EXHIBIT 99.3

ITEM 7. - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 

Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for UniSource Energy and its four primary business segments and includes the following:

· outlook and strategies,

· operating results during 2005 compared with 2004, and 2004 compared with 2003,

· factors which affect our results and outlook,

· liquidity, capital needs, capital resources, and contractual obligations,

· dividends, and

· critical accounting estimates.

UniSource Energy is a holding company that has no significant operations of its own. Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities. UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years. UES began operations in 2003. UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in northern and southern Arizona. Millennium invests in unregulated businesses. UED is facilitating the expansion of the Springerville Generating Station, but currently has no significant operations. We conduct our business in three primary business segments - TEP’s Electric Utility segment, UNS Gas and UNS Electric.

UniSource Energy is in the process of exiting its Millennium investments. In January 2006, UniSource Energy’s Board of Directors approved a plan to sell its investment in Global Solar, Inc. (Global Solar), Millennium’s largest holding, to a third party. The operating results of Global Solar are reported as discontinued operations. On March 31, 2006, Millennium completed the sale of its interest in Global Solar.

UniSource Energy was incorporated in the State of Arizona in 1995 and obtained regulatory approval to form a holding company in 1997. In 1998, TEP and UniSource Energy exchanged shares of stock resulting in TEP becoming a subsidiary of UniSource Energy. Following the share exchange, TEP transferred the stock of its subsidiary Millennium to UniSource Energy.

TEP is the principal operating subsidiary of UniSource Energy and, at December 31, 2005, represented approximately 82% of its assets. The seasonal nature of TEP’s business causes operating results to vary significantly from quarter to quarter. UniSource Energy’s other net income (loss) consists of: parent company expenses, including in 2005, interest expense (net of tax) on debt issued in 2005; interest on the note payable from UniSource Energy to TEP; costs in 2003 and 2004 associated with the proposed acquisition of UniSource Energy; the income and losses associated with Millennium’s investments; and results of operations at UED.

UNISOURCE ENERGY CONSOLIDATED

OUTLOOK AND STRATEGIES

Operating Plans and Strategies

Our financial prospects and outlook for the next few years will be affected by many competitive, regulatory and economic factors. Our plans and strategies include the following:

· Efficiently manage our generation, transmission and distribution resources and look for ways to control our operating expenses while maintaining and enhancing reliability and profitability.

· Expand TEP’s and UNS Electric’s portfolio of generating and purchased power resources to meet growing retail energy demand.

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· Oversee the construction of Springerville Unit 3 and continue to enhance the value of existing assets by working with Salt River Project to facilitate the development of Springerville Unit 4.

· Enhance the value of TEP’s transmission system while continuing to provide reliable access to generation for TEP and UES’ retail customers and market access for all generating assets.

· Continue to integrate UES’ businesses with UniSource Energy’s other businesses.

· Reduce UniSource Energy’s debt.

· Promote economic development in our service territories.

To accomplish our goals, during 2006 we expect to spend the following on capital expenditures:

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

While we believe that our plans and strategies will continue to have a positive impact on our financial prospects and position, we recognize that we continue to be highly leveraged, and as a result, our access to the capital markets may be limited or more expensive than for less leveraged companies.

RESULTS OF OPERATIONS

Executive Overview

UniSource Energy recorded Income Before Discontinued Operations and Cumulative Effect of Accounting Change of $52 million in 2005, $51 million in 2004 and $54 million in 2003. Net Income of $46 million in 2005 includes a $5 million loss from discontinued operations and a $1 million loss from the cumulative effect of an accounting change; Net Income of $46 million in 2004 includes a $5 million loss from discontinued operations; and Net Income of $114 million in 2003 includes a $7 million loss from discontinued operations and a $67 million gain on the cumulative effect of an accounting change. Results in 2005 and 2004 include a full year of operations at UNS Gas and UNS Electric; results in 2003 were for the period August 11 to December 31.

In 2005, outages at TEP’s coal-fired generating plants had a negative impact on results for UniSource Energy. TEP reported higher retail revenues due to warm summer weather and continued customer growth. In addition, TEP’s wholesale revenues benefited from higher market prices for power. However, those gains were offset by a nearly four-week unplanned outage at TEP’s Springerville Unit 2 in August, a period when customer demand was high and energy prices were boosted by the impact of hurricane activity in the Gulf of Mexico. Higher natural gas prices and the cost of purchasing electricity during the outage contributed to an 82 percent increase in TEP’s purchased power expense.

Also in 2005, UniSource Energy completed a financial restructuring, issuing $240 million of debt and using the proceeds to repay an inter-company note and infuse capital into its utility subsidiaries. TEP retired approximately $321 million of debt and capital lease obligations (net of proceeds received from TEP’s investment in Springerville lease debt). Interest expense was lower than in 2004 and TEP will benefit from a full year of interest savings in 2006.

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CONTRIBUTION BY BUSINESS SEGMENT

The table below shows the contributions to our consolidated after-tax earnings by our four business segments and Other net income (loss).

	2005			2004			2003
	-Millions of Dollars-
TEP	$	49		$	46		$	62
UNS Gas (1)		5			6			1
UNS Electric (1)		5			4			2
Other (2)		(7	)		(5	)		(11	)
Income Before Discontinued Operations and  Cumulative Effect of Accounting Change		52			51			54
Discontinued Operations - Net of Tax (3)		(5	)		(5	)		(7	)
Cumulative Effect of Accounting Change - Net of Tax		(1	)		-			67
Consolidated Net Income	$	46		$	46		$	114

⁽¹⁾ 2003 results are for the period from August 11, 2003 to December 31, 2003.

⁽²⁾ Includes: UniSource Energy parent company expenses; interest expense on the note payable from UniSource Energy to TEP; income and losses from Millennium investments and UED, including in 2005, interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement; in 2004 and 2003 includes costs associated with the proposed acquisition of UniSource Energy; and in 2003 includes costs associated with the Citizens acquisition.

⁽³⁾ Relates to the discontinued operations of Global Solar.

Factors Impacting Income Before Discontinued Operations and Cumulative Effect of Accounting Change in 2005 Compared With 2004

2005 Included:

· a $28 million decrease in TEP’s gross margin (the sum of retail and wholesale electric revenues less fuel and purchased power expense) due to the following:

- a $60 million increase in TEP’s purchased power expense resulting from an extended unplanned outage of Springerville Unit 2 in August 2005, planned maintenance outages at San Juan Unit 2 and Four Corners Unit 5 during the second quarter, minor unplanned outages at TEP’s other coal plants during the year and higher wholesale power prices;

- a $14 million increase in TEP’s fuel expense due to a $3 million increase in natural gas costs primarily from higher gas prices and an $11 million increase in coal costs;

- a $28 million increase in retail revenues due to warm weather and a 3% increase in TEP’s customer base; and

- a $19 million increase in TEP’s wholesale revenues due to the higher market price for power compared to last year.

· a $28 million decrease in Other Operations and Maintenance expense (O&M). Higher maintenance costs at TEP’s coal-fired plants were offset by an increase of $10 million in pre-tax gains on the sale of excess SO2 Emission Allowances by TEP.

· a $6 million increase in the amortization of TEP’s Transition Recovery Asset.

· an $8 million decrease in Total Interest Expense related to the financial restructuring of TEP in May 2005; and

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· a $4 million pre-tax gain at Millennium from its investment at Haddington.

2004 Included:

· expenses of $10 million related to the proposed acquisition of UniSource Energy; and

· a $4 million pre-tax gain at Millennium from its investment in Haddington.

Factors Impacting Income Before Discontinued Operations and Cumulative Effect of Accounting Change in 2004 Compared With 2003

2004 Included:

· a $194 million increase in total operating revenues resulting from additional revenues at UNS Gas and UNS Electric of $82 million and $89 million, respectively, and a 2% increase in TEP’s number of retail customers;

· a $118 million increase in purchased energy expense, which includes purchased power and purchased gas expense. This resulted from additional purchased energy expense at UNS Gas and UNS Electric of $51 million and $57 million, respectively, and a $7 million increase at TEP due to higher economic wholesale electric purchases in lieu of running gas-fired generation;

· a $38 million increase in O&M due primarily to additional O&M at UNS Gas and UNS Electric, $10 million of expenses related to the proposed acquisition of UniSource Energy and expenses related to planned and unplanned outages at some of TEP’s generating facilities;

· an $18 million increase in amortization of TEP’s Transition Recovery Asset;

· a $2 million increase in total interest expense due to a full year of interest expense at UNS Gas and UNS Electric;

· a $21 million increase in income tax expense due to higher Income Before Taxes, Discontinued Operations and Cumulative Effect of Accounting Change and a $15 million tax benefit recorded in 2003 resulting from guidance issued by the IRS clarifying rules on limitations of the use of net operating loss carry forwards; and

· income of $1 million recorded by Millennium’s other investments.

2003 Included:

· an $11 million pre-tax development fee received by UED at the financial closing of Springerville Unit 3; and

· net losses of $9 million at Millennium’s other investments.

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LIQUIDITY AND CAPITAL RESOURCES

UNISOURCE ENERGY CONSOLIDATED CASH FLOWS

	2005			2004			2003
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$	276		$	307		$	263
Investing Activities		(170	)		(156	)		(351	)
Financing Activities		(115	)		(98	)		98
Net Increase (Decrease) in Cash	$	(9	)	$	53		$	10

UniSource Energy’s consolidated cash flows are provided primarily from retail and wholesale energy sales at TEP, UNS Gas and UNS Electric, net of the related payments for fuel and purchased energy. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load.

We use our available cash primarily to:

· fund capital expenditures at TEP, UNS Gas and UNS Electric;

· pay dividends to shareholders; and

· reduce leverage.

The primary source of liquidity for UniSource Energy, the parent company, is dividends it receives from its subsidiaries, primarily TEP. Also, under our tax sharing agreement, our subsidiaries make income tax payments to UniSource Energy, which makes payments on behalf of the consolidated group.

As of February 28, 2006, cash and cash equivalents available to UniSource Energy was approximately $152 million.

Executive Overview

UniSource Energy’s cash flows from operations decreased by $31 million in 2005 compared with 2004. Higher retail and wholesale revenues were offset by higher purchased power costs at TEP and higher gas costs at UNS Gas. Operating cash flows at UNS Gas decreased by $7 million in 2005 compared with 2004, due to higher natural gas prices and a lag between the time UNS Gas purchases its gas and the receipts it collects from its customers.

Capital expenditures increased in 2005 due primarily to the construction of the Luna Energy Facility and growth and maintenance of UniSource Energy’s gas and electric utility systems.

UniSource Energy took advantage of the favorable capital markets to improve TEP’s balance sheet and establish additional sources of liquidity. UniSource Energy issued debt in 2005 and used the proceeds to repay an inter-company note and provide capital to its utility subsidiaries. During 2005, TEP retired $321 million of debt and capital lease obligations (net of proceeds received from TEP’s investment in Springerville lease debt).

Operating Activities

In 2005, net cash flows from operating activities decreased by $31 million compared with 2004. The following factors contributed to the decrease:

2005 Included:

· a $52 million increase in cash receipts from retail electric and gas sales due to warm summer weather in TEP’s service territory and customer growth across all of UniSource Energy’s utility service areas;

· a $22 million increase in cash receipts from wholesale electric sales due primarily to higher market prices for power;

· an $11 million increase in cash receipts from the sale of excess Emission Allowances;

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· a $10 million decrease in total income taxes and other taxes paid, due primarily to higher estimated payments and extension payments made in 2004;

· a $7 million decrease in total interest costs paid due primarily to lower debt and capital lease balances at TEP;

· an $83 million increase in purchased energy cost and a $15 million increase in fuel costs paid due to planned and unplanned outages at TEP’s coal plants, as well as higher natural gas and power prices;

· a $12 million increase in payments for O&M costs primarily related to the outages at TEP’s coal plants; and

· a $5 million increase in wages paid due to a greater number of employees and rising wage levels.

2004 Included:

· $17 million received by TEP related to the return of a deposit for its 1992 Mortgage; and

· $7 million termination payment related to the proposed acquisition of UniSource Energy.

Investing Activities

Forecasted Capital Expenditures

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

Capital expenditures of $863 million for 2006 through 2009 are expected to be $80 million, or 10% higher than forecasted amounts reported in the Company’s 2004 Annual Report on Form 10-K. This increase is the result of several factors including deferral of 2005 projects to 2006, higher material and construction costs and greater than expected customer growth.

Net cash used for investing activities was $14 million higher in 2005 than in 2004, primarily due to the following factors:

2005 Included:

· a $37 million increase in capital expenditures due to TEP’s share of the construction costs of the Luna Energy Facility, maintenance expenditures at TEP’s generating plants, and customer growth and system maintenance at UNS Gas and UNS Electric; offset by

· other proceeds from investing activities of $9 million due primarily to the redemption of a $5 million certificate of deposit and the sale of land by TEP;

2004 Included:

· $13 million used by TEP to purchase a one-third interest in the Luna Energy Facility;

· other cash used of $5 million related to the investment in a certificate of deposit; and

· $4 million paid by TEP to purchase Springerville lease debt.

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Financing Activities

Net cash used for financing activities was $17 million higher in 2005 compared with 2004. The following factors primarily contributed to the change:

2005 Included:

· proceeds of $240 million from UniSource Energy’s issuance of $150 million of Convertible Senior Notes and borrowings of $90 million under its term loan;

· $257 million increase in repayments on long-term debt related to TEP’s early redemption of $53 million of 1941 Mortgage Bonds, the repurchase and redemption of $225 million of fixed-rate tax exempt debt and $4 million of principal payments on the UniSource Energy term loan;

· a $6 million increase in dividends paid to UniSource Energy shareholders; and

· a $3 million increase in TEP’s payments on capital lease obligations.

As a result of the activities described above, our consolidated cash and cash equivalents decreased to $145 million at December 31, 2005, from $154 million at December 31, 2004. We invest cash balances in high-grade money market securities with an emphasis on preserving the principal amounts invested.

At February 28, 2006, our consolidated cash balance, including cash equivalents, was approximately $152 million.

We believe that we will continue to have sufficient cash flow to cover our capital needs, as well as required debt payments and dividends to shareholders. In the event that we experience lower cash from operations in 2006, we will use our revolving credit facilities to fund our cash needs.

Convertible Senior Notes

In March 2005, UniSource Energy issued $150 million of 4.50% 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 our 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 in March 2010, UniSource Energy will have the option to redeem the notes, in whole or in part, for cash, at a price equal to 100% of the principal amount plus accrued and unpaid interest. Holders of the notes will have the right to require UniSource Energy to repurchase the notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain specified fundamental changes involving UniSource Energy occur. The repurchase price will be 100% of the principal amount of the notes plus accrued and unpaid interest.

In the event of a fundamental change that occurs prior to March 2010, UniSource Energy may be required to pay a make-whole premium on notes converted in connection with the fundamental change. The make-whole premium will be payable in shares of UniSource Energy Common Stock or the consideration into which UniSource Energy Common Stock has been converted or exchanged in connection with such fundamental change.

A fundamental change involving UniSource Energy will be deemed to have occurred if (1) certain transactions occur as a result of which there is a change in control of UniSource Energy; or (2) UniSource Energy Common Stock ceases to be listed on a national securities exchange or quoted on The Nasdaq National Market or another established automated over-the-counter trading market in the United States.

The notes may be accelerated upon the occurrence and continuance of an event of default under the indenture governing the notes. The failure to make required payments on the notes or comply with the terms of the indenture may constitute an event of default. In addition, events of default may arise upon the acceleration of $50 million of indebtedness for borrowed money of UniSource Energy or TEP, or certain events of bankruptcy involving UniSource Energy or TEP.

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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 in April 2010. The UniSource Credit Agreement includes a $90 million term loan facility and a $15 million revolving credit facility. Quarterly principal payments of $1.25 million are due beginning June 30, 2005, with the balance due at maturity.

We borrowed $80 million under the $90 million term loan in May 2005, and the remaining $10 million in June 2005. We made required $1.25 million principal payments in June, September and December 2005, leaving an outstanding balance at December 31, 2005 on the term loan of $86 million.

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 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.

We expect that we may borrow from time to time under the revolving credit facility to meet temporary cash needs. As of December 31, 2005, we had no borrowings outstanding under the revolving credit facility.

Use of Proceeds

In 2005, we received $146 million of net proceeds from the sale of the Convertible Senior Notes and $90 million of proceeds from the term loan, which was used as follows:

· to repay our $95 million promissory note to TEP plus accrued interest of $11 million;

· to make a capital contribution of $16 million to UNS Gas and a capital contribution of $4 million to UNS Electric; and

· to make a capital contribution of $110 million to TEP.

TEP used the proceeds from the capital contribution, the inter-company note repayment (described above), along with borrowings under its revolving credit facility to repurchase and redeem $225 million of fixed-rate tax-exempt debt obligations. See, Tucson Electric Power, Bond Repurchases and Redemptions, and Tucson Electric Power Company, Liquidity and Capital Resources, Dividends on Common Stock, below.

See below for further discussion of Liquidity and Capital Resources for each of UniSource Energy’s reportable segments.

GUARANTEES AND INDEMNITIES

In the normal course of business, UniSource Energy and certain subsidiaries, including TEP, enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. We entered into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis. The most significant of these guarantees at December 31, 2005 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 system assets;

· UES’ guarantee of a $40 million revolving credit facility available to UNS Gas and UNS Electric;

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

· 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 the consolidated balance sheets.

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

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

CONTRACTUAL OBLIGATIONS

The following charts display UniSource Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2005.

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

⁽¹⁾ Includes quarterly principal payments due on the term loan facility in UniSource Energy’s Credit Agreement. 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.

⁽²⁾ Includes letter of credit and remarketing fees on variable rate debt. The interest rates for variable rate debt are estimated using Eurodollar futures rates for an approximation of LIBOR. For variable rate IDBs, a discount is applied to estimated LIBOR based on the historical discount the IDBs have had to LIBOR.

⁽³⁾ Upon expiration of the Springerville Coal Handling Facilities and Common Leases, TEP is obligated to acquire the facilities at fixed prices of $139 million in 2015, $38 million in 2017, and $68 million in 2021,

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and each of the owners of Unit 3 and Unit 4 (if constructed) have the obligation to purchase from TEP a 14 percent and 17 percent interest, respectively, in such facilities. The acquisition of the assets upon expiration of the lease terms is excluded from the table above. Beginning with commercial operation of Springerville Unit 3 in 2006, Tri-State is obligated to reimburse TEP for various operating costs related to the common facilities on an ongoing basis, including 14 percent of the Springerville Common Lease payments and 17 percent of the Springerville Coal Handling Facilities Lease payments. Similar reimbursement obligations are required if Unit 4 is constructed. TEP remains the obligor under these capital leases. Capital Lease Obligations do not reflect any reduction associated with this reimbursement.

⁽⁴⁾ Purchase obligations reflect the minimum contractual obligation under legally enforceable contracts with contract terms that are both fixed and determinable. The total amount paid under these contracts depends on the quantity purchased and transported. UES and TEP’s requirements are expected to be in excess of these minimums. UniSource Energy has excluded open purchase orders of approximately $17 million expected to be fulfilled in 2006.

⁽⁵⁾ Table includes minimum purchase and transportation requirements that TEP is contractually obligated to spend. Based on prior years’ expenditures, TEP expects to spend approximately $180 million annually for the purchase and transportation of coal through 2010. TEP is unable to estimate how much it will spend under these contracts beyond 2010 due to the uncertain impact of the amended Springerville coal contract.

⁽⁶⁾ Includes forward power purchases for 2006. UniSource Energy has not included amounts payable to PWCC under UNS Electric’s full requirements power supply agreement as payments under this contract are usage based with no fixed demand charges and are recovered through the PPFAC mechanism. We expect to spend approximately $100 million annually under this contract through May 2008. TEP entered into contracts for power purchases in 2006 totaling $18 million subsequent to December 31, 2005, which are excluded from the table above.

⁽⁷⁾ Amounts include UNS Gas’ forward gas purchases and firm transportation agreements with EPNG and Transwestern.Natural gas supply and management agreement commitments with BP are excluded as prices for incremental gas to be supplied vary. Amounts also exclude swap agreements which are marked to market on a monthly basis. UNS Gas entered into forward gas purchases for 2006 through 2008 totaling $11 million subsequent to December 31, 2005, which are excluded from the table above. 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, and is excluded from the table above.

⁽⁸⁾ Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the remote generating stations. TEP estimates its undiscounted final reclamation liability is $41 million with reclamation beginning in 2028. See Note 6. Also excludes $56 million of undiscounted asset retirement obligations expected to occur through 2066. See Note 3. Also, excludes Millennium’s equity commitments totaling $5 million over three years to fund subsidiaries (Haddington and Valley Ventures) as suitable investments are identified.

⁽⁹⁾ These obligations represent TEP and UES’ minimum required contributions to pension plans in 2006 and TEP’s expected postretirement benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. TEP and UES do not know and have not included pension contributions beyond 2006 due to the significant impact that returns on plan assets and changes in discount rates might have on such amounts. TEP funds the postretirement benefit plan on a pay-as-you-go basis.

⁽¹⁰⁾ These obligations represent TEP’s share of the cost of new pollution control equipment based on its ownership of San Juan. Under a settlement agreement signed in March 2005 with the New Mexico Environmental Department and environmental activist groups, the co-owners of San Juan will install new technology at the generating station to reduce mercury, particulate matter, NOx, and SO₂ emissions. In addition, TEP’s share of increased operating and maintenance costs associated with the new technologies is expected to be approximately $12 million over the next 10 years.

In addition, UniSource Energy has contingent obligations under various surety bonds that total approximately $0.5 million. Also, MEG conducts its emissions trading activities using certain contracts which contain provisions whereby MEG may be required to post margin collateral due to a change in contract values. As of December 31, 2005, MEG had no cash collateral posted to its trading counterparties.

We have reviewed our contractual obligations and provide the following additional information:

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· We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.

· None of our contracts or financing structures contains provisions or acceleration clauses due to changes in our stock price.

DIVIDENDS ON COMMON STOCK

On February 10, 2006, UniSource Energy declared a first quarter cash dividend of $0.21 per share on its Common Stock. The first quarter dividend, totaling approximately $7 million, will be paid March 15, 2006 to shareholders of record at the close of business February 21, 2006. During 2005, UniSource Energy paid quarterly dividends to its shareholders of $0.19, totaling approximately $26 million. In 2004, UniSource Energy paid quarterly dividends to its shareholders of $0.16, totaling approximately $22 million.

INCOME TAX POSITION

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

	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	-

The $18 million in NOL carry forwards is subject to limitation due to a reorganization of certain Millennium entities in December 2002. The future use of these losses is dependent upon the generation of sufficient future taxable income at the separate company level. See Critical Accounting Estimates, Deferred Tax Valuation - TEP and Millennium, below.

Internal Revenue Service 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 (IRS) 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 pay an appropriate amount of interest in 2006. Such payments would not affect total tax expense.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

The financial condition and results of operations of TEP are currently the principal factors affecting the financial condition and results of operations of UniSource Energy on an annual basis. The following discussion relates to TEP’s utility operations, unless otherwise noted.

UTILITY SALES AND REVENUES

Customer growth, weather and other consumption factors affect retail sales of electricity. Electric wholesale revenues are affected by market prices in the wholesale energy market, availability of TEP generating resources, and the level of wholesale forward contract activity.

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The table below provides trend information on retail sales by major customer class and electric wholesale sales made by TEP in the last three years, as well as weather data for TEP’s service territory.

	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	%)

2005 Compared with 2004

Total revenues from sales to retail customers increased by $28 million, or 4%, in 2005 compared with 2004, due primarily to customer growth and warm summer weather. Residential kWh sales increased 5% and commercial kWh sales increased 4% during 2005.

Despite lower coal plant availability due to planned and unplanned outages and a 3% decrease in wholesale kWh sales, wholesale revenues increased $18 million, or 11%, in 2005 compared with 2004. The average wholesale market price of energy was $59 per MWh in 2005, compared with $44 per MWh last year. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.

2004 Compared with 2003

Total revenues from kWh sales to retail customers increased by $27 million, or 4%, in 2004 compared with 2003, resulting from customer growth and cool winter weather. The average price of copper was 59% higher in 2004, leading to increased mining activity and an $11 million increase in revenues from TEP’s mining customers.

Wholesale revenues increased $9 million, or 6%, in 2004, despite a 2% decrease in wholesale kWh sales. In the first nine months of 2004, TEP benefited from greater coal plant availability which allowed TEP to sell more excess power into the wholesale market compared to 2003. Wholesale sales opportunities were limited in the fourth quarter of 2004 due to a planned outage at TEP’s Springerville Unit 1. The average wholesale market price of energy was $44 per MWh in 2004, compared with $41 per MWh in 2003. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.

TEP recorded a $3 million reserve in the second quarter of 2004 and a $2 million reserve in the first quarter of 2003 for revenue subject to refund related to wholesale sales made to the California Independent

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System Operator and the California Power Exchange in 2001 and 2000. These amounts are recorded as a reduction to wholesale revenue.

OPERATING EXPENSES

2005 Compared with 2004

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense, and energy resources for 2005, 2004 and 2003 are detailed below:

	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

During 2005, planned outages at Springerville Unit 2, San Juan Unit 2 and Four Corners Unit 5 and an unplanned outage at Springerville Unit 2 during the third quarter led to higher gas-related fuel costs and an 82% increase in purchased power expense. Purchased power expense increased $60 million compared with 2004, due to a 19% increase in MWhs purchased and an increase in wholesale market prices for power. The average market price for around-the-clock energy based on the Palo Verde Index increased 34% in 2005 compared to average prices in 2004. A combination of higher coal and natural gas costs contributed to a $13 million increase in total fuel expense at TEP’s generating plants in 2005.

The table below shows the average cost per kWh for TEP’s generating plants by fuel type.

	2005	2004	2003
	-cents per kWh-
Coal	1.75	1.64	1.64
Gas	9.78	7.87	7.41
All sources	2.01	1.88	1.86

Other Operating Expenses

Other Operations & Maintenance expense decreased $22 million in 2005. O&M expenses related to the plant outages described above were offset by the sale of excess SO₂ Emissions Allowances. During 2005 and 2004, TEP recorded pre-tax gains of $13 million and $3 million, respectively, on the sale of excess SO₂ Emissions Allowances. In 2004, TEP recorded $8 million of expenses related to a proposed acquisition of UniSource Energy. See Factors Affecting Results of Operations, Emission Allowances, below.

Depreciation and amortization decreased $2 million in 2005 primarily due to the extension of useful lives of certain generating assets at TEP in July 2004 and April 2005.

Amortization of the Transition Recovery Asset (TRA) increased $6 million in 2005. Amortization of the TRA is the result of the Settlement Agreement with the ACC, which changed the accounting method for TEP’s

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generation operations. This item reflects the recovery, through 2008, of transition recovery assets which were previously regulatory assets of the generation business. The amount of amortization is a function of the TRA balance and total kWh consumption by TEP’s retail customers. See Factors Affecting Results of Operations, Rates, Settlement Agreement, below.

The table below shows estimated annual TRA amortization and unamortized TRA balances for 2006 through 2008.

	Future Estimated TRA Amortization	Unamortized TRA Balance
	-Millions of Dollars-
2006	$66	$102
2007	76	26
2008	26	-

Other Income (Deductions)

In 2005, TEP’s Income Statement included inter-company Interest Income of $2 million. This represented Interest Income on a promissory note TEP received from UniSource Energy in exchange for the transfer to UniSource Energy of its stock in Millennium in 1998. UniSource Energy repaid the inter-company promissory note in March 2005. On UniSource Energy’s Consolidated Statement of Income, this Interest Income, as well as UniSource Energy’s related interest expense, was eliminated as an inter-company transaction. See Liquidity and Capital Resources, TEP Cash Flows, Inter-Company Note from UniSource Energy, below.

Interest Expense

Total interest expense decreased by $17 million, or 11%, in 2005 due to debt retirements and lower fees under the TEP Credit Agreement entered into in May 2005.

When TEP entered into the new credit agreement in May 2005, it expensed $2 million of unamortized issuance costs associated with the prior credit agreement. Also in May 2005, TEP repurchased and redeemed $225 million of debt and recorded a loss of $3 million related to this transaction. For 2005, the $5 million of expenses related to these two transactions was more than offset by the lower rates under TEP’s Credit Agreement and the interest savings related to the $225 million of debt that was redeemed and repurchased.

Income Tax Expense

Income tax expense was comparable to 2004, as 2005 income before income taxes approximated the prior year. Additionally, TEP released $1 million of valuation allowance in 2005 based on an upward revision of its estimated taxable income.

Cumulative Effect of Accounting Change

TEP adopted FIN 47 in December 2005 and recorded a one-time $1 million after-tax cost. See Note 3 of Notes to Consolidated Financial Statements, Accounting Change: Accounting for Asset Retirement Obligations, and Critical Accounting Estimates, Accounting for Asset Retirement Obligations, below.

2004 Compared with 2003

Fuel and Purchased Power Expense

Fuel expense at TEP’s generating plants was $213 million in 2004 compared with $210 million in 2003. Gas-related fuel expense increased $2 million to $34 million, in 2004 due to an 11% increase in market price for gas. Coal-related fuel expense increased $1 million due to the higher availability and use of TEP’s coal-fired generating plants.

The increase in the regional supply of new gas-generated energy and the completion of a 500-kV transmission connection allowed TEP to decrease use of its older, less efficient gas generation units in favor of more economical purchases of energy in the wholesale market. TEP’s Purchased Power expense increased

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approximately $8 million, or 12% in 2004. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.

Other Operating Expenses

Other O&M expense increased by $20 million, or 12%, in 2004 primarily attributable to increased maintenance costs at the Springerville and San Juan generating facilities and approximately $8 million of costs related to the proposed acquisition of UniSource Energy.

Amortization of the TRA increased $18 million in 2004 compared with 2003.

Other Income (Deductions)

TEP’s Income statement includes inter-company Interest Income of $9 million for 2004, and $10 million for 2003.

Interest Expense

Long-term debt interest expense decreased by $7 million, or 9%, in 2004 due to lower Letter of Credit fees under TEP’s Credit Agreement entered into in March 2004 and lower interest expense related to the $27 million of 8.5% 1941 Mortgage Bonds redeemed in July 2004. Interest on capital leases increased $2 million in 2004 due to a recalculation of interest expense related to a capitalized lease transaction.

Income Tax Expense

Income Tax Expense Before Cumulative Effect of Accounting Change increased $14 million in 2004 compared with 2003, due primarily to a $15 million tax benefit recognized in 2003 resulting from guidance issued by the IRS clarifying rules on limitations of the use of net operating loss carry forwards.

Cumulative Effect of Accounting Change

TEP adopted FAS 143 in January 2003 and recorded a one-time $67 million after-tax gain. Upon adoption of FAS 143, TEP recorded an asset retirement obligation of $38 million at its net present value of $1 million; increased depreciable assets by $0.1 million for asset retirement costs, reversed $113 million of costs previously accrued for final removal recorded in accumulated depreciation, and reversed previously recorded deferred tax assets of $44 million. Adopting FAS 143 results in a reduction to depreciation expense charged throughout the year as well because asset retirement costs are no longer recorded as a component of depreciation expense. For the year 2003, the reduction in depreciation expense is approximately $6 million. See Note 3 of Notes to Consolidated Financial Statements, Accounting Change: Accounting for Asset Retirement Obligations, andCritical Accounting Estimates, Accounting for Asset Retirement Obligations, below.

FACTORS AFFECTING RESULTS OF OPERATIONS

COMPETITION

In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP), however only a small number of commercial and industrial customers initially chose an ESP. By 2002, none of TEP’s retail customers were served by an alternate ESP.

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 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. See Rates, Declaratory Motion Filed with ACC and Motion to Amend the Settlement Agreement, below.

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TEP competes against gas service suppliers and others that provide energy services. Other forms of energy technologies may provide competition to TEP’s services in the future, but to date, are not financially viable alternatives for its retail customers. Self-generation by TEP’s large industrial customers could also provide competition for TEP’s services in the future, but has not had a significant impact to date.

In the wholesale market, TEP competes with other utilities, power marketers and independent power producers in the sale of electric capacity and energy.

RATES

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 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.

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.

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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.

Transition

The Settlement Agreement provides that TEP’s fixed CTC will expire when TEP’s $450 million transition asset is fully amortized and recovered or on December 31, 2008, whichever is earlier. Based on current projections of retail sales, the TRA is expected to be fully amortized by mid-2008. The Settlement Agreement also specifies that TEP’s floating competitive transition charge (floating CTC) will expire on December 31, 2008. This charge, which moves inversely to changes in market-based generation services rates, presently appears as a credit on retail customer bills. Based on current forward pricing in the wholesale energy markets, TEP anticipates that the floating CTC will continue to appear as a credit on retail customer bills through 2008. After the expiration of the floating CTC, TEP’s rates for generation services should be market based.

Absent any other change to TEP’s retail rate structure, TEP estimates that the expiration of the fixed CTC in 2008 (which has provided revenues, on average of .93 cents per kWh sold, or approximately $80 million annually) would result in a decrease in retail revenues of approximately 12% relative to revenues from current retail rates. However, absent any other change except the expiration of the fixed CTC, the expiration in 2008 of the floating CTC would result in market-based generation services rates which would, based on current pricing in the wholesale energy markets, produce a significant retail rate increase in January 2009.

We are operating pursuant to the Settlement Agreement. However, we cannot predict the future rate methodologies for TEP which the ACC could authorize, including whether the ACC will permit or require market-based rates for generation services, reinstate cost of service ratemaking for all or a portion of TEP’s generation services or require an alternate methodology to determine rates for TEP’s generation services. Under any circumstances, TEP will seek appropriate recovery and return on its investment in assets used to serve its customers.

TEP expects that, in establishing future rates, TEP and the ACC will review the entirety of the retail rate structure rather than focusing solely on any one of the elements noted above. Although TEP is unable to predict the type and level of future retail rates, TEP believes that the 2004 general rate case information filed with the ACC evidences that there have been a number of factors that have changed since the Settlement Agreement was approved that justify increasing or maintaining retail rates at current levels.

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;

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

(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.

WESTERN ENERGY MARKETS

As a participant in the western U.S. wholesale power markets, TEP is affected by changes in market conditions and market participants. TEP competes with other utilities, power marketers and independent power producers in the sale of electric capacity and energy at market-based rates in the wholesale market.

As of the end of 2005, electric generating capacity in Arizona has grown to approximately 25,500 MW; an increase of nearly 62% since 2001. A majority of the growth over the last three years is the result of 17 new or upgraded gas-fired generating units with a combined capacity of approximately 9,700 MW.

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Market Prices

The average market price for around-the-clock energy based on the Dow Jones Palo Verde Index increased in 2005, as did the average price for natural gas based on the Permian Index. Average market prices for around-the-clock energy began to rise in 2003 and have continued to increase during 2004 and 2005 primarily due to high natural gas prices. As a result of all of these factors, TEP’s natural gas and purchased power expenses were higher in 2005 than in 2004. Energy prices remain at these high levels to date; however, we cannot predict whether these higher prices will continue, or whether changes in various factors that influence demand and supply will cause prices to fall during 2006.

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

In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers and to meet local reliability needs. Some of these purchased power contracts are price indexed to natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel and gas-indexed purchased power with fixed price contracts for a maximum of three years. TEP currently has approximately 38%, or 2.3 Bcf, of this exposure hedged for the summer peak period of 2006 at a weighted average price of $5.13 per MMBtu. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.

Market prices may also affect TEP’s wholesale revenues. TEP commits to future sales of energy as part of its ongoing efforts to hedge its excess generation based on projected generation capability, forward prices and generation costs. For 2006 and 2007, TEP has sold forward 50 MW of fixed price energy at an average approximate price of $70 per MWh. In 2006, this energy sale excludes on-peak hours in June through September, and in 2007, excludes on-peak hours in April through September.

We expect the market price and demand for capacity and energy to continue to be influenced by factors including:

· the availability and price of natural gas;

· weather;

· continued population growth in the western U.S.;

· economic conditions in the western U.S.;

· availability of generating capacity throughout the western U.S.;

· the extent of electric utility industry restructuring in Arizona, California and other western states;

· the effect of FERC regulation of wholesale energy markets;

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· availability of hydropower;

· transmission constraints; and

· environmental regulations and the cost of compliance.

COAL SUPPLY

In 2003, TEP entered into an agreement for the purchase of coal to Sundt Unit 4 through 2006. TEP expects to begin renegotiating this contract in the first half of 2006. Based on current coal market conditions, we expect the price TEP will pay for coal at Sundt Unit 4 after 2006 to be above existing prices. In 2007, the impact on TEP’s total coal-related fuel expense across all of its plants is expected to increase by 2-3%.

EMISSION ALLOWANCES

TEP has SO₂ Emission Allowances in excess of what is required to operate its generating units. The excess results primarily from a higher removal rate of SO₂ emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations. From time to time, TEP will sell a portion of its excess SO₂ Emission Allowances. In 2004, TEP sold 4,000 SO₂ Emission Allowances for a pre-tax gain of $3 million. In 2005, TEP sold 15,000 SO₂ Emission Allowances for a pre-tax gain of $13 million. The table below summarizes TEP’s forward sales of SO₂ Emission Allowances, as of December 31, 2005.

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

Excluding the forward sales at December 31, 2005, TEP expects to have approximately 20,000 additional excess SO₂ Emission Allowances available for sale in future periods.

SPRINGERVILLE UNITS 3 AND 4

Springerville Unit 3 will consist of a 400 MW coal-fired generating facility at the same site as Springerville Units 1 and 2. Tri-State will lease 100% of Unit 3 from a financial owner. When Unit 3 is built, TEP will allocate the fixed costs of the existing common facilities over the additional generating unit. TEP will operate Unit 3 and upon the completion of construction, expects to receive annual pre-tax benefits of approximately $15 million in the form of cost savings, rental payments, transmission revenues, and other fees. As part of the project, Tri-State provided funding to improve sulfur dioxide scrubbers, low-nitrogen oxide burners and other emission control upgrades for Units 1 and 2, which were completed in 2005.

Salt River Project (SRP) will purchase 100 MW of capacity from Tri-State under a 30 year power purchase agreement and has the right to construct and own Unit 4, a 400 MW coal-fired generating facility at the same Springerville site, at a later date. If SRP decides to construct Unit 4, TEP may be required, along with Tri-State, to exercise best efforts to find a replacement purchaser for SRP to purchase 100 MW of capacity from Unit 3. If TEP and Tri-State are unable to find such a replacement purchaser, TEP would then purchase 100 MW of output from Unit 4, beginning with the commercial operation of Unit 4. Under the terms of existing regulatory permits, Unit 4 is required to be completed by December 31, 2009.

LIQUIDITY AND CAPITAL RESOURCES

TEP CASH FLOWS

TEP’s capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt and capital lease obligations. As shown in the chart below, during the last three years, TEP had sufficient cash available after capital expenditures, scheduled debt payments and capital lease obligations to provide for other investing and financing activities:

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	2005			2004			2003
	-Millions of Dollars-
Cash from Operations	$	243		$	275		$	261
Other Capital Expenditures		(128	)		(116	)		(122	)
Capital Expenditures for Luna Energy Facility Assets		(22	)		(13	)		-
Net Cash Flows after Capital Expenditures*		93			146			139
Debt Maturities		-			(2	)		(2	)
Retirement of Capital Lease Obligations		(53	)		(49	)		(43	)
Proceeds from Investment in Springerville Lease Debt and Equity		14			12			12
Net Cash Flows Available after Required Payments*	$	54		$	107		$	106

* We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments, which are non-GAAP financial measures, provide useful information to investors as measures of liquidity and our ability to meet our capital requirements and mandatory redemptions of debt and capital lease obligations.

During 2006, TEP expects to generate sufficient internal cash flows to fund its operating activities, construction expenditures, required debt maturities, and to pay dividends to UniSource Energy. However, TEP’s cash flows may vary due to changes in wholesale revenues, changes in short-term interest rates, and other factors. TEP currently has $20 million available under its Revolving Credit Facility which it may borrow if cash flows fall short of expectations or if monthly cash requirements temporarily exceed available cash balances.

Operating Activities

In 2005, net cash flows from operating activities declined by $32 million compared with 2004. Net cash flows were impacted by:

2005 included:

· a $22 million decrease in cash receipts from electric retail and wholesale sales, net of fuel and purchased energy costs, due primarily to higher replacement power costs resulting from coal plant outages and higher gas-related fuel costs;

· a $10 million increase in payments for O&M costs related to coal plant outages;

· an $11 million increase in cash receipts from the sale of SO₂ Emissions Allowances;

· a $6 million increase in wages paid primarily due to a greater number of employees and rising wage levels;

· a $12 million decrease in total interest paid due to lower capital lease obligation balances, lower long-term debt balances and lower annual fees under TEP’s Credit Agreement that was entered into in May 2005; and

· a $10 million increase in interest received, due primarily to interest received from UniSource Energy when it repaid its $95 million inter-company loan to TEP.

2004 included:

· the return of a $17 million deposit related to TEP’s 1992 Mortgage.

Investing Activities

Net cash used for investing activities was $3 million higher in 2005 compared with 2004, due to the following:

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2005 included:

· a $20 million increase in capital expenditures related primarily to a planned maintenance outage at Springerville and TEP’s share of the construction costs of the Luna Energy Facility; and

· an increase in other proceeds from investing activities of $6 million related to the redemption of a certificate of deposit and the sale of land by a TEP subsidiary.

2004 included:

· the use of $9 million for a $5 million investment in a certificate of deposit and the purchase of $4 million of Springerville lease debt.

Investments in Springerville Lease Debt

	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

The yields on TEP’s investments in Springerville Lease Debt, at the date of purchase, range from 8.9% to 12.7%.

See Note 9 of Notes to Consolidated Financial Statements - Debt and Capital Lease Obligations.

Capital Expenditures

TEP’s forecasted capital expenditures are summarized below:

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

These estimated expenditures include costs for TEP to comply with current federal and state environmental regulations. These estimates do not include the costs to construct the Tucson to Nogales transmission line. All of these estimates are subject to continuing review and adjustment. Actual construction expenditures may be different from these estimates due to changes in business conditions, construction schedules, environmental requirements, and changes to TEP’s business arising from retail competition. TEP plans to fund these expenditures through internally generated cash flow.

Tucson to Nogales Transmission Line

If all regulatory approvals are received, the future costs to construct the transmission line to Nogales, Arizona is expected to be approximately $95 million. Through December 31, 2005, approximately $11 million in land acquisition, engineering and environmental expenses have been incurred on this project. If the required approvals are not received, TEP may be required to expense approximately $9 million of the costs that have been capitalized related to the project, propose alternative methods to the ACC for approving reliability and spend additional amounts to implement such alternatives. See Item 1. Business, Tucson Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Line.

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In addition to TEP’s forecasted capital expenditures for construction, TEP’s other capital requirements include its required debt maturities and capital lease obligations. See Note 9 of Notes to Consolidated Financial Statements - Debt and Capital Lease Obligations.

Financing Activities

Net cash used for financing activities was $72 million higher in 2005 compared with 2004. The following factors contributed to the increase:

2005 included:

· a $253 million increase in repayments on long-term debt related to TEP’s early redemption of $53 million of 1941 Mortgage Bonds in March of 2005, and the repurchase and redemption of $225 million of fixed-rate tax exempt debt in May 2005;

· a $3 million increase in scheduled payments made on capital lease obligations;

· a capital contribution of $110 million from UniSource Energy;

· the receipt of $95 million from UniSource Energy as a repayment for an inter-company loan;

· a $15 million increase in dividends paid to UniSource Energy;

· an $11 million decline in other financing proceeds; and

· a $4 million decrease in debt issuance costs.

At December 31, 2005, there were no outstanding borrowings under TEP’s revolving credit facility. As of February 28, 2006, cash and cash equivalents available to TEP was approximately $52 million.

Inter-Company Note from UniSource Energy

In March 2005, UniSource Energy repaid to TEP a debt obligation in the principal amount of $95 million plus accrued interest of $11 million. TEP used the proceeds during May 2005 to redeem or repurchase certain of its existing debt through tender offers and redemptions. See Bond Repurchases and Redemptions, below.

Capital Contribution from UniSource Energy

In May 2005, UniSource Energy made a $110 million capital contribution to TEP. TEP used the proceeds during May 2005 to redeem or repurchase certain of its existing debt through tender offers and redemptions. See Bond Repurchases and Redemptions, below.

Bond Repurchases and Redemptions

TEP made a sinking fund payment of $1 million on its 6.1% 1941 Mortgage IDBs in January 2005. In March 2005, TEP redeemed at par the remaining $31 million of its 6.1% 1941 Mortgage IDBs due in 2008, as well as the remaining $21 million of its 7.5% 1941 Mortgage IDBs due in 2006.

In May 2005, TEP used the proceeds from the repayment of the note from UniSource Energy and the capital contribution from UniSource Energy to purchase $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. In May 2005, TEP 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 may choose to resell the Repurchased Bonds to third parties or cancel them in the future.

As a result of the capital contribution, inter-company note repayment, and the bond repurchases and redemptions, TEP’s ratio of equity to total capitalization (excluding capital leases) improved to 40.5% as of December 31, 2005, which allows TEP to dividend up to 100% of its current year net income to UniSource Energy.

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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. See UniSource Energy, Liquidity and Capital Resources, UniSource Energy Credit Agreement, Use of Proceeds, above, and Bond Repurchases and Redemptions, above.

Mortgage Indentures

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

TEP’s mortgage indenture creates a lien on and security interest in most of TEP’s utility plant assets. Springerville Unit 2, which is owned by San Carlos, is not subject to this lien and security interest. TEP’s mortgage indenture allows TEP to issue additional mortgage bonds on the basis of (1) a percentage of net utility property additions and/or (2) the principal amount of retired mortgage bonds. The amount of bonds that TEP may issue is also subject to a net earnings test under the indenture.

TEP’s Credit Agreement, which totals $401 million and is secured by 1992 Mortgage Bonds, limits the amount of mortgage bonds that may be outstanding to no more than $650 million. At December 31, 2005, TEP had a total of $539 million in outstanding mortgage bonds, consisting of the $401 million in bonds securing the TEP Credit Agreement, and the $138 million in bonds securing the 7.50% Collateral Trust Bonds due in 2008. Although the 1992 Mortgage would allow TEP to issue additional bonds, the limit imposed by the TEP Credit Agreement is more restrictive and is currently the governing limitation.

TEP also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions and/or retired bond credits. TEP’s Credit Agreement that was in effect in 2003 limited the amount of property that could be released from the 1992 Mortgage Indenture to $25 million. As a result, TEP deposited $17 million in cash with the 1992 Mortgage trustee in the fourth quarter of 2003 in conjunction with the release of $42 million in property from its mortgage indentures related to the Springerville Unit 3 transaction. The $17 million deposit was refunded to TEP during 2004. This limitation was removed when TEP refinanced its Credit Agreement in March 2004.

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Springerville Common Facilities Leases

In 1985, TEP sold and leased back its undivided one-half ownership interest in the common facilities at the Springerville Generating Station. Under the terms of the Springerville Common Facilities Leases, TEP must arrange for refinancing or refunding of the secured notes underlying the leases prior to June 30, 2006 in order to avoid a special event of loss. A special event of loss results in a termination of the leases and would require TEP to repurchase the facilities for approximately $125 million. TEP is currently in the process of refinancing this debt.

As of December 31, 2005, the principal balance of the lease debt was $69 million. Interest is payable at LIBOR plus 4%. The LIBOR rate is reset every six months and the rate in effect on December 31, 2005 was 3.68%, and was 1.92% on December 31, 2004, which resulted in a total interest rate on the lease debt of 7.68% at December 31, 2005 and 6.17% at December 31, 2004.

Tax-Exempt Local Furnishing Bonds

TEP has financed a substantial portion of utility plant assets with industrial development revenue bonds issued by the Industrial Development Authorities of Pima County and Apache County. The interest on these bonds is excluded from gross income of the bondholder for federal tax purposes. This exclusion is allowed because the facilities qualify as “facilities for the local furnishing of electric energy” as defined by the Internal Revenue Code. These bonds are sometimes referred to as “tax-exempt local furnishing bonds.” To qualify for this exclusion, the facilities must be part of a system providing electric service to customers within not more than two contiguous counties. TEP provides electric service to retail customers in the City of Tucson and certain other portions of Pima County, Arizona and to Fort Huachuca in contiguous Cochise County, Arizona.

TEP has financed the following facilities, in whole or in part, with the proceeds of tax-exempt local furnishing bonds: Springerville Unit 2, Sundt Unit 4, a dedicated 345-kV transmission line from Springerville Unit 2 to TEP’s retail service area (the Express Line), and a portion of TEP’s local transmission and distribution system in the Tucson metropolitan area. As of December 31, 2005, TEP had approximately $359 million of tax-exempt local furnishing bonds outstanding. Approximately $257 million in principal amount of such bonds financed Springerville Unit 2 and the Express Line. In addition, approximately $45 million of remaining lease debt related to the Sundt Unit 4 lease obligation was issued as tax-exempt local furnishing bonds.

Various events might cause TEP to have to redeem or defease some or all of these bonds:

· formation of an RTO or ISO;

· asset divestiture;

· changes in tax laws; or

· changes in system operations.

TEP believes that its qualification as a local furnishing system should not be lost so long as (1) the RTO or ISO would not change the operation of the Express Line or the transmission facilities within TEP’s local service area, (2) the RTO or ISO allows pricing of transmission service such that the benefits of tax-exempt financing continue to accrue to retail customers, and (3) energy produced by Springerville Unit 2 and by TEP’s local generating units continues to be consumed in TEP’s local service area. However, there is no assurance that such qualification can be maintained. Any redemption or defeasance of these bonds would likely require the issuance and sale of higher cost taxable debt securities in the same or a greater amount.

Capital Lease Obligations

At December 31, 2005, TEP had $714 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease amounts.

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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

Except for TEP’s 13% equity interest in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases. TEP may renew the leases or purchase the leased assets at such time. The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time. The purchase price option for the Springerville Coal Handing Facilities and Common Facilities are fixed at $139 million and $106 million, respectively. TEP has agreed to exercise the purchase options for the Springerville Coal Handling Leases and Common Leases.

CONTRACTUAL OBLIGATIONS

The following charts display TEP’s contractual obligations as of December 31, 2005 by maturity and by type of obligation.

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

See UniSource Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, above, for a description of these obligations.

We have no other commercial commitments to report.

We have reviewed our contractual obligations and provide the following additional information:

· TEP’s Credit Agreement contains pricing for its Revolving Credit Facility based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings.

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· TEP’s Credit Agreement contains certain financial and other restrictive covenants, including interest coverage and leverage tests. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At December 31, 2005, TEP was in compliance with these covenants. See TEP Credit Agreement, above.

· TEP conducts its wholesale trading activities under the Western System Power Pool Agreement (WSPP) which contains provisions whereby TEP may be required to post margin collateral due to a change in credit rating or changes in contract values. As of December 31, 2005, TEP has not been required to post such collateral.

DIVIDENDS ON COMMON STOCK

TEP declared and paid dividends of $46 million in 2005, $32 million in 2004 and $80 million in 2003. UniSource Energy is a primary holder of TEP’s common stock.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2005, TEP was in compliance with the terms of the TEP Credit Agreement.

The ACC Holding Company Order, as modified by the UES Settlement Agreement, restricted the amount of dividends that TEP may pay to UniSource Energy. Until TEP’s ratio of common equity to total capitalization (excluding capital lease obligations) equaled 40%, TEP could not pay dividends in excess of 75% of its net income. As of December 31, 2005, TEP’s ratio of common equity to total capitalization (excluding capital lease obligations) was 40.5%.

The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis to pay dividends from current year earnings.

UNS GAS

RESULTS OF OPERATIONS

UniSource Energy formed two operating companies, UNS Gas and UNS Electric, to acquire the Arizona electric and gas assets from Citizens in 2003, as well as an intermediate holding company, UES, to hold the common stock of UNS Gas and UNS Electric. Results of operations in 2003 for UNS Electric and UNS Gas cover the period from August 11, 2003, the date the assets were acquired from Citizens, to December 31, 2003.

In 2005, UNS Gas reported net income of $5 million compared with $6 million in 2004. We expect operations at UNS Gas to vary with the seasons, with peak energy usage occurring in the winter months.

As of December 31, 2005, UNS Gas had approximately 139,000 retail customers, a 4% increase from last year. The table below shows UNS Gas’ therm sales and revenues for 2005, 2004 and 2003.

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	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 Program (NSP)		21		21		13		16		12		7
Total Therm Sales		129		131		54	$	136	$	127	$	47

*For the period August 11 to December 31, 2003

Retail therm sales were 2% lower in 2005 due primarily to warmer winter weather. Retail revenues increased $9 million in 2005 due to the PGA surcharge increase, which became effective in November 2005. See Factors Affecting Results of Operations, Rates and Regulation Energy, Energy Cost Adjustment Mechanism, below.

Through a Negotiated Sales Program (NSP) approved by the ACC, UNS Gas supplies natural gas to some of its large transportation customers. Approximately one half of the margin earned on these NSP sales is retained by UNS Gas, while the remainder benefits retail customers through a credit to the Purchased Gas Adjustor (PGA) mechanism which reduces the gas commodity price. See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.

The table below provides summary financial information for UNS Gas.

	2005		2004		2003*
	-Millions of Dollars-
Gas Revenues	$	136	$	127	$	47
Other Revenues		2		2		-
Total Operating Revenues		138		129		47
Purchased Energy Expense		91		82		31
Utility Gross Margin		47		47		16
Other Operations and Maintenance Expense		23		23		8
Depreciation and Amortization		7		5		2
Taxes other than Income Taxes		3		3		2
Total Other Operating Expenses		33		31		12
Operating Income		14		16		4
Total Interest Expense		6		6		2
Income Tax Expense		3		4		1
Net Income	$	5	$	6	$	1

*For the period August 11 to December 31, 2003

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FACTORS AFFECTING RESULTS OF OPERATIONS

RATES AND REGULATION

When ACC-designated under or over recovery trigger points are met, UNS Gas may request a PGA surcharge or credit to collect or return the amount deferred from or to customers. See Energy Cost Adjustment Mechanism, below.

Energy Cost Adjustment Mechanism

UNS Gas’ retail rates include a Purchased Gas Adjustor (PGA) mechanism intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual gas and transportation costs and the cost of gas and transportation recovered through base rates are deferred and recovered or repaid through the PGA mechanism.

The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month period. The actual gas and transportation costs that are either under or over collected through the PGA factor are charged or credited to a balancing account (PGA bank).

The current annual cap on the maximum increase in the PGA factor is $0.10. In January 2006, UNS Gas filed a request with the ACC to increase the cap to $0.20 to allow for more timely recovery of actual gas costs. We cannot predict when the ACC will take action on this matter.

When ACC-designated under or over recovery trigger points of $6.2 million and $4.5 million, respectively, 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 period deemed appropriate by the ACC.

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.

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.

General Rate Case Filing

UNS Gas expects to file a general rate case in July 2006.

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LIQUIDITY AND CAPITAL RESOURCES

UNS Gas’ capital requirements consist primarily of capital expenditures. In 2005, capital expenditures were $23 million. During 2006, UNS Gas expects internal cash flows to fund its operating activities and a large portion of its construction expenditures. If UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, in 2006, UNS Gas may require additional funding to meet operating and capital requirements. Sources of funding could include an additional surcharge, draws on the revolving credit facility, additional credit lines or the investment of additional equity capital by UniSource Energy. See UNS Gas/UNS Electric Revolver, below.

In January 2005, UNS Gas established a short-term inter-company promissory note to UniSource Energy, by which it could borrow up to $10 million for general corporate purposes. In March 2005, UniSource Energy contributed an additional $6 million in capital to UNS Gas. UNS Gas used the proceeds of this contribution to repay the $6 million outstanding on the inter-company promissory note. In December 2005, UniSource Energy contributed $10 million in capital to UNS Gas. UNS Gas used the proceeds from this contribution for working capital purposes. The ratio of common equity to total capitalization for UNS Gas at December 31, 2005 was 44%.

The table below provides summary information for operating cash flow and capital expenditures:

	2005	2004	2003*
	-Millions of Dollars-
Net Cash Flows - Operating Activities	$ 14	$ 21	$ 5
Capital Expenditures	23	19	9

  *For the period August 11 to December 31, 2003

Forecasted capital expenditures for UNS Gas are as follows:

	2006	2007	2008	2009	2010
	- Millions of Dollars -
UNS Gas	$25	$26	$23	$23	$25

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 and UNS Electric intend to use the proceeds of any loans or letters of credit for general corporate purposes.

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.

UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of capital expenditures. As of December 31, 2005, UNS Gas had

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no borrowings outstanding under the UNS Gas/UNS Electric Revolver. In February 2006, UNS Gas borrowed $5 million under the UNS Gas/UNS Electric Revolver to fund working capital requirements.

Senior Unsecured Notes

UNS Gas has $100 million of senior unsecured notes outstanding consisting of $50 million of 6.23% Notes due in 2011 and $50 million of 6.23% Notes due in 2015 that are guaranteed by UES. The note purchase agreements for UNS Gas contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, incurrence of indebtedness, and minimum net worth. Consolidated Net Worth, as defined by the note purchase agreement for UNS Gas, is approximately equal to the balance sheet line item, Common Stock Equity. The table below outlines the actual and required minimum net worth levels of UES and UNS Gas at December 31, 2005.

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

The incurrence of indebtedness covenant requires UNS Gas to meet certain tests before additional indebtedness may be incurred. These tests include:

· A ratio of Consolidated Long-Term Debt to Consolidated Total Capitalization of no greater than 65% .

· An Interest Coverage Ratio (a measure of cash flow to cover interest expense) of at least 2.50 to 1.00.

However, UNS Gas may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $7 million. UNS Gas may not declare or make distributions or dividends (restricted payments) on its common stock unless (a) immediately after giving effect to such action no default or event of default would exist under its note purchase agreement and (b) immediately after giving effect to such action, it would be permitted to incur an additional dollar of indebtedness under the debt incurrence test. As of December 31, 2005, UNS Gas was in compliance with the terms of its note purchase agreement.

The senior unsecured notes may be accelerated upon the occurrence and continuance of an event of default under the note purchase agreement. Events of default under the note purchase agreement include failure to make payments required thereunder, certain events of bankruptcy or commencement of similar liquidation or reorganization proceedings or a change of control of UES or UNS Gas. In addition, an event of default may occur if UNS Gas, UES or UNS Electric defaults on any payments required in respect of certain indebtedness that is outstanding in an aggregate principal amount of at least $4 million or if any such indebtedness becomes due or capable of being called for payment prior to its scheduled payment date or if there is a default in the performance or compliance with the other terms of such indebtedness and, as a result of such default, such indebtedness has become, or has been declared, due and payable, prior to its scheduled payment date.

CONTRACTUAL OBLIGATIONS

UNS Gas Supply Contracts

UNS Gas has a natural gas supply and management agreement with BP Energy Company (BP). Under the contract, BP manages UNS Gas’ existing supply and transportation contracts and its incremental requirements. The initial term of the agreement expired in August 2005. The agreement was automatically extended one year and will continue to extend on an annual basis unless either party provides 180 days notice of its intent to terminate. No termination notice has been tendered by either party. Prices for incremental gas supplied by BP will vary based upon the market prices for the period during which the gas is delivered.

UNS Gas hedges its gas supply prices by entering into fixed price forward contracts at various times during the year to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of hedging at least 45% and not more than 80% of the expected monthly gas consumption with fixed prices prior to entering into the month. UNS Gas hedged approximately 60% of its expected monthly consumption for the 2005/2006 winter season (November through March). Additionally, UNS Gas has approximately 34% of its expected gas consumption hedged for April through October of 2006, and 28% hedged for the period November 2006 through March of 2007.

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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.

UNS Gas has specific volume limits in each month and specific receipt point rights from the available supply basins (San Juan and Permian). The average daily capacity rights of UNS Gas is approximately 870,000 therms per day, with an average of 1,200,000 therms per day in the winter season (November through March).

EPNG filed a rate case in 2005 with new, higher rates effective in January 2006, subject to refund. Beginning in January 2006, UNS Gas’ annual 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. This represents a 75% increase over previous minimum annual payments. This contract expires in August 2011.

UNS Gas has capacity rights of 250,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline. The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman, Arizona, and also delivers gas to UNS Gas’ facilities serving the Griffith Power Plant in Mohave County. This contract expires in February 2007.

The aggregate annual minimum transportation charges are expected to be approximately $7 million and $3 million for the EPNG and Transwestern contracts, respectively. These costs are passed through to our customers via the PGA. See Rates and Regulation, above.

DIVIDENDS ON COMMON STOCK

The ACC limits dividend payments by UNS Gas to 75% of earnings, until the ratio of UNS Gas’ common equity to total capitalization reaches 40%. During 2005, UniSource Energy made capital contributions to UNS Gas totaling $16 million. At December 31, 2005, the ratio of common equity to total capitalization for UNS Gas was 44%.

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. See Senior Unsecured Notes, above. It is unlikely, however, that UNS Gas will pay dividends in the next few years due to expected cash requirements for capital expenditures.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric’s net income for 2005 was $5 million, compared with $4 million in 2004. Similar to TEP’s operations, we expect UNS Electric’s operations to be seasonal in nature, with peak energy demand occurring in the summer months.

As of December 31, 2005, UNS Electric had approximately 89,000 retail customers, a 4% increase from last year. Retail kWh sales were 4% higher in 2005 due to customer growth and warm weather. The table below shows UNS Electric’s kWh sales and revenues for 2005, 2004 and 2003.

	Sales				Revenues
	2005	2004	2003*		2005		2004		2003*
	-Millions of kWh-				-Millions of Dollars-
Electric Retail Sales:
Residential	745	692	302	$	75	$	70	$	30
Commercial	591	574	153		60		58		16
Industrial	182	194	59		13		14		4
Other	3	3	47		1		1		5
Total Electric Retail Sales	1,521	1,463	561	$	149	$	143	$	55

*For the period August 11 to December 31, 2003

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The table below provides summary financial information for UNS Electric.

	2005		2004		2003*
	-Millions of Dollars-
Electric Revenues	$	149	$	143	$	55
Other Revenues		1		1		1
Total Operating Revenues		150		144		56
Purchased Energy Expense		100		96		39
Utility Gross Margin		50		48		17
Other Operations and Maintenance Expense		23		24		6
Depreciation and Amortization		10		9		3
Taxes other than Income Taxes		4		3		3
Total Other Operating Expenses		37		36		12
Operating Income		13		12		5
Total Interest Expense		5		5		2
Income Tax Expense		3		3		1
Net Income	$	5	$	4	$	2

   *For the period August 11 to December 31, 2003

FACTORS AFFECTING RESULTS OF OPERATIONS

COMPETITION

As required by the ACC order approving UniSource Energy’s acquisition of the Citizens’ Arizona gas and electric assets, in November 2003, UNS Electric filed with the ACC a plan to open its service territories to retail competition by December 31, 2003. The plan addressed all aspects of implementation. It included UNS Electric’s unbundled distribution tariffs for both standard offer customers and customers that choose competitive retail access, as well as Direct Access and Settlement Fee schedules. UNS Electric’s direct access rates for both transmission and ancillary services would be based upon its FERC Open Access Transmission Tariff. The plan is subject to review and approval by the ACC, which has not yet considered the plan. As a result of the court decisions concerning the ACC’s Retail Electric Competition Rules, we are unable to predict when and how the ACC will address this plan. See Tucson Electric Power Company, Factors Affecting Results of Operations, Competition, above for information regarding the Arizona Court of Appeals decision.

RATES AND REGULATION

Energy Cost Adjustment Mechanism

UNS Electric’s retail rates include a PPFAC, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under or over recovery of costs. The ACC has approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWCC.

LIQUIDITY AND CAPITAL RESOURCES

UNS Electric’s capital requirements consist of capital expenditures, which were $30 million in 2005.

To improve the reliability of service in Santa Cruz County, UNS Electric is building a 20 MW gas-fired combustion turbine at the Valencia site, and plans to upgrade its existing 115 kV line over time. The turbine should be in place by mid-2006, helping to improve reliability while the approval and permitting process for the 345 kV Tucson to Nogales transmission line continues. In 2005, UNS Electric’s capital expenditures included $7 million related to the turbine and expects its capital expenditures for 2006 to include approximately $4 million related to this project. See Item 1. Business, TEP Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Line.

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During 2006, UNS Electric expects to generate sufficient internal cash flows to fund its operating activities and a portion of its construction expenditures. In March 2005, UniSource Energy contributed $4 million of capital to UNS Electric. UNS Electric will meet its remaining cash needs through a combination of capital contributions from UniSource Energy and borrowings under a revolving credit facility that was established in April 2005.

The table below provides summary information for operating cash flow and capital expenditures.

	2005	2004	2003*
	-Millions of Dollars-
Net Cash Flows - Operating Activities	$ 21	$ 19	$ 8
Capital Expenditures	30	19	5

     * For the period August 11 to December 31, 2003

Forecasted capital expenditures for UNS Electric are as follows:

	2006	2007	2008	2009	2010
	- Millions of Dollars -
UNS Electric	$35	$33	$22	$22	$26

UNS Gas/UNS Electric Revolver

See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver above for description of UNS Electric’s unsecured revolving credit agreement.

UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of its capital expenditures. As of December 31, 2005, UNS Electric had $5 million outstanding under the UNS Gas/UNS Electric Revolver. At March 3, 2006, UNS Electric had $10 million outstanding under the UNS Gas/UNS Electric Revolver.

Senior Unsecured Notes

UNS Electric has $60 million of 7.61% senior unsecured notes outstanding due in 2008 that are guaranteed by UES. The note purchase agreements for 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. Consolidated Net Worth, as defined by the note purchase agreements for UNS Electric, is approximately equal to the balance sheet line item, Common Stock Equity. The table below outlines the actual and required minimum net worth levels of UES and UNS Electric at December 31, 2005.

Company	Required Net Worth	Actual Net Worth
	- Millions of Dollars -
UES	$50	$130
UNS Electric	26	50

The incurrence of indebtedness covenant requires UNS Electric to meet certain tests before additional indebtedness may be incurred. These tests include:

· A ratio of Consolidated Long-Term Debt to Consolidated Total Capitalization of no greater than 65%.

· An Interest Coverage Ratio (a measure of cash flow to cover interest expense) of at least 2.50 to 1.00.

However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. UNS Electric may not declare or make distributions or dividends (restricted payments) on its common stock unless (a) immediately after giving effect to such action no default or event of default would exist under its note purchase agreement and (b) immediately after giving effect to such action, it would be permitted to incur an additional dollar of indebtedness under the debt incurrence test. As of December 31, 2005, UNS Electric was in compliance with the terms of the note purchase agreement.

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The senior unsecured notes may be accelerated upon the occurrence and continuance of an event of default under the note purchase agreement. Events of default under the note purchase agreement include failure to make payments required thereunder, certain events of bankruptcy or commencement of similar liquidation or reorganization proceedings or a change of control of UES or UNS Electric. In addition, an event of default may occur if UNS Electric, UES or UNS Gas default on any payments required in respect of certain indebtedness that is outstanding in an aggregate principal amount of at least $4 million or if any such indebtedness becomes due or capable of being called for payment prior to its scheduled payment date or if there is a default in the performance or compliance with the other terms of such indebtedness and, as a result of such default, such indebtedness has become, or has been declared, due and payable, prior to its scheduled payment date.

CONTRACTUAL OBLIGATIONS

UNS Electric Power Supply and Transmission Contracts

UNS Electric has a full requirements power supply agreement with Pinnacle West Capital Corporation (PWCC). The agreement expires in May 2008. The agreement obligates PWCC to supply all of UNS Electric’s power requirements at a fixed price per MWh. Payments under the contract are usage based, with no fixed customer or demand charges. UNS Electric is currently evaluating potential replacement energy resources when its supply contract ends with PWCC in 2008.

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. Under the terms of the agreements, UNS Electric’s aggregated minimum fixed transmission charges are expected to be $1 million in 2006 through 2011. UNS Electric made payments under these contracts of $7 million in 2005 and $6 million in 2004.

DIVIDENDS ON COMMON STOCK

The ACC limits dividend payments by UNS Electric to 75% of earnings, until the ratio of common equity to total capitalization reaches 40%. In March 2005, UniSource Energy made a capital contribution of $4 million to UNS Electric. At December 31, 2005, the ratio of common equity to total capitalization for UNS Electric was 43%.

The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. See Senior Unsecured Notes, above. It is unlikely, however, that UNS Electric will pay dividends in the next few years due to expected cash requirements for capital expenditures.

OTHER

RESULTS OF OPERATIONS

The table below summarizes the income (loss) for the Other non-reportable segments in the last three years.

	2005			2004			2003
	- Millions of Dollars -
UniSource Energy Parent Company	$	(7	)	$	(5	)	$	(9	)
Millennium Investments		-			1			(9	)
UED		-			(1	)		7
Income From Continuing Operations	$	(7	)	$	(5	)	$	(11	)

Discontinued Operations - Net of Tax		(5	)		(5	)		(7	)
Total Other Net Loss	$	(12	)	$	(10	)	$	(18	)

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UniSource Energy Parent Company

UniSource Energy parent company expenses include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes, the UniSource Credit Agreement, a note payable from UniSource Energy to TEP, which was repaid in March 2005, income and losses from Millennium investments, income and losses from UED and costs in 2003 associated with the Citizens acquisition.

Millennium Investments

Millennium accounts for its investments under the consolidation method and the equity method. In some cases, Millennium is an investment’s sole provider of funding. When this is the case, Millennium recognizes 100% of an investment’s losses, because as sole provider of funds it bears all of the financial risk. To the extent that an investment becomes profitable and Millennium has recognized losses in excess of its percentage ownership, Millennium will recognize 100% of an investment’s net income until Millennium’s recognized losses equal its ownership percentage of losses.

Results from Other Millennium Investments in 2005 include an after-tax gain of $2 million from the sale of one of Haddington’s investments. The gain was partially offset by an impairment loss of $1 million on Millennium’s investment in MicroSat. In January 2006, Millennium sold its investment in MicroSat and the investment was written down to the value at which it was sold in January.

Results from Other Millennium Investments in 2004 include after-tax gains of $3 million from Haddington, $2 million from MicroSat and less than $1 million from SES. The gains were partially offset by after-tax losses of $2 million from IPS and less than $1 million each from MEG, Nations Energy and POWERTRUSION International, Inc. (Powertrusion), a manufacturer of lightweight utility poles.

Results from Other Millennium Investments in 2003 include after-tax losses of $2 million each from IPS and Powertrusion, $1 million from MicroSat, and less than $1 million each from MEG, SES, Nations Energy and TruePricing, Inc. (TruePricing).

UniSource Energy Development

In 2005, UED had no significant operations.

In 2004, UED recognized an impairment loss on its note receivable from an independent power producer. As UED’s recovery of the note receivable from the entity is subordinated to the rights of others, UED wrote off the entire $2 million balance due on the note at the time that Haddington, an investor in the independent power producer, determined that its investment was impaired. In 2004, UED’s net loss was $1 million.

UED recorded net income of $7 million in 2003. UED’s income in 2003 primarily represents an $11 million pre-tax development fee received at the financial closing of the Springerville Unit 3 project (Unit 3).

In 2003, Tri-State completed financing of Unit 3 and began construction. UED received reimbursement of its development costs totaling $29 million, as well as an $11 million development fee. UniSource Energy used the proceeds to repay a $35 million short-term bridge loan.

UED has no significant current operations and expects no significant activity in 2006.

Discontinued Operations - Global Solar

In these financial statements, UniSource Energy accounts for Global Solar as a discontinued operation and recognizes 100% of Global Solar’s losses. Global Solar recognizes expense when funding is used for research, development and administrative costs. Global Solar recorded losses of $5 million in 2005, $5 million in 2004 and $7 million in 2003.

In January 2006, UniSource Energy’s Board of Directors approved a plan to sell its investment in Global Solar to a third party. The operating results of Global Solar are reported as a discontinued operation. On March 31, 2006, Millennium completed the sale of its interest in Global Solar.

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FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

In April 2005, Millennium restructured its investment in IPS which included the formation of a new entity and a reduction in the percentage of equity held by Millennium to 31.4%. Millennium also committed to fund up to $3 million towards a future IPS stock offering, of which $1 million has already been funded as a secured loan to be converted to shares of IPS stock at the close of the offering.

In January 2006, Millennium sold its equity investment in MicroSat. The results of the fourth quarter of 2005 include an after-tax impairment loss of $1 million to write down the investment to the value at which it was sold in January.

MEG is in the process of winding down its activities and will not engage in any significant new activities after 2005. As of December 31, 2005, the fair value of MEG’s trading assets was $38 million and the fair value of MEG’s trading liabilities was $24 million.

Millennium is in the process of selling its remaining interest in Nations Energy Corporation (Nations Energy).

LIQUIDITY AND CAPITAL RESOURCES

In 2005, Haddington sold one of its investments and Millennium received a $6 million distribution related to the sale. In 2004, Millennium received a $7 million distribution from Haddington related to the gain on a sale of one of its investments. Millennium’s remaining commitments are $2 million to Haddington and $2 million to Valley Ventures.

In 2005, Millennium received $4 million as a return of its investment in Carboelectrica Sabinas, S. de R.L. de C.V., (Sabinas) a Mexican limited liability company. As a result of the $4 million payment, the book value of the investment in Sabinas was reduced to approximately $14 million. Millennium owns 50% of Sabinas.

Millennium received a $4 million payment on a note receivable from a subsidiary of Mirant Corporation in 2005. We expect to receive the remaining payment of $5 million in July 2006.

UniSource Energy has ceased making loans or equity contributions to Millennium. We anticipate that the funding required to fund Millennium’s remaining commitments will be provided only out of existing Millennium cash or cash returns from Millennium investments. We believe such cash and returns will be adequate to fund Millennium’s remaining commitments.

CRITICAL ACCOUNTING ESTIMATES

In preparing financial statements under Generally Accepted Accounting Principles (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions. UniSource Energy and TEP consider Critical Accounting Estimates to be those that could result in materially different financial statement results if our assumptions regarding application of accounting principles were different. UniSource Energy and TEP describe their Critical Accounting Estimates below. Other significant accounting policies and recently issued accounting standards are discussed in Note 1 of Notes to Consolidated Financial Statements - Nature of Operations and Summary of Significant Accounting Estimates.

ACCOUNTING FOR RATE REGULATION

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 the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), require special accounting treatment for regulated companies to show the effect of regulation. 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,

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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.

TEP

Upon approval by the ACC of a settlement agreement (Settlement Agreement) in November 1999, TEP discontinued application of FAS 71 for its generation operations. TEP continues to apply FAS 71 to its cost-based rate regulated operations, which include the transmission and distribution portions of its business.

TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $163 million at December 31, 2005. Regulatory assets of $31 million are not presently included in the rate base and consequently are not earning a return on investment. These regulatory assets are being recovered through the cost of service or are authorized to be collected in future base rates. TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $225 million at December 31, 2004.

TEP regularly assesses whether it can continue to apply FAS 71 to its cost-based rate regulated 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 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 and UNS Electric

UNS Gas and UNS Electric’s regulatory liabilities, net of regulatory assets, collectively totaled $4 million at December 31, 2005 and at December 31, 2004. UNS Electric has $6 million of regulatory liabilities that are not included in rate base. UNS Gas and UNS Electric regularly assess whether they can continue to apply FAS 71 to their cost-based rate regulated operations. If UNS Gas and UNS Electric stopped applying FAS 71 to their regulated operations, they would write off the related balances of regulatory assets as an expense and regulatory liabilities as income on their income statements. Based on the balances of regulatory liabilities and assets at December 31, 2005, if UNS Gas and UNS Electric had stopped applying FAS 71 to their regulated operations, UNS Gas would record an extraordinary after-tax loss of $2 million and UNS Electric would record an extraordinary after-tax gain of $4 million. UNS Gas and UNS Electric’s cash flows would not be affected if they stopped applying FAS 71 unless a regulatory order limited their ability to recover the cost of their regulatory assets.

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

FAS 143, issued by the FASB, 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. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. A legal obligation can also be associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event. We are required to record a conditional asset retirement obligation at its estimated fair value if that fair value can be reasonably estimated. When the liability is initially recorded, the entity should capitalize a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense as an operating expense in the income statement each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount.

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TEP

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 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. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have a material effect on the liability recorded by TEP at December 31, 2005 as well as the associated cumulative effect of the change in accounting principle recorded. The liabilities associated with conditional asset retirement obligations will be adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on the Consolidated Balance Sheets and Consolidated Statements of Income. For more information regarding the implementation and ongoing application of FIN 47, see Notes 1 and 3 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies and Accounting Change: Accounting for Asset Retirement Obligations. As of December 31, 2005, TEP had a liability of $3 million associated with its conditional asset retirement obligations.

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

TEP 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. TEP has estimated that its share of the cost to remove the Navajo and Four Corners facilities and 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.

In 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. See Item 1. - Business, Future Generating Resources - TEP. 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 has various transmission and distribution lines that operate under land leases and rights of way that contain end dates and restorative clauses. TEP operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, TEP is not recognizing the costs of final removal of the transmission and distribution lines in the financial statements. As of December 31, 2005, TEP had accrued $75 million for the net cost of removal for the interim retirements from its transmission, distribution and general plant. As of December 31, 2004, TEP had accrued $67 million for these removal costs. The amount is recorded as a regulatory liability.

Amounts recorded under FAS 143 are subject to various assumptions and determinations, such as determining whether a legal obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and the credit-adjusted risk-free interest rates to be 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

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result in any change in retail rates since all matters relating to the rate-making treatment of TEP’s generating assets have been determined pursuant to the Settlement Agreement.

UES

UES has various transmission and distribution lines that operate under land leases and rights of way that contain end dates and restorative clauses. UES operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, UES is not recognizing the cost of final removal of the transmission and distribution lines in the financial statements. As of December 31, 2005, UES had accrued $4 million and as of December 31, 2004, UES had accrued $2 million for the net cost of removal for interim retirements from its transmission, distribution and general plant. The amount is recorded as a regulatory liability.

PENSION AND OTHER POST RETIREMENT BENEFIT PLAN ASSUMPTIONS

We record plan assets, obligations, and expenses related to pension and other postretirement benefit plans based on actuarial valuations. These valuations include key assumptions on discount rates, expected returns on plan assets, compensation increases and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally recorded or amortized over future periods. We believe that the assumptions used in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries.

TEP

TEP discounted its future pension plan obligations at December 31, 2005 using a rate of 5.8% for its Salaried, Union Plans and Excess Benefit Plan. The discount rate used at December 31, 2004 was 6.1% for its Salaried and Union Plans and 6.0% for its Excess Benefit Plan. TEP discounted its other postretirement plan obligations using a rate of 5.8% at December 31, 2005, compared with 5.9% at December 31, 2004. TEP determines the discount rate annually based on the rates currently available on high-quality, non-callable, long-term bonds. TEP looks to bonds that receive one of the two highest ratings given by a recognized rating agency whose future cash flows match the timing and amount of expected future benefit payments.

The pension liability and future pension expense both increase as the discount rate is reduced. A decrease in the discount rate results in an increase in the Projected Benefit Obligation (PBO) and the service cost component of pension expense. Additionally, the recognized actuarial loss is significantly impacted by a reduction in the discount rate. Since the PBO increases with the decrease in discount rate, the obligation is that much larger than would normally occur due to normal growth of the plan. This leads to an actuarial loss (or a greater actuarial loss than would occur in the absence of the discount rate change), which is amortized over future periods leading to a greater expense. The resulting change in the interest cost component of pension expense is dependent on the effect that the change in the discount rate has on the PBO and will vary based on employee demographics. The effect of the lower rate used to calculate the interest cost is offset to some degree by a larger obligation. The relative magnitude of these two changes determines whether interest cost will increase or decrease. For TEP’s pension plans, a 25 basis point decrease in the discount rate would increase the accumulated benefit obligation (ABO) by approximately $6 million and the related plan expense for 2006 by approximately $1 million. A similar increase in the discount rate would decrease the ABO by approximately $6 million and the related plan expense for 2006 by approximately $1 million. For TEP’s plan for other postretirement benefits, a 25 basis point change in the discount rate would increase or decrease the accumulated postretirement benefit obligation (APBO) by approximately $2 million. A 25 basis point change in the discount rate would not have a significant impact on the related plan expense for 2006.

TEP calculates the market-related value of plan assets using the fair value of plan assets on the measurement date. TEP assumed that its plans’ assets would generate a long-term rate of return of 8.25% at December 31, 2005 and 8.5% at December 31, 2004. In establishing its assumption as to the expected return on plan assets, TEP reviews the plans’ asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the plans’ actuary that includes both historical performance analysis and forward looking views of the financial markets. Pension expense increases as the expected rate of return on plan assets decreases. A 25 basis point change in the expected return on plan assets would not have a significant impact on pension expense for 2006.

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TEP used an initial health care cost trend rate of 10.0% in valuing its postretirement benefit obligation at December 31, 2005. This rate reflects both market conditions and the plan’s experience. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A 1% increase in assumed health care cost trend rates would increase the postretirement benefit obligation by approximately $5 million and the related plan expense by approximately $1 million. A similar decrease in assumed health care cost trend rates would decrease the postretirement benefit obligation by approximately $4 million and the related plan expense by less than $1 million.

TEP recorded a minimum pension liability in Other Comprehensive Income of approximately $24 million at December 31, 2005, compared with $20 million at December 31, 2004. This increase resulted primarily from a reduction in the assumed discount rate.

Based on the above assumptions, TEP will record pension expense of approximately $10 million and other postretirement benefit expense of $6 million ratably throughout 2006. TEP will make required pension plan contributions of $8 million in 2006. TEP’s other postretirement benefit plan is not funded. TEP expects to make benefit payments to retirees under the postretirement benefit plan of approximately $3 million in 2006.

UES

Concurrent with the acquisition of the Arizona gas and electric system assets from Citizens on August 11, 2003, UES established a pension plan for substantially all of its employees. UES did not assume the pension obligation for employees’ years of service with Citizens.

UES discounted its future pension plan obligations using a rate of 5.9% at December 31, 2005 and 6.1% at December 31, 2004. For UES’ pension plan, a 25 basis point change in the discount rate would have minimal effect on either the ABO or the related pension expense. UES did not record a minimum pension liability or offsetting Intangible Asset at December 31, 2005. At December 31, 2004, UES recorded a minimum pension liability and offsetting Intangible Asset of less than $1 million. UES will record pension expense of $1 million in 2006. UES will make a pension plan contribution of $1 million in 2006.

On the acquisition date, UES assumed the obligation to provide postretirement benefits for a small population of former Citizens employees, both active and retired. The plan is not funded. UES discounted its other postretirement plan obligations using a rate of 5.8% at December 31, 2005, compared with 5.9% at December 31, 2004. Postretirement medical benefit expenses are insignificant to UES’ operations.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES

A derivative financial instrument or other contract derives its value from another investment or designated benchmark. 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, typically for one month, three months, or one year, within established limits to take advantage of favorable market opportunities. In general, TEP enters into forward 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 sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. A portion of TEP’s forward contracts are considered to be normal purchases and sales and, therefore, are not required to be marked to market. However, some of these forward contracts are considered to be derivatives, which TEP marks 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. Some of these forward contracts satisfy the requirements for cash flow hedge accounting and the unrealized gains and losses are recorded in Other Comprehensive Income, a component of Common Stock Equity, rather than being reflected in the income statement.

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). TEP also has agreements to purchase power that are priced using spot market gas prices. These contracts meet the definition of normal purchases and are not required to be marked to market. During 2004 and early 2005, in an effort to minimize price risk on these purchases, TEP entered into commodity price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices. The spot market price in the swap agreements is tied to the same index as the purchases under the SWG and purchased power contracts. These swap agreements, which expire during the summer months through 2008, were entered into with the goal of locking in fixed prices on at least 45%

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and not more than 80% of TEP’s expected summer monthly gas risk prior to entering into the month. The swap agreements are marked to market on a monthly basis; however, since the agreements satisfy the requirements for cash flow hedge accounting, the unrealized gains and losses are recorded in Other Comprehensive Income rather than being reflected in the income statement. As the gains and losses on these cash flow hedges are realized, a reclassification adjustment is recorded in Other Comprehensive Income for realized gains and losses that are included in Net Income.

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 Emission 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. 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 new significant activities after 2005.

The market prices used to determine fair values for TEP and MEG’s derivative instruments at December 31, 2005, are estimated based on various factors including broker quotes, exchange prices, over the counter prices and time value. For TEP’s forward power contracts, a 10% decrease in market prices would result in a decrease in unrealized losses of $1 million, while a 10% increase in market prices would result in an increase in unrealized losses of $1 million. For TEP’s forward contracts that are accounted for as cash flow hedges, a 10% decrease in market prices would result in a $2 million decrease in unrealized losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $2 million increase in unrealized losses reported in Other Comprehensive Income. For TEP’s gas swap agreements, a 10% decrease in market prices would result in a $4 million decrease in unrealized gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $4 million increase in unrealized gains reported in Other Comprehensive Income. For MEG’s remaining trading contracts, a 10% decrease in market prices or a 10% increase in market prices would be immaterial.

Because of the complexity of derivatives, the FASB established a Derivatives Implementation Group (DIG). To date, the DIG has issued more than 100 interpretations to provide guidance in applying Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). As the DIG or the FASB continues to issue interpretations, TEP, UNS Gas and UNS Electric may change the conclusions they have reached and, as a result, the accounting treatment and financial statement impact could change in the future.

See Market Risks - Commodity Price Risk in Item 7A.

UNBILLED REVENUE - TEP AND UES

TEP’s, UNS Gas’s and UNS Electric’s retail revenues include an estimate of MWhs/therms delivered but unbilled at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated MWhs/therms delivered to the MWhs/therms billed to TEP, UNS Gas and UNS Electric retail customers. The excess of estimated MWhs/therms delivered over MWhs/therms billed is then allocated to the retail customer classes based on estimated usage by each customer class. TEP, UNS Gas and UNS Electric then record revenue for each customer class based on the various bill rates for each customer class. Due to the seasonal fluctuations of TEP’s actual load, the unbilled revenue amount increases during the spring

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and summer months and decreases during the fall and winter months. The unbilled revenue amount for UNS Gas sales increases during the fall and winter months and decreases during the spring and summer months, whereas, the unbilled revenue amount for UNS Electric sales increases during the spring and summer months and decreases during the fall and winter months.

PLANT ASSET DEPRECIABLE LIVES - TEP AND UES

We calculate depreciation expense based on our estimate of the useful lives of our plant assets. The estimated useful lives, and resulting depreciation rates used to calculate depreciation expense for the transmission and distribution businesses of TEP, UNS Gas and UNS Electric have been approved by the ACC in prior rate decisions. Depreciation rates for transmission and distribution cannot be changed without ACC approval.

The estimated remaining useful lives of TEP’s generating facilities are based on management’s best estimate of the economic life of the units. These estimates are based on engineering estimates, economic analysis, and statistical analysis of TEP’s past experience in maintaining the stations. For 2004, depreciation expense related to generation assets was $35 million, and our generation assets are currently depreciated over periods ranging from 23 to 70 years from the original in-service dates.

During the second quarter of 2005, a study requested by the participants in the San Juan Generating Station 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. TEP’s annual depreciation expense related to San Juan is expected to decrease by $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 another 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, TEP lengthened the useful lives of various generation assets for periods ranging from 11 to 22 years in July 2004. Consequently, depreciation rates and the corresponding depreciation expense have been revised prospectively to reflect the life extensions. The annual impact of these changes in depreciation rates is a reduction in depreciation expense of $9 million.

DEFERRED TAX VALUATION - TEP AND MILLENNIUM

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 valuation allowance, or reserve, for the deferred tax asset amount 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.

At December 31, 2005 and December 31, 2004, UniSource Energy and TEP had a valuation allowance of $7 million and $8 million relating to net operating loss (NOL) and investment tax credit (ITC) carryforward amounts.

Of the $7 million and $8 million valuation allowance balances at December 31, 2005 and December 31, 2004, $7 million 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 a tax 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.

The remaining $1 million of valuation allowance balance at December 31, 2004, relates to ITC carryforwards at TEP which were not expected to be utilized on tax returns prior to their expiration. Due to anticipated changes to prior year taxable income as a result of current IRS audits, it is now expected that UniSource and TEP will utilize all of the ITC carryforward amounts. Therefore, at December 31, 2005, no valuation allowance on ITC carryforward amounts is required. If in the future UniSource Energy and TEP determine that it is probable that TEP will not use all or a portion of the ITC carryforward amounts, then UniSource Energy and TEP would record additional valuation allowance and recognize tax expense. The primary factor that could cause TEP to record a valuation allowance would be a change in expected future taxable income.

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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’s consolidated income tax returns. If UniSource Energy were unable to recognize such losses through its consolidated income tax return in the foreseeable future, UniSource Energy would be required to write off the $9 million in deferred tax assets. Millennium restructured its ownership in one of these investments in 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.

NEW ACCOUNTING PRONOUNCEMENTS

The FASB recently issued the following Statements of Financial Accounting Standards (FAS) and 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 on January 1, 2006 did not 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. The remaining FSP FIN 46(R) were not applicable to UniSource Energy.

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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, includinga 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.

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