f).)

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*4(l)(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(l)(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(m)(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(m)(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(n)(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(n)(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(o)(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(o)(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(p)(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(q)(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.)
*4(r)(1)	--	TEP Credit Agreement dated as of May 1, 2005, among TEP, the Lenders Party Thereto, the Issuing Banks Party Thereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, and Allied Irish Banks, P.L.C., as Documentation Agent. (Form 8-K dated March 31, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4(a).)
*4(s)(1)	--	Note Purchase and Guaranty Agreement dated August 11, 2003 among UNS Gas, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.2.)

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*4(t)(1)	--	Note Purchase and Guaranty Agreement date August 11, 2003 among UNS Electric, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.3.)
*4(u)(1)	--	Indenture dated as of March 1, 2005, to The Bank of New York, as Trustee. (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.1).
*4(v)(1)	--	Registration Rights Agreement dated as of March 1, 2005, between UniSource Energy Corporation and Credit Suisse First Boston LLC, as representative of the several initial purchasers. (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.2).
*4(w)(1)	--	Credit Agreement dated as of April 15, 2005, among UniSource Energy, the Lenders Party Hereto, The Bank of new York, as Syndication Agent, Commerzbank AG, New York and Grand Cayman Branches, as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent and Lead Arranger. (Form 8-K dated April 18, 2005, File Nos. 1-5924 and 1-1339 - Exhibit 4.1).
*4(x)(1)	--	Credit Agreement dated as of April 15, 2005, among UNS Electric and UNS Gas, UniSource Energy Services as Guarantor, and the Banks Named Herein and the Other Lenders from Time to Time party Hereto, The Bank of New York, as Syndication Agent, Wells Fargo Bank, National Association, as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent and Lead Arranger. (Form 8-K dated April 18, 2005, File Nos. 1-5924 and 1-1339 - Exhibit 4.2 and 4.3).
*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

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		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 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 Hubbell Financial, Inc. and JC 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

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		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

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		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 Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860 -- 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

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		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(b)(14)	--	Amendment No. 3 dated as of June 1, 2003, 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, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant.
*10(b)(15)	--	Amendment No. 3 dated as of June 1, 2003, 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, under a Trust Agreement with IBM Credit, LLC as Owner Participant.
*10(b)(16)	--	Amendment No. 3 dated as of June 1, 2003, 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, under a Trust Agreement with Emerson Finance Co. as Owner Participant.
*10(b)(17)	--	Amendment No. 3 dated as of June 1, 2003, 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.
*10(b)(18)	--	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit, LLC 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.

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*10(b)(19)	--	Amendment No. 3 dated as of June 1, 2003, 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.
*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 Sundt 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 Sundt 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 10-K 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

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		Project. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(l)(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 Sundt 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)	--	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(e)	--	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(f)	--	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(g)	--	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(h)	--	1994 Omnibus Stock and Incentive Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43767.)
+*10(i)	--	Management and Directors Deferred Compensation Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43769.)
+*10(j)	--	TEP Supplemental Retirement Account for Classified Employees. (Form S-8 dated May 21, 1998, File No. 333-53309.)
+*10(k)	--	TEP Triple Investment Plan for Salaried Employees. (Form S-8 dated May 21, 1998, File No. 333-53333.)
+*10(l)	--	UniSource Energy Management and Directors Deferred Compensation Plan. (Form S-8 dated May 21, 1998, File No. 333-53337.)
+10(m)	--	Officer Change in Control Agreement between TEP and Karen G. Kissinger, dated as of December 4, 1998 (including a schedule of other officers who are covered by substantially identical agreements.)

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+10(n)	--	Notice of Termination of Change in Control Agreement from TEP to Karen G. Kissinger, dated as of March 3, 2005 (including a schedule of other officers who received substantially identical notices.)
+*10(o)	--	Amended and Restated UniSource Energy 1994 Outside Director Stock Option Plan of UniSource Energy. (Form S-8 dated September 9, 2002, File No. 333-99317.)
*10(p)(1)	--	Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens Communications Company relating to the Purchase of Citizens’ Electric Utility Business in the State of Arizona. (Form 8-K dated October 31, 2002. File No. 1-13739 -- Exhibit 99-1.)
*10(p)(2)	--	Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens Communications Company relating to the Purchase of Citizens’ Gas Utility Business in the State of Arizona. (Form 8-K dated October 31, 2002. File No. 1-13739 -- Exhibit 99-2.)
12(a)	--	Computation of Ratio of Earnings to Fixed Charges - TEP.
12(b)	--	Computation of Ratio of Earnings to Fixed Charges - UniSource Energy.
21	--	Subsidiaries of the Registrants.
23	--	Consents of experts.
24(a)	--	Power of Attorney - UniSource Energy.
24(b)	--	Power of Attorney - TEP.
31(a)	--	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - UniSource Energy, by James S. Pignatelli.
31(b)	--	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - UniSource Energy by Kevin P. Larson.
31(c)	--	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - TEP, by James S. Pignatelli.
31(d)	--	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - TEP, by Kevin P. Larson.
**32	--	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).

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Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification Number

1-13739	UNISOURCE ENERGY CORPORATION (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000	86-0786732

1-5924	TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000	86-0062700

Securities registered pursuant to Section 12(b) of the Act:
Registrant	Title of Each Class	Name of Each Exchange on Which Registered

UniSource Energy Corporation	Common Stock, no par value and Preferred Share Purchase Rights	New York Stock Exchange Pacific Exchange

Note 19. Subsequent Event	147
Note 20. Supplemental Cash Flow Information	148
Note 21. Quarterly Financial Data (Unaudited)	150

Schedules II - Valuation and Qualifying Accounts	152

Item 9. - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	154

Item 9A. - Controls and Procedures	154

Item 9B. - Other Information	154

-- PART III --

Item 10. - Directors and Executive Officers of the Registrants	155

Item 11. - Executive Compensation	157

Item 12. - Security Ownership of Certain Beneficial Owners and Management	158

Item 13. - Certain Relationships and Related Transactions	158

Item 14. - Principal Accountant Fees and Services	158

-- PART IV --

Item 15. - Exhibits and Financial Statements Schedules	159
Signatures	160
Exhibit Index	164

1941 Mortgage	TEP’s Indenture, dated as of April 1, 1941, to JPMorgan Chase Bank, successor trustee, as supplemented and amended, which was satisfied and discharged on June 10, 2005.
1941 Mortgage Bonds	Bonds issued under the 1941 Mortgage.
1992 Mortgage	TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York, successor trustee, as supplemented.
1992 Mortgage Bonds	Bonds issued under the 1992 Mortgage.
ACC	Arizona Corporation Commission.
ACC Holding Company Order	The order approved by the ACC in November 1997 allowing TEP to form a holding company.
AHMSA	Altos Hornos de Mexico, S.A. de C.V. AHMSA owns 50% of Sabinas.
AMT	Alternative Minimum Tax.
APS	Arizona Public Service Company.
Bcf	Billion cubic feet.
Btu	British thermal unit(s).
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.
Citizens	Citizens Communications Company.
Citizens Settlement Agreement	An agreement with the ACC Staff dated April 1, 2003, addressing rate case and financing issues in the acquisition by UniSource Energy of the Citizens’ Arizona gas and electric assets.
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.
Common Stock	UniSource Energy’s common stock, without par value.
Company or UniSource Energy	UniSource Energy Corporation.
Cooling Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures.
Emission Allowance(s)	An allowance issued by the Environmental Protection Agency which permits emission of one ton of sulfur dioxide or one ton of nitrogen oxide. These allowances can be bought and 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, as amended.
FAS 143	Statement of Financial Accounting Standards No. 143: Accounting for Asset Retirement Obligations.
FERC	Federal Energy Regulatory Commission.
Four Corners	Four Corners Generating Station.
Global Solar	Global Solar Energy, Inc., a company that develops and manufactures thin-film photovoltaic cells. Millennium owns 99% of Global Solar.
Haddington	Haddington Energy Partners II, LP, a limited partnership that funds energy-related investments.
Heating Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65.
IDBs	Industrial development revenue or pollution control revenue bonds.
IPS	Infinite Power Solutions, Inc., a company that develops thin-film batteries. Millennium owns 31.4% of IPS.

IRS	Internal Revenue Service.
ISO	Independent System Operator.
ITC	Investment Tax Credit.
kWh	Kilowatt-hour(s).
kV	Kilovolt(s).
LIBOR	London Interbank Offered Rate.
LOC	Letter of Credit.
Luna	Luna Energy Facility.
MEG	Millennium Environment Group, Inc., a wholly-owned subsidiary of Millennium, which manages and trades emission allowances and related financial instruments.
MicroSat	MicroSat Systems, Inc. is a company formed to develop and commercialize small-scale satellites. Millennium currently owns 35%.
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy.
Mimosa	Minerales de Monclova, S.A. de C.V., an owner of coal and associated gas reserves and a supplier of metallurgical coal to the steel industry and thermal coal to the Mexican electricity commission. Sabinas owns 19.5% of Mimosa.
MMBtus	Million British Thermal Units.
MW	Megawatt(s).
MWh	Megawatt-hour(s).
Navajo	Navajo Generating Station.
NOL	Net Operating Loss carryback or carryforward for income tax purposes.
PGA	Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers.
PNM	Public Service Company of New Mexico.
PNMR	PNM Resources.
Powertrusion	POWERTRUSION International, Inc., a company owned 77% by Millennium, which manufactures lightweight utility poles.
PPFAC	Purchased Power and Fuel Adjustment Clause.
PWCC	Pinnacle West Capital Corporation.
Repurchased Bonds	$221 million of fixed-rate tax-exempt bonds that TEP purchased from bondholders on May 11, 2005.
RTO	Regional Transmission Organization.
Rules	Retail Electric Competition Rules.
Sabinas	Carboelectrica Sabinas, S. de R.L. de C.V., a Mexican limited liability company. Millennium owns 50% of Sabinas.
San Carlos	San Carlos Resources Inc., a wholly-owned subsidiary of TEP.
San Juan	San Juan Generating Station.
Sempra	Sempra Energy Trading Company.
SES	Southwest Energy Solutions, Inc., a wholly-owned subsidiary of Millennium.
Settlement Agreement	TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for electric retail competition and transition asset recovery.
Springerville	Springerville Generating Station.
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.

Definitions	vi

-- PART I --

Item 1. - Business	1
Overview of Consolidated Business	1
TEP Electric Utility Operations	2
Service Area and Customers	2
Generating and Other Resources	4
Fuel Supply	7
Water Supply	8
Transmission Access	8
Rates and Regulation	9
TEP’s Utility Operating Statistics	11
Environmental Matters	12
UNS Gas	13
Service Territory and Customers	13
Gas Supply and Transmission	13
Rates and Regulation	14
Environmental Matters	15
UNS Electric	15
Service Territory and Customers	15
Power Supply and Transmission	15
Rates and Regulation	15
Environmental Matters	16
Global Solar Energy, Inc.	16
Other	16
Employees	17
SEC Reports Available on UniSource Energy’s Website	17

Item 1A. - Risk Factors	18

Item 2. - Properties	22
TEP Properties	22
UES Properties	23
Global Solar Properties	24

Item 3. - Legal Proceedings	24

Item 4. - Submission of Matters to a Vote of Security Holders	24

-- PART II --

Item 5. - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity	25

Item 6. - Selected Consolidated Financial Data	26
UniSource Energy	26
TEP	27
Non-GAAP Measures	28

Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
UniSource Energy Consolidated	31
Outlook and Strategies	31
Results of Operations	32
Contribution by Business Segment	33

Liquidity and Capital Resources	35
Tucson Electric Power Company	41
Results of Operations	41
Factors Affecting Results of Operations	45
Liquidity and Capital Resources	50
UNS Gas	57
Results of Operations	57
Factors Affecting Results of Operations	59
Liquidity and Capital Resources	60
UNS Electric	62
Results of Operations	62
Factors Affecting Results of Operations	63
Liquidity and Capital Resources	63
Global Solar Energy, Inc.	65
Results of Operations	65
Other	66
Results of Operations	66
Factors Affecting Results of Operations	67
Liquidity and Capital Resources	67
Critical Accounting Estimates	68
New Accounting Pronouncements	74
Safe Harbor for Forward-Looking Statements	75

Item 7A. - Quantitative and Qualitative Disclosures about Market Risk	76

Item 8. - Consolidated Financial Statements and Supplementary Data	80
Management’s Report on Internal Controls Over Financial Reporting	80
Reports of Independent Registered Public Accounting Firm	81
UniSource Energy Corporation
Consolidated Statements of Income	84
Consolidated Statements of Cash Flows	85
Consolidated Balance Sheets	86
Consolidated Statements of Capitalization	87
Consolidated Statements of Changes in Stockholders’ Equity	88
Tucson Electric Power Company
Consolidated Statements of Income	89
Consolidated Statements of Cash Flows	90
Consolidated Balance Sheets	91
Consolidated Statements of Capitalization	92
Consolidated Statements of Changes in Stockholders’ Equity	93
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies	94
Note 2. Regulatory Matters	103
Note 3. Accounting Change: Accounting for Asset Retirement Obligations	110
Note 4. Segment and Related Information	113
Note 5. Accounting for Derivative Instruments, Trading Activities and Hedging Activities	116
Note 6. Commitments and Contingencies	118
Note 7. Utility Plant and Jointly-Owned Facilities	123
Note 8. Credit Facilities	125
Note 9. Debt and Capital Lease Obligations	127
Note 10. Fair Value of Financial Instruments	131
Note 11. Stockholders’ Equity	132
Note 12. TEP Wholesale Accounts Receivable and Allowances	133
Note 13. Springerville Expansion	133
Note 14. Income and Other Taxes	134
Note 15. Employee Benefit Plans	138
Note 16. Share-Based Compensation Plans	142
Note 17. UniSource Energy Earnings Per Share (EPS)	145
Note 18. Related Parties	146

SRP	Salt River Project Agricultural Improvement and Power District.
Sundt	H. Wilson Sundt Generating Station (formerly known as the Irvington Generating Station).
Sundt Lease	The leveraged lease arrangement relating to Sundt Unit 4.
SWG	Southwest Gas Corporation.
TEP	Tucson Electric Power Company, the principal subsidiary of UniSource Energy.
TEP Credit Agreement	Credit Agreement between TEP and a syndicate of banks, dated as of May 4, 2005.
TEP Revolving Credit Facility	$60 million revolving credit facility entered into under the TEP Credit Agreement, dated as of May 4, 2005, between a syndicate of banks and TEP.
Therm	A unit of heating value equivalent to 100,000 British thermal units (Btu).
Tri-State	Tri-State Generation and Transmission Association.
UED	UniSource Energy Development Company, a wholly-owned subsidiary of UniSource Energy, which engages in developing generation resources and other project development services and related activities.
UES	UniSource Energy Services, Inc., an intermediate holding company established to own the operating companies (UNS Gas and UNS Electric) which acquired the Citizens Arizona gas and electric utility assets in 2003.
UES Settlement Agreement	An agreement with the ACC Staff dated April 1, 2003, addressing rate case and financing issues in the acquisition by UniSource Energy of Citizens’ Arizona gas and electric assets.
UniSource Credit Agreement	Credit Agreement between UniSource Energy and a syndicate of banks, dated as of April 15, 2005.
UniSource Energy	UniSource Energy Corporation.
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens Arizona electric utility assets in 2003.
UNS Gas	UNS Gas, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens Arizona gas utility assets in 2003.
Valencia	Valencia power plant owned by UNS Electric.

							TEP’s Share
Generating Source	Unit No.	Location	Date In Service	Fuel Type	Net Capability MW	Operating Agent	%	MW
Springerville Station⁽¹⁾	1	Springerville, AZ	1985	Coal	380	TEP	100.0	380
Springerville Station	2	Springerville, AZ	1990	Coal	380	TEP	100.0	380
San Juan Station	1	Farmington, NM	1973	Coal	327	PNM	50.0	164
San Juan Station	2	Farmington, NM	1980	Coal	316	PNM	50.0	158
Navajo Station	1	Page, AZ	1974	Coal	750	SRP	7.5	56
Navajo Station	2	Page, AZ	1975	Coal	750	SRP	7.5	56
Navajo Station	3	Page, AZ	1976	Coal	750	SRP	7.5	56
Four Corners Station	4	Farmington, NM	1969	Coal	784	APS	7.0	55
Four Corners Station	5	Farmington, NM	1970	Coal	784	APS	7.0	55
Sundt Station	1	Tucson, AZ	1958	Gas/Oil	81	TEP	100.0	81
Sundt Station	2	Tucson, AZ	1960	Gas/Oil	81	TEP	100.0	81
Sundt Station	3	Tucson, AZ	1962	Gas/Oil	104	TEP	100.0	104
Sundt Station⁽¹⁾	4	Tucson, AZ	1967	Coal/Gas	156	TEP	100.0	156
Internal Combustion Turbines		Tucson, AZ	1972	Gas/Oil	122	TEP	100.0	122
Internal Combustion Turbines		Tucson, AZ	2001	Gas	95	TEP	100.0	95
Solar Electric Generation		Springerville/ Tucson, AZ	2002-2005	Solar	5	TEP	100.0	5
Total TEP Capacity ⁽²⁾								2,004

Peak Demand	2005			2004			2003			2002			2001
	-MW-
Retail Customers - Net One Hour		2,225			2,088			2,060			1,899			1,840
Firm Sales to Other Utilities		342			187			171			228			151
Coincident Peak Demand (A)		2,567			2,275			2,231			2,127			1,991

Total Generating Resources		2,004			2,004			2,003			2,002			1,999
Other Resources ⁽¹⁾		788			454			486			308			217
Total TEP Resources (B)		2,792			2,458			2,489			2,310			2,216

Total Margin (B) - (A)		225			183			258			183			225
Reserve Margin (% of Coincident Peak Demand)		9	%		8	%		12	%		9	%		11	%

	Average Cost per MMBtu						Percentage of Total Btu
			Consumed							Consumed
	2005		2004		2003		2005			2004			2003
Coal	$	1.69	$	1.57	$	1.58		96	%		96	%		96	%
Gas	$	8.10	$	6.75	$	6.38		4	%		4	%		4	%
All Fuels	$	1.93	$	1.79	$	1.79		100	%		100	%		100	%

Station	Coal Supplier	Year Contract Terminates	Average Sulfur Content	Coal Obtained From (A)
Springerville	Peabody Coalsales Company	2020	0.9%	Lee Ranch Coal Company
Four Corners	BHP Billiton	2016	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
Sundt	Various approved suppliers	2006	-	Various locations

	For Years Ended December 31,
	2005		2004		2003		2002		2001
Generation and Purchased Power - kWh (000)
Remote Generation (Coal)		10,059,315		10,159,729		10,182,706		10,067,069		10,362,211
Local Tucson Generation (Oil, Gas & Coal)		1,165,001		1,174,500		1,082,058		1,402,504		1,820,783
Purchased Power		1,638,737		1,322,084		1,153,305		1,329,574		3,656,978
Total Generation and Purchased Power		12,863,053		12,656,313		12,418,069		12,799,147		15,839,972
Less Losses and Company Use		806,168		821,008		778,285		791,852		747,941
Total Energy Sold		12,056,885		11,835,305		11,639,784		12,007,295		15,092,031

Sales - kWh (000)
Residential		3,633,226		3,459,750		3,389,744		3,181,030		3,159,504
Commercial		1,855,432		1,787,472		1,689,014		1,605,148		1,591,942
Industrial		2,302,327		2,226,314		2,245,340		2,254,174		2,297,476
Mining		842,881		829,028		701,638		692,448		1,053,152
Public Authorities		241,119		240,426		250,038		256,867		257,155
Total - Electric Retail Sales		8,874,985		8,542,990		8,275,774		7,989,667		8,359,229
Electric Wholesale Sales		3,181,900		3,292,315		3,364,010		4,017,628		6,732,802
Total Electric Sales		12,056,885		11,835,305		11,639,784		12,007,295		15,092,031

Operating Revenues (000)
Residential	$	330,614	$	315,402	$	309,807	$	291,390	$	285,808
Commercial		192,966		186,625		175,559		168,838		166,139
Industrial		165,988		161,338		160,276		161,749		162,523
Mining		39,749		38,549		28,022		28,072		41,940
Public Authorities		17,559		17,427		17,839		18,672		18,763
Total - Electric Retail Sales		746,876		719,341		691,503		668,721		675,173
Electric Wholesale Sales		178,428		159,918		151,030		157,108		921,280
Other Revenues		12,166		10,039		9,018		8,618		8,508
Total Operating Revenues	$	937,470	$	889,298	$	851,551	$	834,447	$	1,604,961

Customers (End of Period)
Residential		350,628		341,870		334,131		326,847		318,976
Commercial		33,534		32,923		32,369		31,767		31,194
Industrial		673		676		676		695		705
Mining		2		2		2		2		2
Public Authorities		61		61		61		61		61
Total Retail Customers		384,898		375,532		367,239		359,372		350,938

Average Retail Revenue per kWh Sold (cents)
Residential		9.1		9.1		9.1		9.2		9.0
Commercial		10.4		10.4		10.4		10.5		10.4
Industrial and Mining		6.5		6.5		6.4		6.4		6.1
Average Retail Revenue per kWh Sold		8.4		8.4		8.4		8.4		8.1

Average Revenue per Residential Customer	$	954	$	933	$	937	$	902	$	906
Average kWh Sales per Residential Customer		10,484		10,231		10,249		9,842		10,015

Period	Hedged Amount
April 2006 - October 2006	34%
November 2006 - March 2007	28%
April 2007 - October 2007	18%
November 2007 - March 2008	13%


	2005						2004
Quarter:	Market Price per Share of Common Stock ⁽¹⁾				Dividends Declared		Market Price per Share of Common Stock ⁽¹⁾				Dividends Declared
	High		Low				High		Low

First	$	34.80	$	24.30	$	0.19	$	24.74	$	24.11	$	0.16
Second		31.98		28.10		0.19		24.93		24.15		0.16
Third		33.92		30.50		0.19		24.94		24.20		0.16
Fourth		33.86		29.89		0.19		24.88		22.90		0.16
Total					$	0.76					$	0.64

As of December 31,	2005		2004		2003		2002
	- Millions of Dollars -
Net Debt	$	1,379	$	1,684	$	1,761	$	1,783
Total Debt and Capital Lease Obligations	$	1,535	$	1,855	$	1,940	$	1,975

Segment	Estimated Capital Expenditures
	-Millions of Dollars-
TEP	$160
UNS Gas	25
UNS Electric	35
UniSource Energy Consolidated	$220

Business Segment	2006		2007		2008		2009		2010
	-Millions of Dollars-
TEP	$	160	$	166	$	155	$	173	$	145
UNS Gas		25		26		23		23		25
UNS Electric		35		33		22		22		26
UniSource Energy Consolidated	$	220	$	225	$	200	$	218	$	196


UniSource Energy’s Contractual Obligations - Millions of Dollars -
Payment Due in Years Ending December 31,		2006		2007		2008		2009		2010		2011		2012 and after		Total
Long Term Debt
Principal⁽¹⁾	$	5	$	5	$	203	$	5	$	395	$	50	$	554	$	1,217
Interest⁽²⁾		69		69		68		53		45		40		564		908
Capital Lease Obligations⁽³⁾:
Springerville Unit 1		85		85		85		33		57		83		348		776
Springerville Coal Handling		22		24		19		15		17		19		78		194
Sundt Unit 4		10		12		12		13		14		-		-		61
Springerville Common		7		6		5		5		5		5		144		177
Operating Leases		2		2		2		1		1		1		2		11
Purchase Obligations⁽⁴⁾:
Coal and Rail Transportation⁽⁵⁾		88		80		80		79		79		42		240		688
Purchase Power⁽⁶⁾		16		-		-		-		-		-		-		16
Transmission		7		7		2		1		1		1		-		19
Gas⁽⁷⁾		43		26		15		8		7		7		-		106
Other Long-Term Liabilities⁽⁸⁾:
Pension & Other Post Retirement Obligations⁽⁹⁾		13		4		4		5		6		6		28		66
San Juan Pollution Control Equipment⁽¹⁰⁾		2		9		17		4		-		-		-		32
Total Contractual Cash Obligations	$	369	$	329	$	512	$	222	$	627	$	254	$	1,958	$	4,271

	UniSource Energy			TEP
	Amount -Millions of Dollars-		Expiring Year	Amount -Millions of Dollars-		Expiring Year
Net Operating Losses	$	18	2021-2022	$	-	-
Federal AMT Credit		77	-		62	-

	Sales									Operating Revenue
	2005			2004			2003			2005		2004		2003
	-Millions of kWh-									-Millions of Dollars-
Electric Retail Sales:
Residential		3,633			3,460			3,390		$	331	$	315	$	310
Commercial		1,856			1,788			1,689			193		187		176
Industrial		2,302			2,226			2,245			166		161		160
Mining		843			829			702			40		39		28
Public Authorities		241			240			250			17		17		18
Total Electric Retail Sales		8,875			8,543			8,276			747		719		692
Electric Wholesale Sales Delivered:
Long-term Contracts		1,188			1,227			1,199			55		33		31
Other Sales		1,994			2,065			2,165			115		120		115
Transmission		-			-			-			7		5		6
Net Unrealized Gain (Loss) on Forward Sales of Energy		-			-			-			1		2		(1	)
Total Electric Wholesale Sales		3,182			3,292			3,364			178		160		151
Total Electric Sales		12,057			11,835			11,640		$	925	$	879	$	843

Weather Data:
Cooling Degree Days		1,529			1,298			1,567
10-Year Average		1,426			1,409			1,458
% Over / (Under) Prior Year		18	%		(17	%)		9	%
% Over / (Under) 10-Year Average		7	%		(8	%)		7	%

Heating Degree Days		1,257			1,631			1,327
10-Year Average		1,488			1,481			1,459
% Over / (Under) Prior Year		(23	%)		23	%		(8	%)
% Over / (Under) 10-Year Average		(16	%)		10	%		(9	%)

	Generation						Expense
	2005		2004		2003		2005		2004		2003
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation
Four Corners		783		749		806	$	11	$	10	$	11
Navajo		1,221		1,244		1,121		16		15		13
San Juan		2,484		2,435		2,295		53		48		50
Springerville		5,572		5,731		5,962		94		92		92
Sundt 4		787		735		643		16		14		12
Total Coal-Fired Generation		10,847		10,894		10,827	$	190	$	179	$	178
Gas-Fired Generation		368		432		432		36		34		32
Solar and Other		9		8		6		-		-		-
Total Generation		11,224		11,334		11,265		226		213		210
Purchased Power		1,639		1,322		1,153		133		73		65
Total Resources		12,863		12,656		12,418	$	359	$	286	$	275
Less Line Losses and Company Use		806		821		778
Total Energy Sold		12,057		11,835		11,640

	Future Estimated TRA Amortization		Unamortized TRA Balance
	-Millions of Dollars-

2006	$	66	$	102
2007		76		26
2008		26		-

Average Market Price for Around-the-Clock Energy	$/MWh
Month-End December 31, 2005	$	89
Month-End December 31, 2004		51

Quarter ended December 31, 2005		78
Quarter ended December 31, 2004		46

12 months ended December 31, 2005		59
12 months ended December 31, 2004		44

Average Market Price for Natural Gas	$/MMBtu
Month-End December 31, 2005	$	8.45
Month-End December 31, 2004		6.17

Quarter ended December 31, 2005	$	9.67
Quarter ended December 31, 2004		5.90

12 months ended December 31, 2005		7.17
12 months ended December 31, 2004		5.44

Delivery	Allowances Sold		Estimated Pre-tax Gain (millions)
2006		10,000	$	7
2007		10,000	$	6

	Lease Debt Investment Balance
Leased Asset	December 31, 2005		December 31, 2004
	- In Millions -
Springerville Unit 1	$	91	$	98
Springerville Coal Handling Facilities		65		73
Total Investment In Lease Debt	$	156	$	171

Category	2006		2007		2008		2009		2010
	-Millions of Dollars-
Transmission, Distribution and Other Facilities	$	143	$	156	$	135	$	136	$	121
New Generation Facilities		-		-		-		27		13
Luna Energy Facility		14		-		-		-		-
Environmental		3		10		20		10		11
Total	$	160	$	166	$	155	$	173	$	145

Leased Asset	Balance at December 31, 2005		Expiration
	- In Millions -
Springerville Unit 1	$	432		2014
Springerville Coal Handling Facilities		122		2015
Springerville Common Facilities		106		2020
Sundt Unit 4		54		2011
Total Capital Lease Obligations	$	714


TEP’s Contractual Obligations - Millions of Dollars -
Payment Due in Years Ending December 31,	2006		2007		2008		2009		2010		2011		2012 and after		Total
Long-Term Debt:
Principal	$	-	$	-	$	138	$	-	$	329	$	-	$	354	$	821
Interest		47		46		46		36		30		26		392		623
Capital Lease Obligations:
Springerville Unit 1		85		85		85		33		57		83		348		776
Springerville Coal Handling		22		24		19		15		17		19		78		194
Sundt Unit 4		10		12		12		13		14		-		-		61
Springerville Common		7		6		5		5		5		5		144		177
Operating Leases		1		1		1		1		-		-		-		4
Purchase Obligations:
Coal and Rail Transportation		88		80		80		79		79		42		240		688
Purchase Power		16		-		-		-		-		-		-		16
Gas		2		2		2		-		-		-		-		6
Other Long-Term Liabilities:
Pension & Other Post -Retirement Obligations		11		4		4		5		6		6		27		63
San Juan Pollution Control Equipment		2		9		17		4		-		-		-		32
Total Contractual Cash Obligations	$	291	$	269	$	409	$	191	$	537	$	181	$	1,583	$	3,461

	Sales						Revenues
	2005		2004		2003*		2005		2004		2003*
	-Millions of Therms-						-Millions of Dollars-
Retail Therm Sales:
Residential		69		71		25	$	79	$	76	$	25
Commercial		29		29		12		29		28		11
Industrial		3		3		1		2		2		1
Public Authorities		7		7		3		7		6		2
Total Retail Therm Sales		108		110		41		117		112		39
Transport		-		-		-		3		3		1
Negotiated Sales		21		21		13		16		12		7
Program (NSP)
Total Therm Sales		129		131		54	$	136	$	127	$	47

Company	Required Net Worth		Actual Net Worth
	- Millions of Dollars -
UES	$	50	$	130
UNS Gas		43		80

	Unrealized Gain (Loss) of MEG’s Trading Activities
	- Millions of Dollars -
Source of Fair Value At December 31, 2005	Maturity 0 - 6 months			Maturity 6 - 12 months			Maturity over 1 yr.			Total Unrealized Gain (Loss)
Prices actively quoted	$	(5.3	)	$	(0.5	)	$	(0.5	)	$	(6.3	)
Prices based on models and other valuation methods		-			-			14.0			14.0
Total	$	(5.3	)	$	(0.5	)	$	13.5		$	7.7

								Accumulated
	Common				Accumulated			Other			Total
	Shares		Common		Earnings			Comprehensive			Stockholders'
	Outstanding*		Stock		(Deficit)			Income (Loss)			Equity
	- In Thousands -

Balances at December 31, 2002	33,579	$	664,103	$	(203,439	)	$	(4,024	)	$	456,640

Comprehensive Income:
2003 Net Income	-		-		113,941			-			113,941

Minimum Pension Liability
(net of $2,639 income taxes)	-		-		-			2,180			2,180

Total Comprehensive Income											116,121

Dividends Declared	-		-		(20,208	)		-			(20,208	)
Shares Issued under Stock Compensation Plans	7		55		-			-			55
Shares Distributed by Deferred Compensation Trust	3		52		-			-			52
Shares Issued for Stock Options	199		2,736		-			-			2,736
Tax Benefit Realized from Stock Options Exercised	-		753		-			-			753
Other	-		323		-			-			323

Balances at December 31, 2003	33,788		668,022		(109,706	)		(1,844	)		556,472

Comprehensive Income:
2004 Net Income	-		-		45,919			-			45,919

Minimum Pension Liability Adjustment
(net of $1,430 income taxes)	-		-		-			(10,460	)		(10,460	)

Unrealized Gain on Cash Flow Hedges
(net of $960 income taxes)	-		-		-			1,465			1,465

Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $68 income taxes)	-		-		-			104			104

Total Comprehensive Income											37,028

Dividends Declared	-		-		(21,879	)		-			(21,879	)
Shares Issued under Stock Compensation Plans	63		1,307		-			-			1,307
Shares Distributed by Deferred Compensation Trust	4		50		-			-			50
Shares Issued for Stock Options	400		6,117		-			-			6,117
Tax Benefit Realized from Stock Options Exercised	-		1,459		-			-			1,459
Other	-		164		-			-			164

Balances at December 31, 2004	34,255		677,119		(85,666	)		(10,735	)		580,718

Comprehensive Income:
2005 Net Income	-		-		46,144			-			46,144

Minimum Pension Liability Adjustment
(net of $1,378 income taxes)	-		-		-			(2,101	)		(2,101	)

Unrealized Gain on Cash Flow Hedges
(net of $6,503 income taxes)	-		-		-			9,918			9,918

Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $2,403 income taxes)	-		-		-			(3,665	)		(3,665	)

Total Comprehensive Income											50,296

Dividends Declared	-		-		(26,339	)		-			(26,339	)
Shares Issued under Stock Compensation Plans	36		-		-			-			-
Shares Distributed by Deferred Compensation Trust	-		1		-			-			1
Shares Issued for Stock Options	583		9,411		-			-			9,411
Tax Benefit Realized from Stock Options Exercised	-		2,527		-			-			2,527
Other	-		127		-			-			127

Balances at December 31, 2005	34,874	$	689,185	$	(65,861	)	$	(6,583	)	$	616,741

										Accumulated
				Capital			Accumulated			Other			Total
		Common		Stock			Earnings			Comprehensive			Stockholders'
		Stock		Expense			(Deficit)			Income (Loss)			Equity
		- Thousands of Dollars -

Balances at December 31, 2002	$	654,405	$	(6,357	)	$	(290,192	)	$	(4,024	)	$	353,832

Comprehensive Income:
2003 Net Income		-		-			128,913			-			128,913

Minimum Pension Liability
(net of $2,639 income taxes)		-		-			-			2,180			2,180

Total Comprehensive Income													131,093

Dividends Paid		-		-			(80,000	)		-			(80,000	)
Capital Contribution from UniSource Energy		1,129		-			-			-			1,129

Balances at December 31, 2003		655,534		(6,357	)		(241,279	)		(1,844	)		406,054

Comprehensive Income:
2004 Net Income		-		-			46,127			-			46,127

Minimum Pension Liability Adjustment
(net of $1,430 income taxes)		-		-			-			(10,460	)		(10,460	)

Unrealized Gain on Cash Flow Hedges
(net of $960 income taxes)		-		-			-			1,465			1,465

Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $68 income taxes)		-		-			-			104			104

Total Comprehensive Income													37,236

Dividends Paid		-		-			(31,500	)		-			(31,500	)
Capital Contribution from UniSource Energy		2,720		-			-			-			2,720

Balances at December 31, 2004		658,254		(6,357	)		(226,652	)		(10,735	)		414,510

Comprehensive Income:
2005 Net Income		-		-			48,267			-			48,267

Minimum Pension Liability Adjustment		-		-			-			(2,101	)		(2,101	)
(net of $1,378 income taxes)

Unrealized Gain on Cash Flow Hedges
(net of $6,503 income taxes)		-		-			-			9,918			9,918

Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $2,403 income taxes)		-		-			-			(3,665	)		(3,665	)

Total Comprehensive Income													52,419

Dividends Paid		-		-			(46,000	)		-			(46,000	)
Equity Contribution from UniSource Energy		25,261		-			-			-			25,261
Capital Contribution from UniSource Energy		112,456		-			-			-			112,456

Balances at December 31, 2005	$	795,971	$	(6,357	)	$	(224,385	)	$	(6,583	)	$	558,646

Name	Age	Position(s) Held	Executive Officer Since
James S. Pignatelli	62	Chairman, President and Chief Executive Officer	1998
Michael J. DeConcini	41	Senior Vice President, Chief Operating Officer, Energy Resources	1999
Steven J. Glaser	48	Senior Vice President, Chief Operating Officer, Transmission and Distribution	2005
Raymond S. Heyman	50	Senior Vice President and General Counsel	2005
Kevin P. Larson	49	Senior Vice President, Chief Financial Officer and Treasurer	2000
Dennis R. Nelson	55	Senior Vice President, Utility Services	1998
Karen G. Kissinger	51	Vice President, Controller and Chief Compliance Officer	1998
Steven W. Lynn	59	Vice President, Communications and Government Relations	2003
Catherine A. Nichols	47	Corporate Secretary	2003

Required Minimum Net Worth

Actual

Net Worth

-Millions of Dollars-

UNS Electric