Tucson Electric Power 10-K 2005 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 [ X ]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

 [   ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

   THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               .

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification Number
1-13739	UNISOURCE ENERGY CORPORATION (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000	86-0786732
1-5924	TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000	86-0062700

Securities registered pursuant to Section 12(b) of the Act:
Registrant	Title of Each Class	Name of Each Exchange on Which Registered
UniSource Energy Corporation	Common Stock, no par value and Preferred Share Purchase Rights	New York Stock Exchange Pacific Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant is a well known seasoned issuer, as defined in Rule 405

of the Securities Act.

UniSource Energy Corporation         Yes     X   No

Tucson Electric Power CompanyYes     No     X   

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 of

Section 15(d) of the Securities Act.

UniSource Energy Corporation   Yes     No     X   

      Tucson Electric Power CompanyYes     X   No

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes     X   No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

UniSource Energy CorporationLarge Accelerated Filer   X   Accelerated Filer   Non-accelerated filer   

Tucson Electric Power CompanyLarge Accelerated Filer   Accelerated Filer   Non-accelerated filer   X   

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

UniSource Energy CorporationYes     No     X   

Tucson Electric Power CompanyYes     No     X   

The aggregate market value of UniSource Energy Corporation voting Common Stock held by non-affiliates of the registrant was $1,063,786,264 based on the last reported sale price thereof on the consolidated tape on June 30, 2005.

At February 28, 2006, 34,944,467 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At February 28, 2006, 32,139,435 shares of Tucson Electric Power Company’s common stock, no par value, were outstanding, of which 32,139,434 shares were held by UniSource Energy Corporation.

Documents incorporated by reference: Specified portions of UniSource Energy Corporation’s Proxy Statement relating to the 2006 Annual Meeting of Shareholders are incorporated by reference into Part III.

ii

Table of Contents

 

Definitions	vi
-- PART I --
Item 1. - Business	1
Overview of Consolidated Business	1
TEP Electric Utility Operations	2
Service Area and Customers	2
Generating and Other Resources	4
Fuel Supply	7
Water Supply	8
Transmission Access	8
Rates and Regulation	9
TEP’s Utility Operating Statistics	11
Environmental Matters	12
UNS Gas	13
Service Territory and Customers	13
Gas Supply and Transmission	13
Rates and Regulation	14
Environmental Matters	15
UNS Electric	15
Service Territory and Customers	15
Power Supply and Transmission	15
Rates and Regulation	15
Environmental Matters	16
Global Solar Energy, Inc.	16
Other	16
Employees	17
SEC Reports Available on UniSource Energy’s Website	17
Item 1A. - Risk Factors	18
Item 2. - Properties	22
TEP Properties	22
UES Properties	23
Global Solar Properties	24
Item 3. - Legal Proceedings	24
Item 4. - Submission of Matters to a Vote of Security Holders	24
-- PART II --
Item 5. - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity	25
Item 6. - Selected Consolidated Financial Data	26
UniSource Energy	26
TEP	27
Non-GAAP Measures	28
Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
UniSource Energy Consolidated	31
Outlook and Strategies	31
Results of Operations	32
Contribution by Business Segment	33

iii

Liquidity and Capital Resources	35
Tucson Electric Power Company	41
Results of Operations	41
Factors Affecting Results of Operations	45
Liquidity and Capital Resources	50
UNS Gas	57
Results of Operations	57
Factors Affecting Results of Operations	59
Liquidity and Capital Resources	60
UNS Electric	62
Results of Operations	62
Factors Affecting Results of Operations	63
Liquidity and Capital Resources	63
Global Solar Energy, Inc.	65
Results of Operations	65
Other	66
Results of Operations	66
Factors Affecting Results of Operations	67
Liquidity and Capital Resources	67
Critical Accounting Estimates	68
New Accounting Pronouncements	74
Safe Harbor for Forward-Looking Statements	75
Item 7A. - Quantitative and Qualitative Disclosures about Market Risk	76
Item 8. - Consolidated Financial Statements and Supplementary Data	80
Management’s Report on Internal Controls Over Financial Reporting	80
Reports of Independent Registered Public Accounting Firm	81
UniSource Energy Corporation
Consolidated Statements of Income	84
Consolidated Statements of Cash Flows	85
Consolidated Balance Sheets	86
Consolidated Statements of Capitalization	87
Consolidated Statements of Changes in Stockholders’ Equity	88
Tucson Electric Power Company
Consolidated Statements of Income	89
Consolidated Statements of Cash Flows	90
Consolidated Balance Sheets	91
Consolidated Statements of Capitalization	92
Consolidated Statements of Changes in Stockholders’ Equity	93
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies	94
Note 2. Regulatory Matters	103
Note 3. Accounting Change: Accounting for Asset Retirement Obligations	110
Note 4. Segment and Related Information	113
Note 5. Accounting for Derivative Instruments, Trading Activities and Hedging Activities	116
Note 6. Commitments and Contingencies	118
Note 7. Utility Plant and Jointly-Owned Facilities	123
Note 8. Credit Facilities	125
Note 9. Debt and Capital Lease Obligations	127
Note 10. Fair Value of Financial Instruments	131
Note 11. Stockholders’ Equity	132
Note 12. TEP Wholesale Accounts Receivable and Allowances	133
Note 13. Springerville Expansion	133
Note 14. Income and Other Taxes	134
Note 15. Employee Benefit Plans	138
Note 16. Share-Based Compensation Plans	142
Note 17. UniSource Energy Earnings Per Share (EPS)	145
Note 18. Related Parties	146

iv

Note 19. Subsequent Event	147
Note 20. Supplemental Cash Flow Information	148
Note 21. Quarterly Financial Data (Unaudited)	150
Schedules II - Valuation and Qualifying Accounts	152
Item 9. - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	154
Item 9A. - Controls and Procedures	154
Item 9B. - Other Information	154
-- PART III --
Item 10. - Directors and Executive Officers of the Registrants	155
Item 11. - Executive Compensation	157
Item 12. - Security Ownership of Certain Beneficial Owners and Management	158
Item 13. - Certain Relationships and Related Transactions	158
Item 14. - Principal Accountant Fees and Services	158
-- PART IV --
Item 15. - Exhibits and Financial Statements Schedules	159
Signatures	160
Exhibit Index	164

v

DEFINITIONS

The abbreviations and acronyms used in the 2005 Form 10-K are defined below:

1941 Mortgage	TEP’s Indenture, dated as of April 1, 1941, to JPMorgan Chase Bank, successor trustee, as supplemented and amended, which was satisfied and discharged on June 10, 2005.
1941 Mortgage Bonds	Bonds issued under the 1941 Mortgage.
1992 Mortgage	TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York, successor trustee, as supplemented.
1992 Mortgage Bonds	Bonds issued under the 1992 Mortgage.
ACC	Arizona Corporation Commission.
ACC Holding Company Order	The order approved by the ACC in November 1997 allowing TEP to form a holding company.
AHMSA	Altos Hornos de Mexico, S.A. de C.V. AHMSA owns 50% of Sabinas.
AMT	Alternative Minimum Tax.
APS	Arizona Public Service Company.
Bcf	Billion cubic feet.
Btu	British thermal unit(s).
Capacity	The ability to produce power; the most power a unit can produce or the maximum that can be taken under a contract; measured in MWs.
Citizens	Citizens Communications Company.
Citizens Settlement Agreement	An agreement with the ACC Staff dated April 1, 2003, addressing rate case and financing issues in the acquisition by UniSource Energy of the Citizens’ Arizona gas and electric assets.
Collateral Trust Bonds	Bonds issued under the Indenture of Trust, dated as of August 1, 1998, of TEP to The Bank of New York, successor trustee.
Common Stock	UniSource Energy’s common stock, without par value.
Company or UniSource Energy	UniSource Energy Corporation.
Cooling Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures.
Emission Allowance(s)	An allowance issued by the Environmental Protection Agency which permits emission of one ton of sulfur dioxide or one ton of nitrogen oxide. These allowances can be bought and sold.
Energy	The amount of power produced over a given period of time; measured in MWh.
EPA	The Environmental Protection Agency.
ESP	Energy Service Provider.
Express Line	345-kV circuit connecting Springerville Unit 2 to the Tucson 138-kV system.
FAS 71	Statement of Financial Accounting Standards No. 71: Accounting for the Effects of Certain Types of Regulation.
FAS 133	Statement of Financial Accounting Standards No. 133: Accounting for Derivative Instruments and Hedging Activities, as amended.
FAS 143	Statement of Financial Accounting Standards No. 143: Accounting for Asset Retirement Obligations.
FERC	Federal Energy Regulatory Commission.
Four Corners	Four Corners Generating Station.
Global Solar	Global Solar Energy, Inc., a company that develops and manufactures thin-film photovoltaic cells. Millennium owns 99% of Global Solar.
Haddington	Haddington Energy Partners II, LP, a limited partnership that funds energy-related investments.
Heating Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65.
IDBs	Industrial development revenue or pollution control revenue bonds.
IPS	Infinite Power Solutions, Inc., a company that develops thin-film batteries. Millennium owns 31.4% of IPS.

vi

IRS	Internal Revenue Service.
ISO	Independent System Operator.
ITC	Investment Tax Credit.
kWh	Kilowatt-hour(s).
kV	Kilovolt(s).
LIBOR	London Interbank Offered Rate.
LOC	Letter of Credit.
Luna	Luna Energy Facility.
MEG	Millennium Environment Group, Inc., a wholly-owned subsidiary of Millennium, which manages and trades emission allowances and related financial instruments.
MicroSat	MicroSat Systems, Inc. is a company formed to develop and commercialize small-scale satellites. Millennium currently owns 35%.
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy.
Mimosa	Minerales de Monclova, S.A. de C.V., an owner of coal and associated gas reserves and a supplier of metallurgical coal to the steel industry and thermal coal to the Mexican electricity commission. Sabinas owns 19.5% of Mimosa.
MMBtus	Million British Thermal Units.
MW	Megawatt(s).
MWh	Megawatt-hour(s).
Navajo	Navajo Generating Station.
NOL	Net Operating Loss carryback or carryforward for income tax purposes.
PGA	Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers.
PNM	Public Service Company of New Mexico.
PNMR	PNM Resources.
Powertrusion	POWERTRUSION International, Inc., a company owned 77% by Millennium, which manufactures lightweight utility poles.
PPFAC	Purchased Power and Fuel Adjustment Clause.
PWCC	Pinnacle West Capital Corporation.
Repurchased Bonds	$221 million of fixed-rate tax-exempt bonds that TEP purchased from bondholders on May 11, 2005.
RTO	Regional Transmission Organization.
Rules	Retail Electric Competition Rules.
Sabinas	Carboelectrica Sabinas, S. de R.L. de C.V., a Mexican limited liability company. Millennium owns 50% of Sabinas.
San Carlos	San Carlos Resources Inc., a wholly-owned subsidiary of TEP.
San Juan	San Juan Generating Station.
Sempra	Sempra Energy Trading Company.
SES	Southwest Energy Solutions, Inc., a wholly-owned subsidiary of Millennium.
Settlement Agreement	TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for electric retail competition and transition asset recovery.
Springerville	Springerville Generating Station.
Springerville Coal Handling Facilities Leases	Leveraged lease arrangements relating to the coal handling facilities serving Springerville.
Springerville Common
Facilities	Facilities at Springerville used in common with Springerville Unit 1 and Springerville Unit 2.
Springerville Common Facilities Leases	Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities.
Springerville Unit 1	Unit 1 of the Springerville Generating Station.
Springerville Unit 1 Lease	Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities.
Springerville Unit 2	Unit 2 of the Springerville Generating Station.

vii

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

viii

PART I

This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. You should read forward-looking statements together with the cautionary statements and important factors included in this Form 10-K. (See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Safe Harbor for Forward-Looking Statements). Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions. Forward-looking statements are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions. We express our expectations, beliefs and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be achieved or accomplished. In addition, UniSource Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

ITEM 1. - BUSINESS

OVERVIEW OF CONSOLIDATED BUSINESS

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 substantially all of the outstanding common stock of TEP, and all of the outstanding common stock of 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, including Global Solar Energy, Inc. (Global Solar), a developer and manufacturer of thin-film photovoltaic cells and modules. UED is facilitating the expansion of the Springerville Generating Station (Springerville), but has no significant operations. We conduct our business in four primary business segments - TEP’s Electric Utility segment, UNS Gas, UNS Electric and Global Solar.

The Company is in the process of exiting its Millennium investments. Millennium is in the process of negotiating the sale of its interest in Global Solar, its largest holding.

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

BUSINESS SEGMENT CONTRIBUTIONS

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 (1)	$	48		$	46		$	129
UNS Gas (2)		5			6			1
UNS Electric (2)		5			4			2
Global Solar		(7	)		(5	)		(7	)
Other (3)		(5	)		(5	)		(11	)
Consolidated Net Income	$	46		$	46		$	114

K-1

⁽¹⁾ TEP results in 2003 include an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (FAS 143).

⁽²⁾ 2003 results are for the period from August 11, 2003 to December 31, 2003.

⁽³⁾ Includes: UniSource Energy parent company expenses; interest expense on the note payable from UniSource Energy to TEP; income and losses from other 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.

See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Outlook and Strategies, for a discussion of our plans and strategies and Rates and Regulation, below, for the status of competition in Arizona.

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

TEP ELECTRIC UTILITY OPERATIONS

TEP was incorporated in the State of Arizona in 1963. TEP is the successor by merger in 1964, to a Colorado corporation that was incorporated in 1902. TEP is the principal operating subsidiary of UniSource Energy. In 2005, TEP’s electric utility operations contributed 76% of UniSource Energy’s operating revenues and comprised 82% of its assets.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to more than 385,000 retail customers in Southeastern Arizona. TEP’s service territory consists of a 1,155 square mile area and includes a population of approximately 956,000 in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP holds a franchise to provide electric distribution service to customers in the Cities of Tucson and South Tucson. These franchises expire in 2026 and 2017, respectively. TEP also sells electricity to other utilities and power marketing entities in the western U.S.

RETAIL CUSTOMERS

In 2005, TEP’s number of retail customers increased by 3% and total retail energy consumption increased by approximately 4%. The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years.

	2005			2004			2003
Residential		41	%		40	%		41	%
Commercial		21	%		21	%		20	%
Non-mining Industrial		26	%		26	%		27	%
Mining		9	%		10	%		9	%
Public Authority		3	%		3	%		3	%

TEP expects that its peak demand, number of retail customers and retail energy consumption will increase 2 - 3% annually through 2009. The retail energy consumption by customer class through 2009 is expected to be similar to the 2005 distribution.

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. Certain portions of the Arizona Corporation Commission’s (ACC) rules that enabled ESPs to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2005. In February 2006, the ACC Staff requested that a proceeding be opened to address the issue of retail electric competition. 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. Even though some of TEP’s retail customers may, in the future, be able to choose other energy

K-2

providers, the forecasted customer growth rates referred to above would continue to apply to its distribution business. See Rates and Regulation, State, below.

Sales to Large Industrial Customers

TEP provides electric utility service to a diverse group of commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases and other governmental entities. Local, regional, and national economic factors can impact the financial condition and operations of TEP’s large industrial customers. Such economic conditions may directly impact energy consumption by large industrial customers, and may indirectly impact residential and small commercial sales and revenues if employment levels and consumer spending are affected.

Two of TEP’s largest retail customers are in the copper mining industry. TEP has contracts with these customers to provide electric service at negotiated rates. In 2005, the average revenue per kWh sold to TEP’s mining customers was $0.047. These contracts expire in December of 2006 and 2008. TEP’s sales to mining customers depend on a variety of factors including changes in supply and demand in the world copper market, the financial health of its mining customers and the economics of self-generation. In 2005, Asarco, one of our mining customers, was subject to a four-month labor strike. As a result, electricity sales to Asarco were approximately 20% less than kWh sales in 2004. Copper prices have risen steadily since 2003 and average U.S. copper prices reached a five-year high of $2.16 per pound in December 2005. Higher copper prices have led to increased mining operations, increased rates which are tied to copper prices and an increase in kWh sales of TEP’s mining customers of 2%.

WHOLESALE BUSINESS

TEP’s electric utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale sales transactions are made on both a firm and interruptible basis. A firm contract requires that, TEP must supply the power (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions. See Other Purchases and Interconnections, below.

TEP typically uses its own generation to serve the requirements of its retail and long-term wholesale customers. Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified portfolio approach to provide a balance between long-term, mid-term and spot energy sales. When TEP expects to have excess coal generating capacity and energy (usually in the first, second and fourth calendar quarters), its wholesale sales consist primarily of three types of sales:

(1) Sales under long-term contracts for periods of more than one year. TEP currently has long-term contracts with three entities to sell firm capacity and energy: Salt River Project Agricultural Improvement and Power District (SRP), which expires in May 2011, the Navajo Tribal Utility Authority, which expires in December 2009, and the Tohono O’odham Utility Authority, which expires in August 2009.

(2) Short-term sales. Under forward contracts, TEP commits to sell a specified amount of capacity or energy at a specified price over a given period of time, typically for one-month, three-month or one-year periods. Under short-term sales, TEP sells energy in the daily or hourly markets at fluctuating spot market prices and makes other non-firm energy sales.

(3) Sales of transmission service.

TEP purchases power in the wholesale markets when economic. TEP may enter into contracts: (a) to purchase energy under long-term contracts to serve retail load and long-term wholesale contracts, (b) to purchase capacity or energy during periods of planned outages or for peak summer load conditions, and (c) to purchase energy to resell to certain wholesale customers under load and resource management agreements. Finally, TEP may purchase energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when it is more economical than generating its own energy.

Over the past three years, both the natural gas and western U.S. wholesale electricity markets experienced some price spikes and volatility due to severe winter weather, gas production and storage concerns and, in 2005, hurricane activity in the Gulf of Mexico. TEP cannot predict, however, whether gas and wholesale electricity prices will remain elevated and what the impact will be on TEP’s sales and revenues in the future.

K-3

TEP expects to continue to be a participant in the wholesale energy markets, primarily by making sales and purchases in the short-term and forward markets. TEP expects the market price in the western U.S. and demand for capacity and energy to continue to be influenced by the following factors, among others:

· the availability and price of natural gas;

· weather;

· continued population growth;

· economic conditions in the western U.S.;

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

· the extent of electric utility restructuring;

· the effect of FERC regulation of wholesale energy markets;

· the availability of hydropower;

· transmission constraints; and

· environmental requirements and the cost of compliance.

See Item 7. -Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Western Energy Markets, for additional discussion of TEP’s wholesale marketing activities.

GENERATING AND OTHER RESOURCES

TEP GENERATING RESOURCES

At December 31, 2005, TEP owned or leased 2,004 MW of net generating capability as set forth in the following table:

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

⁽¹⁾ Springerville Unit 1 and Sundt unit 4 are leased by TEP.

⁽²⁾ Excludes 788 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2005, total owned capacity was 1,468 MW and leased capacity was 536 MW.

The Springerville Generating Station also includes the Springerville Coal Handling Facilities and the Springerville Common Facilities. In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. In 1985, TEP sold and leased back a 50% interest in the Springerville Common Facilities. The other 50% interest is included in the Springerville Unit 1 leases.

K-4

TEP obtains approximately 600 MW, or 30% of its generating capacity from jointly-owned facilities at the San Juan, Four Corners, and Navajo Generating Stations in New Mexico and northern Arizona.

The Sundt Generating Station and the internal combustion turbines located in Tucson are designated as “must-run generation” facilities. Must-run generation units are those which are required to run in certain circumstances to maintain distribution system reliability and to meet local load requirements.

In 2004, TEP purchased a one-third interest in the partially constructed 570-MW natural gas-fired Luna Energy Facility (Luna) located in southern New Mexico. Luna is expected to provide TEP with 190 MW of power and be operational by the summer of 2006. See Future Generating Resources - TEP, Luna Energy Facility, below.

See Note 9 of Notes to Consolidated Financial Statements, Debt and Capital Lease Obligations, and Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for more information regarding the Springerville and Sundt leases.

POWER EXCHANGE AGREEMENTS

In January 2005, TEP entered into a one year exchange agreement with Sempra Energy Trading Company (Sempra). TEP provided firm system capacity of 40 MW to Sempra during February through May 2005. Sempra then provided TEP with firm system capacity of 50 MW during June through September 2005.

OTHER PURCHASES AND INTERCONNECTIONS

TEP purchases additional electric energy from other utilities and power marketers. The amount of energy purchased varies substantially from time to time depending on the demand for energy, the cost of purchased energy compared with TEP’s cost of generation and the availability of such energy.

TEP is a member of various regional reserve sharing, reliability and power sharing organizations. These relationships allow TEP to call upon other utilities during emergencies such as plant outages and system disturbances, and reduce the amount of reserves TEP is required to carry.

TEP has the following power purchase agreement that it entered into in 2003 as part of the ACC’s Track B competitive energy bidding process:

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

Springerville was originally designed for four units. Springerville Unit 3, and, if constructed, Unit 4, will each consist of a 400 MW coal-fired, base-load generating facility at the same site as Springerville Units 1 and 2. Once built, Tri-State will lease 100% of Unit 3 from a financial owner. In conjunction with the expansion of the Springerville Generating Station, TEP entered into a power purchase contract with Tri-State for up to 100 MW of capacity from Tri-State’s system resources. This contract with Tri-State is for up to five years, beginning with commercial operation of Unit 3, expected in the third quarter of 2006. Tri-State has the ability to permanently reduce the 100 MW of capacity it will sell to TEP in 25 MW increments, by giving at least 90 days notice. TEP anticipates that any power purchased under this contract will be sold in the wholesale markets.

K-5

PEAK DEMAND AND RESOURCES

Peak Demand	2005			2004			2003			2002			2001
	-MW-
Retail Customers - Net One Hour		2,225			2,088			2,060			1,899			1,840
Firm Sales to Other Utilities		342			187			171			228			151
Coincident Peak Demand (A)		2,567			2,275			2,231			2,127			1,991
Total Generating Resources		2,004			2,004			2,003			2,002			1,999
Other Resources (1)		788			454			486			308			217
Total TEP Resources (B)		2,792			2,458			2,489			2,310			2,216
Total Margin (B) - (A)		225			183			258			183			225
Reserve Margin (% of Coincident Peak Demand)		9	%		8	%		12	%		9	%		11	%

⁽¹⁾ Other Resources include firm power purchases and interruptible retail and wholesale loads.

TEP’s retail sales are influenced by several factors, including seasonal weather patterns and the overall economic climate. The peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand has grown at an average annual rate of approximately 4% from 2001 to 2005.

The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s margin is the difference between total energy resources and coincident peak demand, and the reserve margin is the ratio of margin to coincident peak demand. TEP maintains a minimum reserve margin in excess of 7% to comply with reliability criteria set forth by the Western Electricity Coordinating Council (WECC, formerly the Western Systems Coordinating Council). TEP’s actual reserve margin in 2005 was 9%.

Forecasted retail peak demand for 2006 is approximately 2,242 MW, compared with actual peak demand of 2,225 MW in 2005. Except for certain peak hours during the summer, TEP believes it has sufficient resources to meet expected demand in 2006 with its existing generation capacity and power purchase agreements.

FUTURE GENERATING RESOURCES - TEP

TEP is required to supply energy for customers who do not choose other energy providers. Continued regulatory developments and an Arizona Court of Appeals decision invalidating certain portions of the ACC rules on retail competition and related market pricing, have raised uncertainty about the status and pace of retail competition in Arizona. See Rates and Regulation, Arizona Court of Appeals Decision Invalidating Certain Retail Electric Competition Rules 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Competition, below.

Luna Energy Facility

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

TEP paid $13 million for its one-third interest in 2004. In 2005, TEP spent $22 million for its one-third share of the costs to complete construction of Luna and purchase necessary inventory items and expects to spend an additional $14 million in 2006. TEP anticipates that internal cash flows will fund its share of the costs related to the plant.

K-6

Peaking Resources

TEP will continue to add peaking resources in the Tucson area as needed based upon our forecasts of retail and firm wholesale load, as well as the statewide transmission infrastructure. TEP currently forecasts that additional peaking resources of 75 MW may be needed in 2010 and 150 MW in 2013.

FUEL SUPPLY

TEP purchases coal and natural gas in the normal course of business to fuel its generating plants. The majority of its coal supplies are purchased under long-term contracts, which result in more predictable prices.

Fuel information is provided below on a delivered to the boiler basis:

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

TEP’S COAL AND GAS SUPPLY

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and Colorado. Four Corners, Navajo and San Juan Stations are mine mouth generating stations located adjacent to the coal reserves. The coal supply for Springerville requires approximately 200 miles of railroad transportation, while the coal supply for Sundt is approximately 1,300 miles away. All of the contracts for coal and rail contain price adjustment provisions that are expected to increase the prices at a rate less than the expected growth of inflation. The average cost per ton of coal for 2005, 2004, and 2003 was $32.39, $30.20, and $30.31, respectively.

Station	Coal Supplier	Year Contract Terminates	Average Sulfur Content	Coal Obtained From (A)
Springerville	Peabody Coalsales Company	2020	0.9%	Lee Ranch Coal Company
Four Corners	BHP Billiton	2016	0.8%	Navajo Indian Tribe
San Juan	San Juan Coal Company	2017	0.8%	Federal and State Agencies
Navajo	Peabody Coalsales Company	2011	0.6%	Navajo and Hopi Indian Tribes
Sundt	Various approved suppliers	2006	-	Various locations

(A) Substantially all of the suppliers’ mining leases extend at least as long as coal is being mined in economic quantities.

TEP Operated Generating Facilities

TEP is the sole owner (or lessee) and operator of the Springerville Units 1 and 2 and Sundt Unit 4 Generating Stations. The coal supplies for the Springerville Units 1 and 2 are transported by railroad from northwestern New Mexico and from Colorado for Sundt Unit 4. TEP expects coal reserves to be sufficient to supply the estimated requirements for Units 1 and 2 for their presently estimated remaining lives. TEP has entered into agreements for the purchase and transportation of coal from Colorado to Sundt Unit 4 through December 2006. The total amount paid under these agreements depends on the number of tons of coal purchased and transported. The long-term rail contract for coal from New Mexico for Sundt Unit 4 is in effect until the earliest of 2015 or the remaining life of Unit 4. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual Obligations andNote 6 of Notes to Consolidated Financial Statements - Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.

K-7

Generating Facilities Operated by Others

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan, where coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining lives of the stations.

San Juan Coal Company, the coal supplier to San Juan, commenced development of the underground mine in 2000. The underground mine did not achieve full station supply until 2003 due to geological issues. PNM, TEP and San Juan Coal Company have begun a review of long term coal cost projections given the production issues encountered and the experience gained from mining operations.

Natural Gas

TEP typically uses generation from its facilities fueled by natural gas and purchased power, in addition to energy from its coal-fired facilities, to meet the summer peak demands of its retail customers and 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, gas-indexed purchased power and spot market purchases with fixed price contracts for a maximum of three years. TEP purchases its remaining gas fuel needs from the Permian Basin, and purchased power in the spot and short-term markets.

TEP entered into a Gas Procurement Agreement with Southwest Gas Corporation (SWG) in 2001, with a primary term of five years. Starting in January 1, 2006, interim supply terms were put into place. This arrangement goes from month to month until terminated by either party with 30 days notice and does not include a minimum volume obligation.

WATER SUPPLY

Drought conditions in the Four Corners region, combined with water usage in upper New Mexico, have resulted in decreasing water levels in Navajo Lake that indirectly supplies water to the San Juan and Four Corners Generating Stations. These conditions may affect the water supply of the plants in the future if adequate moisture is not received in the watershed that supplies the area. Although the moisture levels in the region during the 2004-2005 winter seasons were above historic averages, drought conditions still persist. TEP has a 50% ownership interest in each of San Juan units 1 and 2 (322 MW capacity) and a 7% ownership interest in each of Four Corners units 4 and 5 (110 MW capacity).

PNM, the operating agent for San Juan, has negotiated supplemental water contracts with BHP Billiton and the Jicarilla Apache Nation to assist San Juan in meeting its water requirements in the event of a water shortage.

Drought conditions within the southwestern region, combined with increased water usage in Arizona, Nevada and southern California, have caused water levels to significantly recede at Lake Powell, which supplies operating water for the Navajo Generating Station. Work has begun to lower the water intakes in Lake Powell, which will help minimize the exposure of water loss to the plant due to continuing drought conditions. This project is expected to be completed in the first quarter of 2007. TEP’s expected share of the total cost is approximately $2 million based on its 7.5% ownership interest in Navajo Units 1, 2, and 3 (168 MW capacity).

TRANSMISSION ACCESS

TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers.

Tucson to Nogales Transmission Line

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

K-8

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

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

Based on the alternative proposals and passage of time since it approved the location of the line, the ACC, in January 2005, ordered TEP to review the status of electric service reliability in Nogales, Arizona and the need for the 345-kV line. The ACC also indicated that it would review any new information regarding the location of the proposed transmission line.

In December 2005, an Administrative Law Judge (ALJ) for the ACC issued a recommended opinion and order reaffirming the ACC’s original position requiring the construction of the Tucson to Nogales transmission line. After a hearing on the issue, the ACC directed the ALJ to amend the recommendation to direct the Line Siting Committee of the ACC to gather facts related to options for improving service reliability in Nogales, Arizona. TEP expects the ACC to address the ALJ’s amended recommended opinion and order in the first half of 2006.

RATES AND REGULATION

The FERC and the ACC regulate portions of TEP’s utility accounting practices and electricity rates. The FERC regulates the terms and prices of TEP’s transmission services and wholesale electricity sales. In 1996, TEP filed a tariff at FERC governing the rates, terms and conditions of open access transmission services. In 1997, TEP was granted a FERC tariff to sell power at market based rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties.

State

Historically, the ACC determined TEP’s rates for retail sales of electric energy on a “cost of service” basis, which was designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable rate of return on TEP’s “fair value rate base.” Fair value rate base was generally determined by reference to the original cost and the reconstruction cost (net of depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and other items, plus a working capital component. Over time, rate base was increased by additions to utility plant in service and reduced by depreciation and retirements of utility plant.

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 and approved the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Rates, for more information.

Track A and Track B Proceedings

During 2002 and 2003 the ACC reexamined circumstances that had changed since it approved the Rules in 1999. The outstanding issues were divided into two groups. Track A related primarily to the divestiture of generation assets while Track B related primarily to the competitive energy bidding process.

Track A

The ACC’s Track A Order eliminated the requirement in the TEP Settlement Agreement that TEP transfer its generation assets to a subsidiary. As a result, generation assets remain at TEP. At the same time, the ACC ordered the parties, including TEP, to develop a competitive bidding process, and reduced the amount of power to be acquired in the competitive bidding process to only that portion not supplied by TEP’s existing resources.

K-9

Track B

The ACC Track B Order defined the competitive bidding process TEP must use to obtain capacity and energy requirements beyond what is supplied by TEP’s existing resources for the period 2003 through 2006. The Track B Order did not address TEP’s purchased power or asset acquisitions occurring subsequent to the 2003 competitive solicitation. See Generating and Other Resources, Other Purchases and Interconnections, above.

Arizona Court of Appeals Decision Invalidating Certain Retail Electric Competition Rules

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. Based on this decision, we expect that the ACC will address the competition rules in an administrative proceeding. We cannot predict what changes, if any, the ACC will make to the competition rules.

See Note 2 of the Notes to Consolidated Financial Statements - Regulatory Matters, for more information on the Settlement Agreement.

K-10

TEP’s UTILITY OPERATING STATISTICS

	For Years Ended December 31,
	2005		2004		2003		2002		2001
Generation and Purchased Power - kWh (000)
Remote Generation (Coal)		10,059,315		10,159,729		10,182,706		10,067,069		10,362,211
Local Tucson Generation (Oil, Gas & Coal)		1,165,001		1,174,500		1,082,058		1,402,504		1,820,783
Purchased Power		1,638,737		1,322,084		1,153,305		1,329,574		3,656,978
Total Generation and Purchased Power		12,863,053		12,656,313		12,418,069		12,799,147		15,839,972
Less Losses and Company Use		806,168		821,008		778,285		791,852		747,941
Total Energy Sold		12,056,885		11,835,305		11,639,784		12,007,295		15,092,031
Sales - kWh (000)
Residential		3,633,226		3,459,750		3,389,744		3,181,030		3,159,504
Commercial		1,855,432		1,787,472		1,689,014		1,605,148		1,591,942
Industrial		2,302,327		2,226,314		2,245,340		2,254,174		2,297,476
Mining		842,881		829,028		701,638		692,448		1,053,152
Public Authorities		241,119		240,426		250,038		256,867		257,155
Total - Electric Retail Sales		8,874,985		8,542,990		8,275,774		7,989,667		8,359,229
Electric Wholesale Sales		3,181,900		3,292,315		3,364,010		4,017,628		6,732,802
Total Electric Sales		12,056,885		11,835,305		11,639,784		12,007,295		15,092,031
Operating Revenues (000)
Residential	$	330,614	$	315,402	$	309,807	$	291,390	$	285,808
Commercial		192,966		186,625		175,559		168,838		166,139
Industrial		165,988		161,338		160,276		161,749		162,523
Mining		39,749		38,549		28,022		28,072		41,940
Public Authorities		17,559		17,427		17,839		18,672		18,763
Total - Electric Retail Sales		746,876		719,341		691,503		668,721		675,173
Electric Wholesale Sales		178,428		159,918		151,030		157,108		921,280
Other Revenues		12,166		10,039		9,018		8,618		8,508
Total Operating Revenues	$	937,470	$	889,298	$	851,551	$	834,447	$	1,604,961
Customers (End of Period)
Residential		350,628		341,870		334,131		326,847		318,976
Commercial		33,534		32,923		32,369		31,767		31,194
Industrial		673		676		676		695		705
Mining		2		2		2		2		2
Public Authorities		61		61		61		61		61
Total Retail Customers		384,898		375,532		367,239		359,372		350,938
Average Retail Revenue per kWh Sold (cents)
Residential		9.1		9.1		9.1		9.2		9.0
Commercial		10.4		10.4		10.4		10.5		10.4
Industrial and Mining		6.5		6.5		6.4		6.4		6.1
Average Retail Revenue per kWh Sold		8.4		8.4		8.4		8.4		8.1
Average Revenue per Residential Customer	$	954	$	933	$	937	$	902	$	906
Average kWh Sales per Residential Customer		10,484		10,231		10,249		9,842		10,015

K-11

ENVIRONMENTAL MATTERS

TEP is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities. TEP believes that all existing facilities are in compliance and will be in compliance with expected environmental regulations.

The 1990 Federal Clean Air Act Amendments (CAAA), through the Acid Rain Program, required reductions of sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions. All of TEP’s generating facilities (except 142 MW of its internal combustion turbines) are affected.

Emission Allowances

TEP’s generating units affected by CAAA Phase II have been allocated SO₂ Emission Allowances based on past operational history. Each allowance gives the owner the right to emit one ton of SO₂. Generating units subject to CAAA Phase II must hold Emission Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years. TEP has Emission Allowances in excess of what is required to comply with the CAAA Phase II SO₂ regulations. 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. Potential changes to the allocation of SO₂ allowances may impact these expectations in future years.

Title V of the CAAA requires that all of TEP’s generating facilities obtain more complex air quality permits. All TEP facilities (including those jointly owned and operated by others) have obtained these permits. TEP received Title V permits for the Springerville and Sundt generating stations which expired in 2004. Because TEP has submitted a permit renewal application, under its Title V permits, TEP can continue to operate the plants. Approval of TEP’s renewal application is expected in 2006. TEP must pay an annual emission-based fee for each generating facility subject to a Title V permit. These emission-based fees are included in the CAAA compliance expenses discussed below. The CAAA also requires multi-year studies of visibility impairment in specified areas and studies of hazardous air pollutants. The results of these studies will impact the development of future regulation of electric utility generating units. These activities are ongoing and involve the gathering of information not currently available.

State Regulation

Arizona and New Mexico have adopted regulations restricting the emissions from existing and future coal, oil and gas-fired plants. TEP believes that all existing generating facilities are in compliance with all existing state regulations. These regulations are in some instances more stringent than those adopted by the Environmental Protection Agency (EPA). The principal generating units of TEP are located relatively close to national parks, monuments, wilderness areas and Indian reservations. These areas have relatively high air quality and TEP could be subject to control standards that relate to the “prevention of significant deterioration” of visibility and tall stack limitation rules. In addition, the ACC mandated under the Environmental Portfolio Standard (EPS) that TEP derive a percentage of its total retail energy sold from new solar resources or environmentally-friendly renewable electricity technologies. TEP has generated electricity from solar and other environmentally-friendly renewable technologies per the EPS rules using revenues from the EPS surcharge collected from customers. The ACC is currently considering changes to the EPS rules. We do not believe that any future changes in the EPS rules will significantly impact TEP. SeeNote 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies, TEP Contingencies, Litigation and Claims Related to San Juan Generating Station.

Mercury Emissions

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

K-12

Capital and Operating Costs

TEP capitalized $1 million in 2005, $9 million in 2004 and $11 million in 2003 in construction costs to comply with environmental requirements and expects to capitalize $3 million in 2006 and $10 million in 2007. In addition, TEP recorded expenses of $11 million in 2005, $9 million in 2004 and $8 million in 2003 related to environmental compliance, including the cost of lime used to scrub the stack gas. TEP expects environmental expenses to be $11 million in 2006. TEP may incur additional costs to comply with recent and future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may result in a reduction in operating efficiency.

In order to meet Title V permit requirements in connection with the construction of Springerville Unit 3, the Unit 3 project paid for approximately $90 million of capital expenditures related to pollution control equipment upgrades on Springerville Unit 1 and Unit 2. See Note 6 of Notes to Consolidated Financial Statements - Commitments and Contingencies, Resolution of Springerville Generating Station Complaint.

UNS GAS

On August 11, 2003, UniSource Energy completed the purchase of the Arizona gas and electric system assets from Citizens for a total of $223 million, comprised of the base purchase price plus other operating capital adjustments and transaction costs. UES was formed to hold the common stock of UNS Gas and UNS Electric, which operate these gas and electric system assets, respectively.

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 139,000 retail customers in Mohave, Yavapai, Coconino, and Navajo Counties in northern Arizona, as well as Santa Cruz County in southeast Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 751,000 in 2005.

UNS Gas’ customer base is primarily residential. Total revenues derived from residential customers were approximately 58% in 2005, while sales to other retail customer classes accounted for approximately 28% of total revenues. Approximately 14% of total revenues in 2005 were derived from gas transportation services and a Negotiated Sales Program (NSP). UNS Gas is supplying natural gas transportation service to the 600 MW Griffith Power Plant located near Kingman, Arizona, under a 20-year contract which expires in 2021. UNS Gas also supplies natural gas to some of its large transportation customers, through an NSP approved by the ACC. One half of the margin earned on these NSP sales is retained by UNS Gas, while the other half benefits retail customers through a credit to the purchased gas adjustor (PGA) mechanism which reduces the gas commodity price.

GAS SUPPLY AND TRANSMISSION

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 term of the agreement is automatically extended for one year 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. The market price for gas supplied by BP will vary based upon the period during which the commodity 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’s hedging positions at December 31, 2005 are summarized below:

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

K-13

Most of the gas distributed by UNS Gas in Arizona is procured from the San Juan Basin in the Four Corners region and delivered on the El Paso and Transwestern interstate pipeline systems. UNS Gas has firm transportation agreements with El Paso Natural Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its customers’ demands.

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. The current contract with Transwestern expires in February 2007. In February 2006, UNS Gas extended its firm transportation contract with Transwestern through February 2012.

The aggregate annual minimum transportation charges are expected to be approximately $7 million for the EPNG contract; $3 million for the Transwestern contract through February 2007; and $2 million for the Transwestern contract from 2007-2012. These costs are passed through to our customers via the PGA. See Rates and Regulation, below.

RATES AND REGULATION

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

Purchased Gas Adjustor

The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjuster. The difference between UNS Gas’ actual gas and transportation costs and the cost of gas and transportion that are 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. 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 Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, for more information.

2006 General Rate Case Filing

Under the terms of the UES Settlement Agreement, UNS Gas may not file for a general rate increase until July 2006 and any resulting rate increase may not become effective until August 1, 2007. UNS Gas expects to file a general rate case in July 2006.

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ENVIRONMENTAL MATTERS

UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities. UNS Gas believes that all existing facilities are in compliance with all existing regulations and will be in compliance with expected environmental regulations.

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is an electric transmission and distribution company serving approximately 89,000 retail customers in Mohave and Santa Cruz counties. These counties had a population of approximately 232,000 in 2005.

UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers. Peak demand for 2005 was 412 MW.

POWER SUPPLY AND TRANSMISSION

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. Payments under the contract are usage based, with no fixed customer or demand charges. UNS Electric imports the power it purchases from PWCC into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric’s transmission capacity agreement with WAPA expires in February 2008. Under the terms of the agreement, UNS Electric’s aggregate minimum fixed transmission charges are expected to be $5 million in 2006. UNS Electric also has a long-term electric transmission capacity agreement with WAPA that expires in 2011. Under the terms of this contract, the aggregate minimum transmission payments are $1 million per year.

UNS Electric owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona. The Valencia plant consists of three gas and diesel-fueled combustion turbine units and provides approximately 48 MW of peaking resources. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas. Under the PWCC agreement, Valencia will be dispatched by PWCC when needed for local reliability or when it is economic relative to other PWCC resources.

As a consequence of the delays in the construction of the Tucson to Nogales transmission line, UNS Electric is building a 20 MW gas-fired combustion turbine at the Valencia site to improve electric service reliability. The turbine should be operational by mid-2006.

RATES AND REGULATION

UNS Electric is regulated by the ACC with respect to retail electric rates, quality of service, the issuance of securities, and transactions with affiliated parties, and by the FERC with respect to wholesale power contracts and interstate transmission service. UNS Electric’s retail electric rates include a purchase power and fuel adjustment clause (PPFAC), which allows for UNS Electric to recover the actual costs of its power purchases.

2006 General Rate Case Filing

Under the terms of the UES Settlement Agreement, UNS Electric may not file a general rate increase until July 2006 and any resulting rate increase may not become effective until August 1, 2007. UNS Electric expects to file a general rate case in the second half of 2006.

State Regulation

Like TEP, UNS Electric is subject to the ACC’s EPS rules. The ACC is currently considering changes to the EPS rules, however we do not believe that any future changes in the EPS rules will significantly impact UNS Electric. See TEP Electric Utility Operations, Environmental Matters, State Regulation, above.

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ENVIRONMENTAL MATTERS

UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities. UNS Electric believes that all existing facilities are in compliance with all existing regulations and will be in compliance with expected environmental regulations.

GLOBAL SOLAR ENERGY, INC.

Global Solar Energy, Inc. (Global Solar) develops and manufactures light weight thin-film photovoltaic cells and panels. Global Solar’s target markets have included military, space and commercial applications. Millennium owns 99% of Global Solar, and at December 31, 2005, Global Solar represented 1% of UniSource Energy’s total assets. Millennium is in the process of negotiating the sale of its interest in Global Solar, its largest holding.

OTHER

Other Millennium Investments

Through affiliates, Millennium holds investments in unregulated energy and emerging technology companies. At December 31, 2005, Millennium’s assets, excluding Global Solar, represented 1% of UniSource Energy’s total assets. 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. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other, Liquidity and Capital Resources.

Millennium’s other consolidated investments include:

Southwest Energy Solutions, Inc. (SES), a wholly-owned Millennium subsidiary, provides electrical contracting services in Arizona to commercial, industrial and governmental customers in both high voltage and inside wiring capacities and meter reading services to TEP.

Millennium Environmental Group, Inc. (MEG), a wholly-owned Millennium subsidiary established in September 2001, manages and trades emission allowances, and other environmental related products including derivative instruments. MEG is in the process of winding down its activities and does not anticipate engaging in any significant new activities after 2005.

Nations Energy Corporation (Nations Energy), a wholly-owned subsidiary of Millennium, developed and invested in independent power projects worldwide and has been inactive since 2001. Nations Energy has one remaining investment, a 32% equity interest in an independent power producer that owns and operates a 43 MW power plant near Panama City, Panama.

Equity Method Millennium Investments

Millennium has the following equity method investments:

Haddington Energy Partners II, LP (Haddington) is a limited partnership that funds energy-related investments. A member of the UniSource Energy Board of Directors has an investment in Haddington and is a managing director of the general partner of the limited partnership. Millennium committed $15 million in capital, excluding fees, to Haddington in exchange for approximately 31% ownership. As of December 31, 2005, Millennium has invested $13 million in Haddington and received distributions of $15 million. At December 31, 2005, Millennium had $2 million remaining on this commitment, which is expected to be funded in 2006.

Valley Ventures III, LP (Valley Ventures) is a venture capital fund that focuses on investments in information technology, microelectronics and biotechnology, primarily within the southwestern U.S. Another member of the UniSource Energy Board of Directors was a general partner of the company that manages the fund until January 1, 2006, at which time the Board member terminated his role and interest as a general partner but maintained a non-voting financial interest in the company. Millennium committed $6 million, including fees, to the fund and owns approximately 15% of the fund. As of December 31, 2005, Millennium has not received any

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distributions from Valley Ventures and had $2 million remaining on this commitment, which is expected to be funded over the next two to three years.

Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas) is a Mexican limited liability company created to develop up to 800 MW of coal-fired generation in the Sabinas region of Coahuila, Mexico. Sabinas also owns 19.5% of Minerales de Monclova, S.A. de C.V. (Mimosa). Mimosa is an owner of coal and associated gas reserves and a supplier of metallurgical coal to the Mexican steel industry and thermal coal to the major electric utility in Mexico. Millennium owns 50% of Sabinas. Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and affiliates also own 50%. UniSource Energy’s Chairman, President and Chief Executive Officer is a member of the Board of Directors of AHMSA. Since 1999, both AHMSA and Mimosa are parties to a suspension of payments procedure, under applicable Mexican law, which is the equivalent of a U.S. Chapter 11 proceeding. Under certain circumstances, Millennium has the right to sell (a put option) its interest in Sabinas to an AHMSA affiliate for $20 million plus any accrued service fee. These circumstances include failure of Sabinas to reach financial closing on the generation project within a specified time.

EMPLOYEES (As of December 31, 2005)

TEP had 1,287 employees, of which approximately 54% are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A collective bargaining agreement between the IBEW and TEP was ratified in January 2006 and expires in January 2009.

UNS Gas had 202 employees, of which 114 employees were represented by IBEW Local No. 1116 and 6 employees were represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2009 and February 2010, respectively.

UNS Electric had 157 employees, of which 30 employees were represented by the IBEW Local No. 387 and 102 employees were represented by the IBEW Local No. 769. The existing agreement with the IBEW Local No. 387 expires in February 2010 and the agreement with IBEW Local No. 769 expires in July 2007.

Global Solar had 84 employees, none of whom are represented by a bargaining unit.

SES had 217 employees, of which approximately 95% are represented by unions. Of the employees represented by unions, 179 are represented by IBEW Local No. 1116, 15 by IBEW Local No. 769, 11 by IBEW Local No. 570 and 2 by IBEW Local No. 387. The existing agreements expire as follows: IBEW Local No. 1116, October 2006; IBEW Local No. 769, July 2007; IBEW Local No. 570, May 2006; and IBEW Local No. 387, February 2010.

SEC REPORTS AVAILABLE ON UNISOURCE ENERGY’S WEBSITE

UniSource Energy and TEP make available their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after they electronically file them with, or furnish them to, the SEC. These reports are available free of charge through UniSource Energy’s website address: http://www.uns.com. A link from UniSource Energy’s website to these SEC reports is accessible as follows: At the UniSource Energy main page, select Investor Relations from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page. UniSource Energy’s code of ethics, and any amendments made to the code of ethics, is also available on UniSource Energy’s website.

Information contained at UniSource Energy’s website is not part of any report filed with the SEC by UniSource Energy or TEP.

The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The SEC website address is http://www.sec.gov. Interested parties may also read and copy any materials UniSource Energy or TEP file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0030.

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ITEM 1A. - RISK FACTORS

The business and financial results of UniSource Energy and TEP are subject to a number of risks and uncertainties, including those set forth below and in other documents we file with the Securities and Exchange Commission.

Regulatory and other restrictions limit the ability of TEP, UNS Gas and UNS Electric to make distributions to UniSource Energy.

UniSource Energy is a holding company that is dependent on the earnings and distributions of funds from its subsidiaries to service its debt and pay dividends to shareholders.

ACC restrictions on TEP, UNS Gas and UNS Electric include:

· a limit on the payment of dividends to 75% of earnings unless common equity equals at least 40% of total capitalization (excluding capital lease obligations); and

· a restriction on lending or transferring funds or issuing securities without ACC approval.

As of December 31, 2005, the ratio of common equity to total capitalization, as calculated for ACC purposes, was 40.5% for TEP, 44% for UNS Gas and 43% for UNS Electric. UniSource Energy does not expect to receive distributions from UNS Gas or UNS Electric before 2008 due to the growth of these businesses.

The Federal Power Act also restricts electric utilities’ ability to pay dividends out of funds that are properly included in their capital account. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe there is a reasonable basis for TEP to pay dividends from current year earnings. However, the FERC could attempt to stop TEP from paying further dividends or could seek to impose additional restrictions on the payment of dividends.

TEP, UNS Gas and UNS Electric must be in compliance with their respective debt agreements to make dividend payments to UniSource Energy.

TEP’s retail rates are capped through 2008, which could negatively impact TEP’s results of operations, net income and cash flows.

TEP’s current retail rates were established under a Settlement Agreement approved by the ACC in 1999. Under the Settlement Agreement, TEP’s rates are capped until December 31, 2008. Operational failures or unscheduled outages at TEP’s generating stations, especially during peak seasons, could result in unanticipated power purchases which could significantly increase the cost of serving TEP’s retail load. Operational failures or damage to TEP’s facilities, from storms or other events, could result in increased operating and capital expenses.

In the event that any power purchase, natural gas or coal costs, operation and maintenance or other expenses increase, TEP could be adversely affected unless it were able to find ways of offsetting these increased costs with other cost reductions or increases in income and cash flow or otherwise seek rate recovery of such increased costs under emergency provisions of the Settlement Agreement. TEP may not be able to recover such costs.

Uncertainty exists as to what methodology the ACC will use to set TEP’s retail rates after December 31, 2008, which could negatively impact TEP’s results of operations, net income and cash flows.

There is disagreement between the participants in TEP’s regulatory proceedings about what is to happen to the rates TEP charges for generation service after December 31, 2008. TEP believes the Settlement Agreement requires it charge market-based generation service rates while other participants, including ACC staff, disagree.

The Settlement Agreement also requires TEP to record and amortize a $450 million transition recovery asset (TRA) and collect the balance from customers though a fixed charge (CTC). Based on current projections of retail sales, the TRA is expected to be fully amortized by mid-2008. The fixed CTC currently produces revenues of slightly less than one cent per kWh sold, or approximately $80 million. If TEP is required to reduce its retail rates

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by the amount of the fixed CTC, and is not allowed to charge market rates for its generation services, TEP’s retail revenues will decrease approximately 12% relative to revenues from current retail rates. 

Restrictions on rate increases and the ability to recover fuel costs at UNS Gas could negatively impact its liquidity, cash flows and net income.

An ACC order restricts UNS Gas from filing a general rate case until July 2006 and any resulting rate increase may not become effective until August 1, 2007.

UNS Gas is subject to operational risks, including operational failures or damage to facilities which could result in unplanned operation, maintenance and capital expenditures. UNS Gas could be adversely affected unless it was able to find ways of offsetting these increased costs.

UNS Gas has an automatic gas price adjustment mechanism, known as the Purchased Gas Adjustor (PGA) through which increases or decreases in the cost of gas can be passed on to customers. The PGA is subject to a cap on how much the factor can change in a 12-month period and anything above the cap must be approved by the ACC.

In 2005, the cost of gas represented more than 70% of UNS Gas’ total operating costs. Natural gas prices may fluctuate substantially over relatively short periods of time and expose UNS Gas to commodity price risks to the extent they cannot be collected from customers in a timely manner.

If UNS Gas is unable to recover its fuel costs or other costs of providing service in a timely manner, its liquidity could be adversely affected and it may be more difficult for UNS Gas to satisfy its obligations, including purchasing and paying for gas. In addition, it may be more difficult for UNS Gas to comply with the obligations and restrictive covenants of its debt agreements, which limit its ability to borrow money, and could result in an event of default.

Restrictions on rate increases and the ability to recover purchased power and fuel costs at UNS Electric could negatively impact its liquidity, cash flows and net income.

An ACC order restricts UNS Electric from filing a general rate case until July 2006 and any resulting rate increase may not become effective until August 1, 2007.

Operational failures or damage to UNS Electric’s facilities from storms or other events, could result in increased operating and capital expenditures. UNS Electric could be adversely affected unless it was able to find ways of offsetting these increased costs.

The expiration of UNS Electric’s power supply agreement will require UNS Electric to find alternate sources for its energy needs, which may not be recovered through rates.

UNS Electric has a full requirements power supply agreement for 100% of its customers’ energy needs that expires May 2008. UNS Electric pays a fixed price per MWh for the power it purchases under the agreement. In 2005, UNS Electric sold approximately 1.5 million MWh to its retail customers. In 2008, UNS Electric will need to have a replacement source of energy for its customer base, which grew at 4% in 2005.

UNS Electric has a Purchased Power and Fuel Adjustor mechanism (PPFAC) through which increases or decreases in the cost of power and fuel can be passed on to customers. The cost of UNS Electric’s existing power supply agreement is being fully recovered through the PPFAC. The ACC must approve any change to the PPFAC.

UniSource Energy’s utility subsidiaries’ revenues, results of operations and cash flows are seasonal, and are subject to weather conditions, economic conditions and customer usage patterns, which are beyond the Company’s control.

TEP typically earns the majority of its operating revenue and net income in the third quarter because of higher air conditioning usage by its retail customers due to hot summer weather. Furthermore, TEP typically reports limited net income in the first quarter because of relatively mild winter weather in its retail service territory. UNS Gas’ peak sales occur in the winter; UNS Electric’s peak sales occur in the summer. Cool summers or warm winters may adversely affect the utility subsidiaries’ operating revenues and net income by reducing sales.

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Changes in federal energy regulation may affect TEP, UNS Gas and UNS Electric’s results of operations, net income and cash flows.

TEP, UNS Gas and UNS Electric are subject to comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric and gas utility industries and the ways in which these industries are regulated. UniSource Energy’s utility subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC). The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale prices.

Deregulation or restructuring of the electric utility industry may result in increased competition resulting in an erosion of TEP and UNS Electric’s retail customer base and reduce TEP’s wholesale revenues.

In 1999, the ACC approved rules proving a framework for the introduction of retail electric competition in Arizona. As a result of the energy crisis in California in 2000 and 2001 and the volatility of natural gas prices, the competitive retail market in Arizona that was anticipated in 1999 did not materialize. In addition, a 2005 Arizona Court of Appeals ruling held certain portions of the ACC’s retail competition rules invalid.

Currently, none of TEP or UNS Electric’s customers are receiving energy from other providers, however we cannot predict if retail competition will enter the Arizona market.

Competition in wholesale markets has greatly increased due to increased participation by utilities, non-utility generators, independent power producers and other wholesale power marketers and brokers. Since 2001, electric generating capacity in Arizona has increased 62% to 25,500 MW. Approximately 9,700 MW of the new capacity is from gas-fired generators.

Increased competition combined with increased supply and fewer creditworthy counterparties could reduce the prices at which TEP sells electricity in the wholesale market. In 2005, TEP’s wholesale revenues were $178 million or 19% of TEP’s total revenues.

UniSource Energy and its subsidiaries have a substantial amount of indebtedness which could adversely affect its business and results of operations.

UniSource Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. At December 31, 2005, total debt (including capital lease obligations) to total capitalization for UniSource Energy and its subsidiaries was 76%. The substantial amount of indebtedness of UniSource Energy and its subsidiaries could:

· require UniSource Energy and its subsidiaries to dedicate a substantial portion of their cash flow to pay principal and interest on its debt, which could reduce the funds available for working capital, capital expenditures, acquisitions and other general corporate purposes;

· make UniSource Energy and its subsidiaries more vulnerable to restrictions imposed by new governmental regulations as well as changes in general economic, industry and competitive conditions;

· limit UniSource Energy and its subsidiaries ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of its business strategy or other purposes;

· limit the ability of the subsidiaries to pay dividends to UniSource Energy; and

· make it more difficult for UniSource Energy and its subsidiaries to comply with the obligations of its debt instruments, and any failure to comply with the obligations of any debt instruments, including financial and other restrictive covenants, could result in an event of default under the agreements.

The terms of UniSource Energy’s and its subsidiaries’ existing debt instruments and future debt instruments may restrict UniSource Energy’s current and future operations, particularly the ability to respond to changes in its business or to take certain actions.

The UniSource Energy Credit Agreement, the TEP Credit Agreement and other existing debt instruments contain a number of restrictive covenants that impose significant operating and financial restrictions on UniSource

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Energy, including restrictions on the ability to engage in acts that may be in UniSource Energy’s best long-term interests. The TEP Credit Agreement includes financial covenants, including requirements to maintain certain minimum cash coverage ratios and not to exceed certain maximum total leverage ratios. The UniSource Credit Agreement contains similar financial covenants.

The operating and financial restrictions and covenants in UniSource Energy’s and its subsidiaries’ existing debt agreements and any future financing agreements may adversely affect UniSource Energy’s ability to finance future operations or capital needs or to engage in other business activities.

The cost of renewing or purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power, could adversely affect TEP’s results of operations, net income and cash flows.

TEP, under separate sale and leaseback arrangements, leases the following generation facilities:

· Springerville Unit 1;

· Sundt Unit 4;

· Springerville Coal Handling Facilities; and

· Springerville Common Facilities.

TEP may renew the leases or purchase the asset when the leases expire at various times between 2011 and 2021. These renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time.

In addition, in the event that the debt relating to the leases of the 50% undivided interest in the Springerville common facilities is not refinanced by June 2006, such leases will terminate, and TEP will be required to repurchase such interest in the common facilities for approximately $125 million.

UniSource Energy’s utility subsidiaries are subject to numerous environmental laws and regulations which may increase their cost of operations or expose them to environmentally-related litigation and liabilities.

UniSource Energy’s utility subsidiaries are subject to numerous federal, state and local environmental regulations affecting present and future operations, including regulations regarding air emissions, water quality, wastewater discharges, solid waste and hazardous waste. Many of these regulations arise from TEP’s use of coal as the primary fuel for energy generation. Existing environmental regulations may be revised or new regulations may be adopted or become applicable to UniSource Energy’s utility subsidiaries. Compliance with existing or new environmental laws and regulations can result in increased capital, operating and other costs.

TEP is also contractually obligated to pay a portion of its environmental reclamation costs at generating stations in which it has a minority interest and possibly at the mines that supply these generating stations. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.

TEP may be required to redeem significant amounts of its outstanding tax-exempt bonds.

TEP has financed a portion of its utility plant assets with tax-exempt bonds for which the exemption from income taxes requires that the financed facilities be used for the local furnishing of electric energy. Approximately $359 million of these bonds were outstanding as of December 31, 2005. Various events, including, in certain circumstances, the formation of an RTO or an independent system operator, asset divestitures, changes in tax laws or changes in system operations, could cause TEP to have to redeem or defease some or all of these bonds which would likely require the issuance and sale of higher cost taxable debt securities in the same or a greater principal amount.

TEP may not be permitted to construct a Tucson to Nogales transmission line and TEP or UNS Electric may be required to find alternate ways to improve reliability in UNS Electric’s Santa Cruz service area.

In 2001, TEP entered into an agreement to build a 62-mile transmission line from Tucson to Nogales, Arizona, in response to an order from the ACC to improve reliability to UNS Electric’s retail customers in Nogales.

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Required regulatory approvals have delayed the construction of the transmission line, and in 2005, the ACC initiated proceedings to review the status of service in Nogales and need for the 345-kV line.

If TEP does not receive required approvals, it may be required to expense a portion of the $11 million it has incurred through December 31, 2005, in land acquisition, engineering and environmental expenses. In such an event, TEP or UNS Electric may be required to make additional expenditures to improve reliability. In the event TEP or UNS Electric were not able to recover such expenditures, their results of operations and net income could be adversely effected.

ITEM 2. - PROPERTIES

TEP PROPERTIES

TEP’s transmission facilities, located in Arizona and New Mexico, transmit electricity from TEP’s remote electric generating stations at Four Corners, Navajo, San Juan and Springerville to the Tucson area for use by TEP’s retail customers (see Item 1. - Business - Generating and Other Resources). The transmission system is interconnected at various points in Arizona and New Mexico with a number of regional utilities. TEP has arrangements with approximately 120 companies to interchange generation capacity and transmission of energy.

As of December 31, 2005, TEP owned, or participated in, an overhead electric transmission and distribution system consisting of:

· 512 circuit-miles of 500-kV lines;

· 1,098 circuit-miles of 345-kV lines;

· 364 circuit-miles of 138-kV lines;

· 434 circuit-miles of 46-kV lines; and

· 2,645 circuit-miles of lower voltage primary lines.

The underground electric distribution system is comprised of 4,022 cable-miles. TEP owns approximately 77% of the poles on which the lower voltage lines are located. Electric substation capacity consisted of 199 substations with a total installed transformer capacity of 6,063,772 kilovolt amperes.

The electric generating stations (except as noted below), operating headquarters, warehouse and service center are located on land owned by TEP. The electric distribution and transmission facilities owned by TEP are located:

· on property owned by TEP;

· under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights which are generally subject to termination;

· under or over private property as a result of easements obtained primarily from the record holder of title; or

· over American Indian reservations under grant of easement by the Secretary of Interior or lease by American Indian tribes.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

Springerville is located on land parcels held by TEP under a long-term surface ownership agreement with the State of Arizona.

Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Nation, respectively. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired easements and leases for transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP has also acquired easements for transmission facilities, related to San Juan, Four Corners, and Navajo, across the Zuni, Navajo and Tohono O’odham Indian Reservations.

TEP’s rights under these various easements and leases may be subject to defects such as:

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 · possible conflicting grants or encumbrances due to the absence of or inadequacies in the recording laws or record systems of the Bureau of Indian Affairs and the American Indian tribes;

· possible inability of TEP to legally enforce its rights against adverse claimants and the American Indian tribes without Congressional consent; or

· failure or inability of the American Indian tribes to protect TEP’s interests in the easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants.

These possible defects have not interfered and are not expected to materially interfere with TEP’s interest in and operation of its facilities.

TEP, under separate sale and leaseback arrangements, leases the following generation facilities (which do not include land):

· coal handling facilities at Springerville;

· a 50% undivided interest in the Springerville Common Facilities;

· Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities; and

· Sundt Unit 4 and related common facilities.

See Note 9 of Notes to Consolidated Financial Statements, Debt and Capital Lease Obligations and Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for additional information on TEP’s capital lease obligations.

Substantially all of the utility assets owned by TEP are subject to the lien of the 1992 Mortgage. Springerville Unit 2, which is owned by San Carlos Resources Inc., a wholly-owned subsidiary of TEP (San Carlos), is not subject to the lien.

UES PROPERTIES

UNS Gas

As of December 31, 2005, UNS Gas’ transmission and distribution system consisted of approximately 78 miles of steel transmission mains, 4,121 miles of steel and plastic distribution mains, and 143,244 customer service lines.

UNS Electric

As of December 31, 2005, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 224 circuit-miles of 69-kV transmission lines, and 3,251 circuit-miles of underground and overhead distribution lines. UNS Electric also owns 38 substations having a total installed capacity of 1,177,550 kilovolt amperes and the 48 MW Valencia plant.

The gas and electric distribution and transmission facilities owned by UNS Gas and UNS Electric are located:

· on property owned by UNS Gas or UNS Electric;

· under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights which are generally subject to termination; or

· under or over private property as a result of easements obtained primarily from the record holder of title.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

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GLOBAL SOLAR PROPERTIES

Global Solar’s 31,000 square foot manufacturing facility is leased from Millennium and is located in Tucson, Arizona.

ITEM 3 - LEGAL PROCEEDINGS

See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Operations, for litigation related to ACC orders and retail competition.

We discuss other legal proceedings in Note 6 ofNotes to Consolidated Financial Statements, Commitments and Contingencies.

Cross-Complaints in Wholesale Electricity Antitrust Cases I and II

           In late 2000, various California municipalities and citizens filed suits against Duke Energy Trading and Marketing, L.L.C., Reliant Energy Services, Inc. and other large suppliers of wholesale electricity alleging that Duke, Reliant, and the other large suppliers violated antitrust laws by colluding to effect the price of electricity in the California wholesale electricity market.  These actions were subsequently consolidated in San Diego Superior Court in March 2002 as Wholesale Electricity Antitrust Cases I and II.

            Duke and Reliant responded by filing cross-complaints against TEP and numerous other wholesale electricity market participants in April 2002.  The cross complaints allege that cross-defendants sold power in significant amounts at prices the plaintiffs allege were excessive, and as participants in power sales, cross-defendants are also liable for plaintiffs alleged damages.  The entire action was removed to the United States District Court for the Southern District of California in May 2002.  The plaintiffs responded to the removal by filing a motion for remand, and in December 2002, the District Court remanded the case back to state court.

            Duke and Reliant appealed the District Court’s remand order and requested that the order be stayed pending resolution of their appeal.  In December 2004, the Ninth Circuit affirmed the District Court’s order and the case was remanded to the state court. Once there, the defendants filed a joint motion to dismiss to the master complaint and TEP and other cross-defendants filed a joint motion to dismiss to the cross-complaints.

On October 3, 2005, the state court sustained defendants’ joint motion to dismiss and dismissed the master complaint without leave to amend. Before a hearing was held on the cross-defendants’ motion to dismiss, Duke and Reliant entered into stipulations for dismissal of their cross-complaints with TEP and the other cross-defendants. The orders of dismissal will be entered upon final approval of Duke and Reliant’s pending settlement with the plaintiffs. Although plaintiffs have appealed the dismissal of the master complaint and that appeal is pending, the dismissal of the cross-complaints against TEP and the other cross-defendants will be final once the Duke and Reliant settlements are approved by the state court.

City of Tacoma

            In June 2004, the City of Tacoma, Washington filed a lawsuit (City of Tacoma v. American Electric Power Services Corporation, et al. (U.S. District Ct.  W. D. Wash.)) against TEP and various other electricity generators and marketers alleging that the defendants violated antitrust laws by colluding to affect the price of electricity in the Pacific Northwest from May 2000 through 2001.  These claims are similar to those alleged in the antitrust cases against TEP and other wholesale electricity market participants described above in Cross-Complaints in Wholesale Electricity Antitrust Cases I and II.  In September 2004, the case was transferred to the United States District Court for the Southern District of California.  TEP along with other defendants filed a joint motion to dismiss and the motion was granted on February 11, 2005. The City of Tacoma appealed the dismissal to the Ninth Circuit and the appeal is now pending.

            TEP believes these claims are without merit and intends to vigorously contest them.

ITEM 4. - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

K-24

PART II

ITEM 5. - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF COMMON EQUITY

Stock Trading

UniSource Energy’s Common Stock is traded under the ticker symbol UNS. It is listed on the New York Stock Exchange and the Pacific Exchange. On February 28, 2006, the closing price was $30.41, with 11,887 shareholders of record. UniSource Energy did not purchase any shares of its common stock during the fourth quarter of 2005.

Dividends

UniSource Energy’s Board of Directors currently expects to continue to pay regular quarterly cash dividends on our common stock subject, however, to the directors’ evaluation of our financial condition, earnings, cash flows and dividend policy. On February 10, 2006, UniSource Energy’s Board of Directors indicated its desire to achieve, over the next several years, a dividend payout level of approximately 50 percent of net income.

TEP pays dividends on its common stock after its Board of Directors declares them. UniSource Energy is the primary shareholder of TEP’s common stock. UniSource Energy relies on dividends from its subsidiaries, primarily TEP, to declare and pay dividends to its shareholders. The ACC does not allow TEP to pay dividends in excess of 75% of its annual earnings until TEP’s common equity equals 40% of capitalization (excluding capital lease obligations). See Note 11 of Notes to Consolidated Financial Statements, Stockholders’ Equity for a discussion of limitations on UniSource Energy’s subsidiaries' ability to pay dividends to UniSource Energy.

See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Dividends on Common Stock.

Common Stock Dividends and Price Ranges

	2005						2004
Quarter:	Market Price per Share of Common Stock (1)				Dividends Declared		Market Price per Share of Common Stock (1)				Dividends Declared
	High		Low				High		Low
First	$	34.80	$	24.30	$	0.19	$	24.74	$	24.11	$	0.16
Second		31.98		28.10		0.19		24.93		24.15		0.16
Third		33.92		30.50		0.19		24.94		24.20		0.16
Fourth		33.86		29.89		0.19		24.88		22.90		0.16
Total					$	0.76					$	0.64

⁽¹⁾ UniSource Energy’s Common Stock price as reported in the consolidated reporting system.

On February 10, 2006, UniSource Energy declared a cash dividend of $0.21 per share on its Common Stock. The dividend will be paid March 15, 2006 to shareholders of record at the close of business February 21, 2006.

TEP declared and paid cash dividends of $46 million in 2005, $32 million in 2004 and $80 million in 2003.

Convertible Senior Notes

In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Financing Activities.

K-25

ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA

UniSource Energy	2005			2004			2003			2002			2001
	- In Thousands - (except per share data)
Summary of Operations
Operating Revenues (1)	$	1,229,535		$	1,168,978		$	972,755		$	839,576		$	1,613,304
Loss Before Income Taxes of Millennium Energy Businesses	$	(9,449	)	$	(6,920	)	$	(26,350	)	$	(30,702	)	$	(14,455	)
Income Before Extraordinary Item andAccounting Change (1)	$	46,770		$	45,919		$	46,470		$	34,928		$	63,369
Net Income (1) (2)	$	46,144		$	45,919		$	113,941		$	34,928		$	63,839
Basic Earnings per Share:
Before Extraordinary Item & Accounting Change	$	1.35		$	1.34		$	1.38		$	1.04		$	1.90
Net Income	$	1.33		$	1.34		$	3.37		$	1.04		$	1.91
Diluted Earnings per Share:
Before Extraordinary Item & Accounting Change	$	1.30		$	1.31		$	1.35		$	1.02		$	1.86
Net Income	$	1.28		$	1.31		$	3.32		$	1.02		$	1.87
Shares of Common Stock Outstanding
Average		34,798			34,380			33,828			33,665			33,398
End of Year		34,874			34,255			33,788			33,579			33,502
Year-end Book Value per Share	$	17.69		$	16.95		$	16.47		$	13.60		$	13.17
Cash Dividends Declared per Share	$	0.76		$	0.64		$	0.60		$	0.50		$	0.40
Financial Position
Total Utility Plant - Net	$	2,171,461		$	2,081,137		$	2,069,215		$	1,835,904		$	1,832,164
Investments in Lease Debt and Equity	$	156,301		$	170,893		$	178,789		$	191,867		$	84,459
Other Investments and Other Property	$	68,759		$	85,035		$	109,570		$	123,238		$	98,288
Total Assets	$	3,126,780		$	3,175,518		$	3,122,719		$	2,885,954		$	2,925,937
Long-Term Debt (3)	$	1,212,420		$	1,257,595		$	1,286,320		$	1,128,963		$	802,804
Non-Current Capital Lease Obligations		665,737			701,931			762,968			801,611			853,793
Common Stock Equity		616,741			580,718			556,472			456,640			441,133
Total Capitalization	$	2,494,898		$	2,540,244		$	2,605,760		$	2,387,214		$	2,097,730
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	276,410		$	306,979		$	263,396		$	176,437		$	215,379
Capital Expenditures	$	(203,428	)	$	(167,017	)	$	(137,282	)	$	(112,706	)	$	(121,735	)
Other Investing Cash Flows		32,860			10,828			(213,450	)		(158,184	)		4,888
Net Cash Flows From Investing Activities	$	(170,568	)	$	(156,189	)	$	(350,732	)	$	(270,890	)	$	(116,847	)
Net Cash Flows From Financing Activities	$	(115,191	)	$	(98,028	)	$	97,674		$	(42,773	)	$	(33,382	)
Ratio of Earnings to Fixed Charges(4)		1.49			1.43			1.37			1.36			1.77

⁽¹⁾ In 2003, Operating Revenues, Income Before Extraordinary Item and Accounting Change and Net Income include results from UES for the period from August 11, 2003 to December 31, 2003.

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⁽²⁾ Net income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of FIN 47 in 2005, an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the implementation of FAS 143 in 2003 and $0.5 million for the Cumulative Effect of Accounting Change from the implementation of FAS 133 in 2001.

⁽³⁾ TEP’s tax-exempt variable rate bonds in the amount of $329 million are backed by LOCs issued under TEP’s Credit Agreement. TEP’s obligations under the Credit Agreement are collateralized with 1992 Mortgage Bonds. In November 2002, TEP obtained new LOCs in the amount of $341 million to replace the LOCs provided under its then existing Credit Agreement that would have expired on December 30, 2002. The 2002 LOCs would have expired in 2006. Accordingly, these IDBs were classified as short-term debt at December 31, 2001 and classified as long-term debt at December 31, 2002. TEP entered into a new Credit Agreement in May 2005, which provided LOCs that expire in 2010.

⁽⁴⁾ For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, plus interest expense, and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expense on indebtedness.

See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA

TEP		2005			2004			2003			2002			2001
		-Thousands of Dollars-
Summary of Operations
Operating Revenues	$	937,470		$	889,298		$	851,551		$	834,447		$	1,604,961
Income Before Extraordinary Item and Accounting Change	$	48,893		$	46,127		$	61,442		$	55,390		$	77,308
Net Income (1)	$	48,267		$	46,127		$	128,913		$	55,390		$	77,778
Financial Position
Total Utility Plant - Net	$	1,866,622		$	1,816,782		$	1,832,156		$	1,835,904		$	1,832,164
Investments in Lease Debt and Equity	$	156,301		$	170,893		$	178,789		$	191,867		$	84,459
Other Investments and Other Property	$	24,238		$	23,393		$	41,285		$	21,358		$	21,416
Total Assets	$	2,575,435		$	2,742,168		$	2,767,047		$	2,808,810		$	2,824,555
Long-Term Debt(2)	$	821,170		$	1,097,595		$	1,126,320		$	1,128,410		$	801,924
Non-Current Capital Lease Obligations		665,299			701,405			762,323			801,508			853,447
Common Stock Equity		558,646			414,510			406,054			353,832			337,082
Total Capitalization	$	2,045,115		$	2,213,510		$	2,294,697		$	2,283,750		$	1,992,453
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	243,013		$	275,151		$	260,989		$	206,991		$	261,169
Capital Expenditures	$	(149,906	)	$	(129,505	)	$	(121,854	)	$	(103,307	)	$	(103,913	)
Other Investing Cash Flows		21,001			3,743			11,408			(151,035	)		(8,861	)
Net Cash Flows From Investing Activities	$	(128,905	)	$	(125,762	)	$	(110,446	)	$	(254,342	)	$	(112,774	)
Net Cash Flows From Financing Activities	$	(173,882	)	$	(101,444	)	$	(141,059	)	$	(56,551	)	$	(77,427	)
Ratio of Earnings to Fixed Charges(3)		1.60			1.52			1.51			1.60			1.85

⁽¹⁾ Net Income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of FIN 47 in 2005, an after-tax gain of $67 million for the Cumulative Effect of Accounting change from the implementation of FAS 143 in 2003 and $0.5 million for the Cumulative Effect of Accounting Change from the implementation of FAS 133 in 2001.

⁽²⁾ TEP’s tax-exempt variable rate bonds in the amount of $329 million are backed by LOCs issued under TEP’s Credit Agreement. TEP’s obligations under the Credit Agreement are collateralized with 1992 Mortgage Bonds. In

K-27

November 2002, TEP obtained new LOCs in the amount of $341 million to replace the LOCs provided under its then existing Credit Agreement that would have expired on December 30, 2002. The 2002 LOCs would have expired in 2006. Accordingly, these IDBs were classified as short-term debt at December 31, 2001 and classified as long-term debt at December 31, 2002. TEP entered into a new Credit Agreement in May 2005, which provided LOCs that expire in 2010.

⁽³⁾ For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expense on indebtedness.

Note: Disclosure of earnings per share information for TEP is not presented as the common stock of TEP is not publicly traded.

See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations.

NON-GAAP MEASURES

Adjusted EBITDA

Adjusted EBITDA represents EBITDA excluding the cumulative effect of accounting change which is a non-cash item. EBITDA is earnings before interest, taxes, depreciation and amortization. Adjusted EBITDA is presented here as a measure of liquidity because it can be used as an indication of a company’s ability to incur and service debt and is commonly used as an analytical indicator in our industry. Adjusted EBITDA measures presented may not be comparable to similarly titled measures used by other companies. Adjusted EBITDA is not a measurement presented in accordance with United States generally accepted accounting principles (GAAP), and we do not intend Adjusted EBITDA to represent cash flows from operations as defined by GAAP. Adjusted EBITDA should not be considered to be an alternative to cash flows from operations or any other items calculated in accordance with GAAP or an indicator of our operating performance.

UniSource Energy and TEP believe Adjusted EBITDA, which is a non-GAAP financial measure, provides useful information to investors as a measure of liquidity. The most directly comparable GAAP measure to Adjusted EBITDA is Net Cash Flows from Operating Activities.

Adjusted EBITDA and Net Cash Flows from Operating Activities

UniSource Energy	2005		2004		2003		2002
	- Millions of Dollars -
Adjusted EBITDA	$	438	$	439	$	395	$	366
Net Cash Flows from Operating Activities	$	276	$	307	$	263	$	176

TEP	2005		2004		2003		2002
	- Millions of Dollars -
Adjusted EBITDA	$	400	$	411	$	403	$	399
Net Cash Flows from Operating Activities	$	243	$	275	$	261	$	207

Reconciliation of Adjusted EBITDA to Cash Flows from Operations

UniSource Energy	2005		2004		2003		2002
	- Millions of Dollars -
Adjusted EBITDA (1)	$	438	$	439	$	395	$	366
Amounts from the Income Statements:
Less:  Income Taxes		33		34		12		18
Total Interest Expense		160		168		167		155
Changes in Assets and Liabilities and Other Non-Cash Items		31		70		47		(17	)
Net Cash Flows from Operating Activities	$	276	$	307	$	263	$	176

K-28

TEP	2005		2004		2003		2002
	- Millions of Dollars -
Adjusted EBITDA (1)	$	400	$	411	$	403	$	399
Amounts from the Income Statements:
Less:  Income Taxes		34		35		21		36
Total Interest Expense		140		157		161		154
Changes in Assets and Liabilities and Other Non-Cash Items		17		56		40		(2	)
Net Cash Flows from Operating Activities	$	243	$	275	$	261	$	207

⁽¹⁾ Adjusted EBITDA was calculated as follows:

UniSource Energy	2005			2004		2003		2002
	- Millions of Dollars -
Net Income	$	46		$	46	$	114	$	35
Amounts from the Income Statements:
Less: Cumulative Effect of Accounting Change		(1	)		-		67		-
Plus:  Income Taxes		33			34		12		18
Total Interest Expense		160			168		167		155
Depreciation and Amortization		136			135		131		128
Amortization of Transition Recovery Asset		56			50		32		24
Depreciation included in Fuel and Other O&M Expense (See Note 20 of Notes to Consolidate Financial Statements)		6			6		6		6
Adjusted EBITDA	$	438		$	439	$	395	$	366

TEP	2005			2004		2003		2002
	- Millions of Dollars -
Net Income	$	48		$	46	$	129	$	55
Amounts from the Income Statements:
Less: Cumulative Effect of Accounting Change		(1	)		-		67		-
Plus:  Income Taxes		34			35		21		36
Total Interest Expense		140			157		161		154
Depreciation and Amortization		115			117		121		124
Amortization of Transition Recovery Asset		56			50		32		24
Depreciation included in Fuel and Other O&M Expense (See Note 20 of Notes to Consolidated Financial Statements)		6			6		6		6
Adjusted EBITDA	$	400		$	411	$	403	$	399

K-29

Net Debt and Total Debt and Capital Lease Obligations - TEP

Net Debt represents the current and non-current portions of TEP’s long-term debt and capital lease obligations less investment in lease debt. We have subtracted investment in lease debt because it represents TEP’s ownership of the debt component of its own capital lease obligations. Net Debt measures presented may not be comparable to similarly titled measures used by other companies. Net Debt is not a measurement presented in accordance with GAAP and we do not intend Net Debt to represent debt as defined by GAAP. You should not consider Net Debt to be an alternative to debt or any other items calculated in accordance with GAAP. We believe Net Debt, which is a non-GAAP measure, provides useful information to investors as a measure of TEP’s debt and capital lease obligations.

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

Reconciliation of Total Debt and Capital Lease Obligations to Net Debt

As of December 31,	2005			2004			2003			2002
	- Millions of Dollars -
Long-Term Debt	$	821		$	1,098		$	1,126		$	1,182
Current Portion - Long-Term Debt		-			2			2			2
Total Debt		821			1,100			1,128			1,130
Capital Lease Obligations		665			701			762			802
Current Portion - Capital Lease Obligations		49			54			50			43
Total Debt and Capital Lease Obligations		1,535			1,855			1,940			1,975
Investment in Lease Debt		(156	)		(171	)		(179	)		(192	)
Net Debt	$	1,379		$	1,684		$	1,761		$	1,783

K-30

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, and all of the outstanding common stock of 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 August 2003. UES, through its two operating subsidiaries, UNS Gas and UNS Electric, provides gas and electric service to 30 communities in northern and southern Arizona. Millennium is composed of unregulated businesses, including Global Solar Energy a developer and manufacturer of thin-film photovoltaic cells and modules. UED is facilitating the expansion of the Springerville Generating Station, but has no significant operations. We conduct our business in these four primary business segments - TEP’s Electric Utility Segment, UNS Gas, UNS Electric and Global Solar.

UniSource Energy is in the process of exiting its Millennium investments. Millennium is in the process of negotiating the sale of its interest in Global Solar, its largest holding.

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. Although representing approximately 1% of UniSource Energy’s total assets, losses from Global Solar had a significant impact on earnings reported by UniSource Energy in 2005 and 2004. 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 other investments, excluding Global Solar; 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.

· 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.

K-31

· 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.

· Complete the sale of Global Solar.

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 Net Income of $46 million in 2005. This compares with Net Income of $46 million in 2004, and $114 million in 2003. Net Income in 2003 includes an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (FAS 143). Income Before Cumulative Effect of Accounting Change was $46 million in 2003. 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.

K-32

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 (1)	$	48		$	46		$	129
UNS Gas (2)		5			6			1
UNS Electric (2)		5			4			2
Global Solar		(7	)		(5	)		(7	)
Other (3)		(5	)		(5	)		(11	)
Consolidated Net Income	$	46		$	46		$	114

⁽¹⁾ TEP results in 2003 include an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the adoption of FAS 143.

⁽²⁾ 2003 results are for the period from August 11, 2003 to December 31, 2003.

⁽³⁾ Includes: UniSource Energy parent company expenses, including in 2005, interest expense (net of tax) on the UniSource Energy Convertible Senior Notes, on the UniSource Energy Credit Agreement, and on the note payable from UniSource Energy to TEP; costs in 2003 associated with the Citizens acquisition; costs in 2004 and 2003 associated with the proposed acquisition of UniSource Energy; income and losses from other Millennium investments and income and losses from UED.

Factors Impacting Net Income 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 $24 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;

· a $2 million increase in losses at Global Solar; 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 Net Income in 2004 Compared With 2003

2004 Included:

· a $196 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 $36 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 $22 million increase in income tax expense due to higher Income Before Taxes 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;

· a $2 million decrease in net losses at Global Solar; 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 $9 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 $36 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

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million of indebtedness for borrowed money of UniSource Energy or TEP, or certain events of bankruptcy involving UniSource Energy or TEP.

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:

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 · 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;

· 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.

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⁽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, 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

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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:

· 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.

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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 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.

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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 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

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more economical purchases of energy in the wholesale market. TEP’s Purchased Power expense increased 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 amoritization 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		21		21		13		16		12		7
Program (NSP)
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 PGAfactor 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.

GLOBAL SOLAR ENERGY, INC.

RESULTS OF OPERATIONS

UniSource Energy accounts for Global Solar under the consolidation method and recognizes 100% of Global Solar’s losses. Global Solar recognizes expense when funding is used for research, development and administrative costs. Losses are expected to continue in the first half of 2006, or until UniSource Energy completes a sale of Global Solar.

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The table below provides a breakdown of the net losses recorded by Global Solar for the last three years.

	2005			2004			2003
	- Millions of Dollars -
Global Solar
Research & Development Contract Revenues from Third Parties	$	-		$	1		$	1
Other Revenues		5			8			9
Research & Development Contract Expenses & Losses		(3	)		(4	)		(5	)
Research & Development - Internal Development Expenses		-			-			(1	)
Depreciation & Amortization Expense		(3	)		(3	)		(3	)
Administrative & Other Costs		(11	)		(11	)		(13	)
Global Solar Net Loss before Income Tax Benefits		(12	)		(9	)		(12	)
Income Tax Benefits		5			4			5
Total Global Solar Net Loss	$	(7	)	$	(5	)	$	(7	)

GLOBAL SOLAR COMMITMENTS

Millennium is in the process of negotiating the sale of its interest in Global Solar, its largest holding. We anticipate that any operating and capital funding required to maintain Global Solar in the interim will be provided only out of Millennium cash or cash returns from other Millennium investments. We believe such cash and returns will be adequate for that purpose.

OTHER

RESULTS OF OPERATIONS

The table below summarizes the income and losses for the Other non-reportable segments in the last three years.

	2005			2004			2003
	- Millions of Dollars -
UniSource Energy Parent Company	$	(6	)	$	(5	)	$	(9	)
Other Millennium Investments		1			1			(9	)
UED		-			(1	)		7
Total Other	$	(5	)	$	(5	)	$	(11	)

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 other than Global Solar, income and losses from UED and costs in 2003 associated with the Citizens acquisition.

Other 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

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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.

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.

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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, 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

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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.

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

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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 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-

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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.

TEP used an initial health care cost trend rate of 10% 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.

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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% 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

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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 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

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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.

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.

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· 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.

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

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

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UniSource Energy and TEP are including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for UniSource Energy or TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates”, “estimates”, “expects”, “intends”, “plans”, “predicts”, “projects”, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of UniSource Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UniSource Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

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Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. We express our expectations, beliefs and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in other parts of this report:

1.    Supply and demand conditions in wholesale energy markets, including volatility in market prices and illiquidity in markets, which are affected by a variety of factors. These factors include the availability of generating capacity in the western U.S., including hydroelectric resources, weather, natural gas prices, the extent of utility restructuring in various states, transmission constraints, environmental regulations and cost of compliance, FERC regulation of wholesale energy markets, and economic conditions in the western U.S.

2.    Effects of competition in retail and wholesale energy markets.

3.    Changes in economic conditions, demographic patterns and weather conditions in our retail service areas.

4.    Effects of restructuring initiatives in the electric industry and other energy-related industries.

5.    The creditworthiness of the entities with which we transact business or have transacted business.

6.    Changes affecting our cost of providing electric and gas service including changes in fuel costs, generating unit operating performance, scheduled and unscheduled plant outages, interest rates, tax laws, environmental laws, and the general rate of inflation.

7.    Changes in governmental policies and regulatory actions with respect to financing and rate structures.

8.    Changes affecting the cost of competing energy alternatives, including changes in available generating technologies and changes in the cost of natural gas.

9.    Changes in accounting principles or the application of such principles to our businesses.

10.  Changes in the depreciable lives of our assets.

11.  Unanticipated changes in future liabilities relating to employee benefit plans due to changes in market values of retirement plan assets and health care costs.

12.  The outcome of any ongoing or future litigation.

13.  Ability to obtain financing through debt and/or equity issuance, which can be affected by various factors, including interest rate fluctuations and capital market conditions.

ITEM 7A. - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISKS

We are exposed to various forms of market risk. Changes in interest rates, returns on marketable securities, and changes in commodity prices may affect our future financial results.

For additional information concerning risk factors, including market risks, see Safe Harbor for Forward-Looking Statements, above.

Interest Rate Risk

TEP is exposed to risk resulting from changes in interest rates on certain of its variable rate debt obligations. At December 31, 2005 and 2004, TEP’s debt included $329 million of tax-exempt variable rate debt. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 2.48% in 2005 and

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1.25% in 2004. TEP also has approximately $69 million in outstanding principal amount of variable rate lease debt related to its Springerville Common Facilities Leases. Interest on this lease debt is payable at LIBOR plus 4%. The average interest rate on this lease debt was 7.36% in 2005 and 5.92% in 2004. A one percent increase (decrease) in average interest rates would result in a decrease (increase) in TEP’s pre-tax income by approximately $4 million.

Marketable Securities Risk

TEP is exposed to fluctuations in the return on its marketable securities, comprised of investments in debt securities. At December 31, 2005 and 2004, TEP had marketable debt securities with an estimated fair value of $165 million and $182 million, respectively. At December 31, 2005 and 2004, the fair value exceeded the carrying value by $9 million and $11 million, respectively. These debt securities represent TEP’s investments in lease debt underlying certain of TEP’s capital lease obligations. Changes in the fair value of such debt securities do not present a material risk to TEP, as TEP intends to hold these investments to maturity.

Risk Management Committee

We have a Risk Management Committee responsible for the oversight commodity price risk and credit risk related to the wholesale energy marketing activities of TEP, the emissions and trading activities of MEG, and the fuel and power procurement activities at TEP and UES. Our Risk Management Committee, which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, transmission and distribution operations, and the generation operations departments of UniSource Energy. To limit TEP’s, UES’ and MEG’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP’s, UES’ and MEG’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure, as well as credit policies and limits.

Commodity Price Risk

We are exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, coal and emission allowances.

TEP

Purchases and Sales of Energy

To manage its exposure to energy price risk, TEP enters into forward contracts to buy or sell energy at a specified price and future delivery period. Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified market approach to provide a balance between long-term, mid-term and spot energy sales. TEP generally enters into forward purchases during its summer peaking period to ensure it can meet its load and reserve requirements and account for other contracts and resource contingencies. TEP also enters into limited forward purchases and sales to optimize its resource portfolio and take advantage of locational differences in price. These positions are managed on both a volumetric and dollar basis and are closely monitored using risk management policies and procedures overseen by the Risk Management Committee. For example, the risk management policies provide that TEP should not take a short position in the third quarter and must have owned generation backing up all forward sales positions at the time the sale is made. TEP’s risk management policies also restrict entering into forward positions with maturities extending beyond the end of the next calendar year except for approved hedging purposes.

The majority of TEP’s forward contracts are considered to be “normal purchases and sales” of electric energy and are not considered to be derivatives under FAS 133. TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered. From time to time, however, TEP enters into forward contracts that meet the definition of a derivative under FAS 133. When TEP has derivative forward contracts, it marks them to market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other southwestern U.S. trading hubs. TEP believes that these broker quotations used to calculate the mark-to-market values represent accurate measures of the fair values of TEP’s positions, because of the short-term nature of TEP’s positions, as limited by risk management policies, and the liquidity in the short-term market.

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To adjust the value of its derivative forward contracts to fair value in Other Comprehensive Income and on its income statement, TEP recorded net unrealized gains of $6 million in Other Comprehensive Income for the 2005, and gains of less than $1 million in Other Comprehensive Income for 2004. TEP also recorded net unrealized gains of $1 million in Wholesale Sales for 2005, and net unrealized gains of $2 million in Wholesale Sales for 2004.

TEP uses sensitivity analysis to measure the impact of an unfavorable change in market prices on the fair value of its derivative forward contracts. As of December 31, 2005, for TEP’s forward power contracts (a majority of which are sales 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 majority of which are sales contracts), 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.

Natural Gas

TEP is also subject to commodity price risk from changes in the price of natural gas. 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, gas-indexed purchase power and spot market purchases with fixed price contracts for a maximum of three years. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.

In 2005, the average market price of natural gas was $7.17 per MMBtu, or 32% higher than 2004. TEP’s generation output fueled by natural gas was approximately 368,000 MWh, or 3% of total generation and purchased power in 2005. During 2005, TEP purchased a total of 1,639,000 MWh of energy, or 13% of total generation and purchased power. As of December 31, 2005, 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.

Coal

TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants.

In 2003, TEP amended and extended the long-term coal supply contract for Springerville Units 1 and 2 through 2020. TEP expects coal reserves to be sufficient to supply the estimated requirements for Units 1 and 2 for their presently estimated remaining lives. During the extension period of 2011 through 2020, the coal price will be determined by the cost of Powder River Basin coal delivered to Springerville for Unit 3 subject to a floor and ceiling. Based on current coal market conditions, this range would be from $24 to $30 per ton. TEP estimates its future minimum annual payments under this contract to be $45 million through 2010, the initial contract expiration date, and $14 million from 2011 through 2020. TEP’s coal transportation contract at Springerville runs through 2011. TEP estimates minimum annual payments under this contract to be $13 million through 2010 and $7 million in 2011. Any transportation cost change after June 2011 is offset in the coal price calculation in the 2011-2020 extension period.

In 2003, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through December 2006. The total amount paid under these agreements depends on the number of tons of coal purchased and transported. The coal purchase agreements require TEP to take 335,000 tons annually with an estimated minimum payment of $6 million in 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 be a 2-3% increase. The rail agreement requires TEP to transport 325,000 tons with an estimated minimum payment of $3 million in 2006.

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The long-term rail contract for Sundt Unit 4 is in effect until the earliest of 2015 or the remaining life of Unit 4. This rail contract requires TEP to transport at least 75,000 tons of coal per year through 2015 at an estimated annual cost of $2 million or to make a minimum payment of $1 million.

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan, where coal supplies are under long-term contracts administered by the operating agents. In 2003, the Four Corners coal contract was extended through July 2016. This contract requires TEP to purchase minimum amounts of coal at an estimated annual cost of $5 million for the next 12 years. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining lives of the stations.

In 2000, the plant operator terminated the San Juan Generating Station’s coal supply contract and entered into a new coal supply contract, replacing two surface mining operations with one underground operation. San Juan Coal Company, the coal supplier to San Juan, commenced development of the underground mine in the fourth quarter of 2000. The underground mine did not achieve full station supply until December 2003 due to geological issues. PNM, TEP and San Juan Coal Company have begun a review of long term coal cost projections given the production issues encountered and the experience gained from mining operations.

The contracts to purchase coal for use at the jointly-owned facilities require TEP to purchase minimum amounts of coal at an estimated average annual cost of $19 million for the next five years. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual Obligations andNote 6 of Notes to Consolidated Financial Statements - Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.

UES

UES is also subject to commodity price risk, primarily from the changes in the price of natural gas purchased for its UNS Gas customers. This risk is mitigated through the PGA mechanism which provides an adjustment to UNS Gas’ retail rates to recover the actual costs of gas and transportation. UNS Gas further reduces this risk by purchasing forward fixed price contracts for a portion of its projected gas needs under its Price Stabilization Plan. UNS Gas purchases between 45% and 80% of its estimated gas needs in this manner.

UNS Electric is not exposed to commodity price risk for its purchase of electricity as it has a fixed price full-requirements supply agreement with PWCC through May 2008.

MEG

MEG trades emissions allowances and related instruments; however, MEG is in the process of winding down its activities and does not expect to engage in any significant new activities after 2005. We manage the market risk of this line of business by setting notional limits by product, as well as limits to the potential change in fair market value under a 33% change in price or volatility. We closely monitor MEG’s trading activities, which include swap agreements, options and forward contracts, using risk management policies and procedures overseen by the Risk Management Committee.

MEG marks its trading positions to market on a daily basis using actively quoted prices obtained from brokers and options pricing models for positions that extend through 2007. As of December 31, 2005 and December 31, 2004, the fair value of MEG’s trading assets combined with emissions allowances it holds in escrow was $38 million and $77 million, respectively. The fair value of MEG’s trading liabilities was $24 million at December 31, 2005 and $65 million at December 31, 2004. For 2005, MEG reflected an $11 million unrealized gain and an $11 million realized loss on its income statement, compared with an unrealized gain of $1 million and a realized gain of $1 million in 2004. For MEG’s remaining trading contracts at December 31, 2005, a 10% decrease in market prices or a 10% increase in market prices would be immaterial.

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

Credit Risk

UniSource Energy is exposed to credit risk in its energy-related marketing and trading activities related to potential nonperformance by counterparties. We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standard agreement which allows for the netting of current period exposures to and from a single counterparty.

We calculate counterparty credit exposure by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts. As of December 31, 2005, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $41 million. Approximately $1 million of TEP’s exposure is to non-investment grade companies. TEP had two counterparties with exposures of greater than 10% of its total credit exposure, totaling approximately $22 million. MEG’s total credit exposure related to its trading activities was $14 million and was concentrated primarily with one counterparty. MEG’s credit exposure to non-investment grade counterparties is less than $0.1 million.

UNS Gas is subject to credit risk from non-performance by its supply counterparty, BP Energy (BP), to the extent that this contract has a mark-to-market value in favor of UNS Gas. As of December 31, 2005, UNS Gas has purchased under fixed price contracts approximately 50% of the expected monthly consumption for the 2005/2006 winter season (November through March) and approximately 28% of its expected consumption for the 2006/2007 winter season. At December 31, 2005, the supply contract with BP was in a favorable mark-to-market position for UNS Gas. When netted against amounts owed to BP, this credit exposure was approximately $9 million.

ITEM 8. - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Controls Over Financial Reporting

UniSource Energy Corporation’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the UniSource Energy Corporation’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.

Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2005, UniSource Energy Corporation’s internal control over financial reporting was effective.

Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

UniSource Energy Corporation:

We have completed integrated audits of UniSource Energy Corporation's 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) and the financial statement schedule listed in the index appearing under Item 15(a)(2), respectively presents fairly, in all material respects, the financial position of UniSource Energy Corporation and its subsidiaries at December 31, 2005 and December 31, 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 3 to the consolidated financial statements, the company changed the manner in which it accounts for asset retirement costs as a result of implementing Financial Accounting Standards Board Interpretation No. 47 as of December 31, 2005.

As described in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management's Report on Internal Controls Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Los Angeles, California

March 3, 2006

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Tucson Electric Power Company:

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) and financial statement schedule listed in index appearing under Item 15(a)(2), respectively presents fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 3 to the consolidated financial statements, the company changed the manner in which it accounts for asset retirement costs as a result of implementing Financial Accounting Standards Board Interpretation No. 47 as of December 31, 2005.

As described in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

PricewaterhouseCoopers LLP
Los Angeles, California

March 3, 2006

K-83

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
		2005			2004			2003
	- Thousands of Dollars -
Operating Revenues
Electric Retail Sales	$	895,411		$	862,258		$	746,578
Electric Wholesale Sales		178,667			160,154			151,111
Gas Revenue		135,909			126,666			46,520
Other Revenues		19,548			19,900			28,546
Total Operating Revenues		1,229,535			1,168,978			972,755
Operating Expenses
Fuel		226,278			212,514			210,163
Purchased Energy		324,351			250,668			132,754
Other Operations and Maintenance		228,237			252,711			216,323
Depreciation and Amortization		135,556			135,315			130,643
Amortization of Transition Recovery Asset		56,418			50,153			31,752
Taxes Other Than Income Taxes		47,737			48,227			48,115
Total Operating Expenses		1,018,577			949,588			769,750
Operating Income		210,958			219,390			203,005
Other Income (Deductions)
Interest Income		19,838			20,192			20,493
Other Income		10,985			15,030			7,306
Other Expense		(2,155	)		(6,439	)		(5,620	)
Total Other Income (Deductions)		28,668			28,783			22,179
Interest Expense
Long-Term Debt		76,762			80,968			80,844
Interest on Capital Leases		79,098			85,912			84,080
Loss on Reaquired Debt		5,261			1,990			-
Other Interest Expense		3,153			1,947			3,709
Interest Capitalized		(3,978	)		(2,509	)		(2,001	)
Total Interest Expense		160,296			168,308			166,632
Income Before Income Taxes and Cumulative Effect of Accounting Change		79,330			79,865			58,552
Income Tax Expense		32,560			33,946			12,082
Income Before Cumulative Effect of Accounting Change		46,770			45,919			46,470
Cumulative Effect of Accounting Change - Net of Tax		(626	)		-			67,471
Net Income	$	46,144		$	45,919		$	113,941
Weighted-average Shares of Common Stock Outstanding (000)		34,798			34,380			33,828
Basic Earnings per Share
Income Before Cumulative Effect of Accounting Change	$	1.35		$	1.34		$	1.38
Cumulative Effect of Accounting Change - Net of Tax	$	(0.02	)		-		$	1.99
Net Income	$	1.33		$	1.34		$	3.37
Diluted Earnings per Share
Income Before Cumulative Effect of Accounting Change	$	1.30		$	1.31		$	1.35
Cumulative Effect of Accounting Change - Net of Tax	$	(0.02	)		-		$	1.97
Net Income	$	1.28		$	1.31		$	3.32
Dividends Declared per Share	$	0.76		$	0.64		$	0.60

See Notes to Consolidated Financial Statements.

K-84

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2005			2004			2003
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	975,378		$	931,450		$	814,425
Cash Receipts from Electric Wholesale Sales		227,095			204,902			203,717
Cash Receipts from Gas Sales		145,281			136,797			38,306
Sale of Excess Emission Allowances		13,474			2,760			-
Other Cash Receipts		13,763			18,660			11,982
MEG Cash Receipts from Trading Activity		72,441			170,506			101,368
UED Springerville 3 Financial Closing Proceeds		-			-			43,265
Interest Received		23,194			22,608			22,428
Performance Deposits		4,702			(6,487	)		(3,124	)
Income Tax Refunds Received		1,484			5,427			17,093
Deposit-Second Mortgage Indenture		-			17,040			(17,040	)
Fuel Costs Paid		(223,672	)		(208,549	)		(204,920	)
Purchased Energy Costs Paid		(369,218	)		(286,115	)		(187,933	)
Wages Paid, Net of Amounts Capitalized		(98,071	)		(92,781	)		(82,482	)
Payment of Other Operations and Maintenance Costs		(133,766	)		(125,197	)		(114,864	)
MEG Cash Payments for Trading Activity		(79,990	)		(162,609	)		(100,963	)
Capital Lease Interest Paid		(67,707	)		(70,752	)		(74,865	)
Taxes Other Than Income Paid, Net of Amounts Capitalized		(140,431	)		(139,637	)		(110,391	)
Interest Paid, Net of Amounts Capitalized		(72,481	)		(75,957	)		(73,565	)
Income Taxes Paid		(10,147	)		(20,483	)		(6,716	)
Other Cash Payments		(4,919	)		(14,604	)		(12,325	)
Net Cash Flows - Operating Activities		276,410			306,979			263,396
Cash Flows from Investing Activities
Capital Expenditures		(203,428	)		(167,017	)		(137,282	)
Purchase of Citizens Arizona Gas and Electric Assets		-			-			(223,430	)
Proceeds from Investment in Springerville Lease Debt		13,646			11,590			12,078
Return of Investment from Millennium Energy Businesses		15,236			10,120			-
Other Proceeds from Investing Activities		8,848			2,716			1,876
Payments for Investment in Springerville Lease Debt		-			(4,499	)		-
Investments in and Loans to Equity Investees		(4,870	)		(4,095	)		(2,072	)
Other Payments for Investing Activities		-			(5,004	)		(1,902	)
Net Cash Flows - Investing Activities		(170,568	)		(156,189	)		(350,732	)
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt		240,000			-			160,000
Repayment of Long-Term Debt		(285,516	)		(28,732	)		(2,976	)
Payments of Capital Lease Obligations		(52,907	)		(49,378	)		(42,657	)
Payment of Debt Issue Costs		(12,431	)		(9,364	)		(3,283	)
Proceeds from Borrowings Under Revolving Credit Facilities		45,000			20,000			45,000
Payments for Borrowings Under Revolving Credit Facilities		(40,000	)		(20,000	)		(45,000	)
Proceeds from Issuance of Short-Term Debt		-			-			36,125
Repayments of Short-Term Debt		-			-			(35,960	)
Common Stock Dividends Paid		(26,339	)		(21,879	)		(20,208	)
Proceeds from Stock Options Exercised		10,691			6,970			-
Other Proceeds from Financing Activities		11,906			8,007			7,949
Other Payments for Financing Activities		(5,595	)		(3,652	)		(1,316	)
Net Cash Flows - Financing Activities		(115,191	)		(98,028	)		97,674
Net (Decrease) Increase in Cash and Cash Equivalents		(9,349	)		52,762			10,338
Cash and Cash Equivalents, Beginning of Year		154,028			101,266			90,928
Cash and Cash Equivalents, End of Year	$	144,679		$	154,028		$	101,266

See Note 20 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-85

UNISOURCE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
		2005			2004
ASSETS	- Thousands of Dollars -
Utility Plant
Plant in Service	$	3,167,900		$	3,033,405
Utility Plant under Capital Leases		723,900			723,901
Construction Work in Progress		160,186			116,161
Total Utility Plant		4,051,986			3,873,467
Less Accumulated Depreciation and Amortization		(1,408,158	)		(1,348,017	)
Less Accumulated Amortization of Capital Lease Assets		(472,367	)		(444,313	)
Total Utility Plant - Net		2,171,461			2,081,137
Investments and Other Property
Investments in Lease Debt		156,301			170,893
Other		68,759			85,035
Total Investments and Other Property		225,060			255,928
Current Assets
Cash and Cash Equivalents		144,679			154,028
Trade Accounts Receivable		100,156			107,694
Unbilled Accounts Receivable		53,920			55,350
Allowance for Doubtful Accounts		(15,037	)		(16,492	)
Materials and Fuel Inventory		69,829			62,225
Trading Assets		36,418			73,258
Current Regulatory Assets		15,563			11,515
Deferred Income Taxes - Current		9,104			24,055
Interest Receivable - Current		9,830			10,475
Other		20,052			24,451
Total Current Assets		444,514			506,559
Regulatory and Other Assets
Transition Recovery Asset		167,611			224,029
Income Taxes Recoverable Through Future Revenues		39,936			44,624
Other Regulatory Assets		20,944			13,961
Other Assets		57,254			49,280
Total Regulatory and Other Assets		285,745			331,894
Total Assets	$	3,126,780		$	3,175,518
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	616,741		$	580,718
Capital Lease Obligations		665,737			701,931
Long-Term Debt		1,212,420			1,257,595
Total Capitalization		2,494,898			2,540,244
Current Liabilities
Current Obligations under Capital Leases		48,804			53,694
Current Maturities of Long-Term Debt		5,000			1,725
Borrowing Under Revolving Credit Facilities		5,000			-
Accounts Payable		99,798			95,276
Interest Accrued		57,386			60,679
Trading Liabilities		27,300			65,101
Taxes Accrued		64,804			53,192
Accrued Employee Expenses		16,052			19,216
Customer Deposits		15,463			14,794
Other		4,426			4,477
Total Current Liabilities		344,033			368,154
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent		95,281			101,753
Regulatory Liability - Net Cost of Removal for Interim Retirements		78,535			69,585
Other		114,033			95,782
Total Deferred Credits and Other Liabilities		287,849			267,120
Commitments and Contingencies (Note 6)
Total Capitalization and Other Liabilities	$	3,126,780		$	3,175,518

See Notes to Consolidated Financial Statements.

K-86

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION
 

				December 31,
				2005			2004
COMMON STOCK EQUITY				- Thousands of Dollars -
Common Stock--No Par Value				$	689,185		$	677,119
	2005	2004
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	34,874,450	34,255,070
Accumulated Deficit					(65,861	)		(85,666	)
Accumulated Other Comprehensive Loss					(6,583	)		(10,735	)
Total Common Stock Equity					616,741			580,718
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding					-			-
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1					431,493			459,815
Springerville Coal Handling Facilities					122,353			126,538
Springerville Common Facilities					106,136			105,529
Sundt Unit 4					53,924			62,607
Other Leases					635			1,136
Total Capital Lease Obligations					714,541			755,625
Less Current Maturities					(48,804	)		(53,694	)
Total Long-Term Capital Lease Obligations					665,737			701,931
LONG-TERM DEBT
Issue	Maturity	Interest Rate
Convertible Senior Notes	2035	4.50%			150,000			-
UniSource Credit Agreement - Term Loan	2010	Variable ***			86,250			-
1941 Mortgage Bonds
Industrial Development Revenue Bonds (IDBs)	2006 - 2008	6.10% to 7.50	%		-			53,150
1992 Mortgage IDBs*	2018 - 2022	Variable**			328,600			328,600
Collateral Trust Bonds	2008	7.50%			138,300			138,300
Unsecured IDBs	2020 - 2033	5.85% to 7.13	%		354,270			579,270
Senior Unsecured Notes	2008 - 2015	6.23% to 7.61	%		160,000			160,000
Total Stated Principal Amount					1,217,420			1,259,320
Less Current Maturities					(5,000	)		(1,725	)
Total Long-Term Debt					1,212,420			1,257,595
Total Capitalization				$	2,494,898		$	2,540,244

* The 1992 Mortgage IDBs (defined below) are backed by $341 million of LOCs under TEP's Credit Agreement which expire in May 2010. TEP's obligations under the Credit Agreement are collateralized with 1992 Mortgage Bonds. At December 31, 2005, the annual LOC fees (including fronting fees) were 1.125%. At December 31, 2004, the annual LOC fees (including fronting fees) were 2.60%. See Note 8.

** Weighted average interest rates on variable rate tax-exempt debt (IDBs) ranged from 0.91% to 3.55% during 2005 and 2004, and the average interest rate on such debt was 2.48% in 2005 and 1.25% in 2004.

*** Interest accrues at a rate of LIBOR plus 1.75% or the agent bank's reference rate plus 0.75%. The weighted average interest rate on the UniSource Credit Agreement for the year ended December 31, 2005, was 6.24%.

UniSource Energy also has stock options outstanding. See Note 16.

See Notes to Consolidated Financial Statements.

K-87

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME

								Accumulated
	Common				Accumulated			Other			Total
	Shares		Common		Earnings			Comprehensive			Stockholders'
	Outstanding*		Stock		(Deficit)			Income (Loss)			Equity
	- In Thousands -
Balances at December 31, 2002	33,579	$	664,103	$	(203,439	)	$	(4,024	)	$	456,640
Comprehensive Income:
2003 Net Income	-		-		113,941			-			113,941
Minimum Pension Liability
(net of $2,639 income taxes)	-		-		-			2,180			2,180
Total Comprehensive Income											116,121
Dividends Declared	-		-		(20,208	)		-			(20,208	)
Shares Issued under Stock Compensation Plans	7		55		-			-			55
Shares Distributed by Deferred Compensation Trust	3		52		-			-			52
Shares Issued for Stock Options	199		2,736		-			-			2,736
Tax Benefit Realized from Stock Options Exercised	-		753		-			-			753
Other	-		323		-			-			323
Balances at December 31, 2003	33,788		668,022		(109,706	)		(1,844	)		556,472
Comprehensive Income:
2004 Net Income	-		-		45,919			-			45,919
Minimum Pension Liability Adjustment
(net of $1,430 income taxes)	-		-		-			(10,460	)		(10,460	)
Unrealized Gain on Cash Flow Hedges
(net of $960 income taxes)	-		-		-			1,465			1,465
Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $68 income taxes)	-		-		-			104			104
Total Comprehensive Income											37,028
Dividends Declared	-		-		(21,879	)		-			(21,879	)
Shares Issued under Stock Compensation Plans	63		1,307		-			-			1,307
Shares Distributed by Deferred Compensation Trust	4		50		-			-			50
Shares Issued for Stock Options	400		6,117		-			-			6,117
Tax Benefit Realized from Stock Options Exercised	-		1,459		-			-			1,459
Other	-		164		-			-			164
Balances at December 31, 2004	34,255		677,119		(85,666	)		(10,735	)		580,718
Comprehensive Income:
2005 Net Income	-		-		46,144			-			46,144
Minimum Pension Liability Adjustment
(net of $1,378 income taxes)	-		-		-			(2,101	)		(2,101	)
Unrealized Gain on Cash Flow Hedges
(net of $6,503 income taxes)	-		-		-			9,918			9,918
Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $2,403 income taxes)	-		-		-			(3,665	)		(3,665	)
Total Comprehensive Income											50,296
Dividends Declared	-		-		(26,339	)		-			(26,339	)
Shares Issued under Stock Compensation Plans	36		-		-			-			-
Shares Distributed by Deferred Compensation Trust	-		1		-			-			1
Shares Issued for Stock Options	583		9,411		-			-			9,411
Tax Benefit Realized from Stock Options Exercised	-		2,527		-			-			2,527
Other	-		127		-			-			127
Balances at December 31, 2005	34,874	$	689,185	$	(65,861	)	$	(6,583	)	$	616,741

* UniSource Energy has 75 million authorized shares of Common Stock.

We describe limitations on our ability to pay dividends in Note 11.

See Notes to Consolidated Financial Statements.

K-88

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2005			2004			2003
	- Thousands of Dollars -
Operating Revenues
Electric Retail Sales	$	746,876		$	719,341		$	691,503
Electric Wholesale Sales		178,428			159,918			151,030
Other Revenues		12,166			10,039			9,018
Total Operating Revenues		937,470			889,298			851,551
Operating Expenses
Fuel		226,278			212,514			210,163
Purchased Power		132,883			72,558			65,127
Other Operations and Maintenance		168,056			190,347			170,086
Depreciation and Amortization		114,704			117,109			121,037
Amortization of Transition Recovery Asset		56,418			50,153			31,752
Taxes Other Than Income Taxes		39,790			39,933			42,388
Total Operating Expenses		738,129			682,614			640,553
Operating Income		199,341			206,684			210,998
Other Income (Deductions)
Interest Income		18,884			20,021			20,328
Interest Income - Note Receivable from UniSource Energy		1,684			9,329			10,242
Other Income		4,182			6,520			3,272
Other Expense		(1,685	)		(4,600	)		(1,604	)
Total Other Income (Deductions)		23,065			31,270			32,238
Interest Expense
Long-Term Debt		56,243			69,904			76,585
Interest on Capital Leases		79,064			85,869			84,053
Loss on Reacquired Debt		5,261			1,990			-
Other Interest Expense		2,597			1,263			1,820
Interest Capitalized		(3,559	)		(2,014	)		(1,754	)
Total Interest Expense		139,606			157,012			160,704
Income Before Income Taxes andCumulative Effect of Accounting Change		82,800			80,942			82,532
Income Tax Expense		33,907			34,815			21,090
Income Before Cumulative Effect of Accounting Change		48,893			46,127			61,442
Cumulative Effect of Accounting Change - Net of Tax		(626	)		-			67,471
Net Income	$	48,267		$	46,127		$	128,913

See Notes to Consolidated Financial Statements.

K-89

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2005			2004			2003
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	815,624		$	780,335		$	753,424
Cash Receipts from Electric Wholesale Sales		227,031			204,643			203,644
Interest Received		21,073			21,928			22,049
Interest Received from UniSource Energy		11,013			-			19,571
Income Tax Refunds Received		713			3,712			16,926
Deposit-Second Mortgage Indenture		-			17,040			(17,040	)
Sale of Excess Emission Allowances		13,474			2,760			-
Other Cash Receipts		4,007			8,319			3,935
Fuel Costs Paid		(223,672	)		(208,549	)		(204,920	)
Purchased Power Costs Paid		(179,682	)		(115,323	)		(119,635	)
Wages Paid, Net of Amounts Capitalized		(74,627	)		(68,832	)		(63,409	)
Payment of Other Operations and Maintenance Costs		(109,543	)		(99,382	)		(96,380	)
Capital Lease Interest Paid		(67,673	)		(70,748	)		(74,851	)
Taxes Other Than Income Paid, Net of Amounts Capitalized		(105,741	)		(102,648	)		(100,622	)
Interest Paid, Net of Amounts Capitalized		(56,341	)		(65,504	)		(73,071	)
Income Taxes Paid		(28,900	)		(21,402	)		(5,230	)
Other Cash Payments		(3,743	)		(11,198	)		(3,402	)
Net Cash Flows - Operating Activities		243,013			275,151			260,989
Cash Flows from Investing Activities
Capital Expenditures		(149,906	)		(129,505	)		(121,854	)
Proceeds from Investment in Springerville Lease Debt		13,646			11,590			12,078
Other Proceeds from Investing Activities		7,355			1,652			1,232
Payments for Investment in Springerville Lease Debt		-			(4,499	)		-
Other Payments for Investing Activities		-			(5,000	)		(1,902	)
Net Cash Flows - Investing Activities		(128,905	)		(125,762	)		(110,446	)
Cash Flows from Financing Activities
Repayments of Long-Term Debt		(281,766	)		(28,725	)		(2,090	)
Payments of Capital Lease Obligations		(52,826	)		(49,431	)		(42,553	)
Equity Investment from UniSource Energy		110,000			-			-
Proceeds from Repayment of UniSource Energy Note		95,393			-			-
Proceeds from Borrowings Under Revolving Credit Facility		40,000			20,000			45,000
Payments for Borrowings Under Revolving Credit Facility		(40,000	)		(20,000	)		(45,000	)
Payment of Debt Issue Costs		(5,235	)		(8,890	)		(788	)
Dividends Paid to UniSource Energy		(46,000	)		(31,500	)		(80,000	)
Other Proceeds from Financing Activities		8,297			18,419			1,916
Other Payments for Financing Activities		(1,745	)		(1,317	)		(17,544	)
Net Cash Flows - Financing Activities		(173,882	)		(101,444	)		(141,059	)
Net (Decrease) Increase in Cash and Cash Equivalents		(59,774	)		47,945			9,484
Cash and Cash Equivalents, Beginning of Year		113,207			65,262			55,778
Cash and Cash Equivalents, End of Year	$	53,433		$	113,207		$	65,262

See Note 20 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-90

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

				December 31,
	2005				2004
ASSETS	- Thousands of Dollars -
Utility Plant
Plant in Service	$	2,861,511			$	2,771,665
Utility Plant under Capital Leases		723,195				723,195
Construction Work in Progress		132,427				94,336
Total Utility Plant		3,717,133				3,589,196
Less Accumulated Depreciation and Amortization		(1,378,362	)			(1,328,228	)
Less Accumulated Amortization of Capital Lease Assets		(472,149	)			(444,186	)
Total Utility Plant - Net		1,866,622				1,816,782
Investments and Other Property
Investments in Lease Debt		156,301				170,893
Other		24,238				23,393
Total Investments and Other Property		180,539				194,286
Note Receivable from UniSource Energy		-				79,462
Current Assets
Cash and Cash Equivalents		53,433				113,207
Trade Accounts Receivable		78,487				72,042
Unbilled Accounts Receivable		29,658				33,179
Allowance for Doubtful Accounts		(14,528	)			(14,166	)
Intercompany Accounts Receivable		5,807				10,111
Materials and Fuel Inventory		57,815				51,207
Current Regulatory Assets		9,663				9,653
Deferred Income Taxes - Current		10,684				24,157
Interest Receivable - Current		9,747				10,475
Trading Assets		12,338				2,300
Other		12,407				16,030
Total Current Assets		265,511				328,195
Regulatory and Other Assets
Transition Recovery Asset		167,611				224,029
Income Taxes Recoverable Through Future Revenues		39,936				44,624
Other Regulatory Assets		20,634				13,684
Other Assets		34,582				41,106
Total Regulatory and Other Assets		262,763				323,443
Total Assets	$	2,575,435			$	2,742,168
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	558,646			$	414,510
Capital Lease Obligations		665,299				701,405
Long-Term Debt		821,170				1,097,595
Total Capitalization		2,045,115				2,213,510
Current Liabilities
Current Obligations under Capital Leases		48,718				53,611
Current Maturities of Long-Term Debt		-				1,725
Accounts Payable		62,974				46,377
Intercompany Accounts Payable		9,362				20,026
Income Taxes Payable		17,111				17,815
Interest Accrued		50,230				56,514
Taxes Accrued		27,260				27,123
Accrued Employee Expenses		14,585				17,594
Trading Liabilities		2,923				79
Other		10,687				9,513
Total Current Liabilities		243,850				250,377
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent		119,895				129,842
Regulatory Liability - Net Cost of Removal for Interim Retirements		74,825				67,485
Other		91,750				80,954
Total Deferred Credits and Other Liabilities		286,470				278,281
Commitments and Contingencies (Note 6)
Total Capitalization and Other Liabilities	$	2,575,435			$	2,742,168

See Notes to Consolidated Financial Statements.

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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31,
					2005		2004
COMMON STOCK EQUITY					- Thousands of Dollars -
Common Stock--No Par Value				$	795,971		$	658,254
	2005	2004
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	32,139,555	32,139,555
Capital Stock Expense					(6,357	)		(6,357	)
Accumulated Deficit					(224,385	)		(226,652	)
Accumulated Other Comprehensive Loss					(6,583	)		(10,735	)
Total Common Stock Equity					558,646			414,510
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized,     None Outstanding					-			-
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1					431,493			459,815
Springerville Coal Handling Facilities					122,353			126,538
Springerville Common Facilities					106,136			105,529
Sundt Unit 4					53,924			62,607
Other Leases					111			527
Total Capital Lease Obligations					714,017			755,016
Less Current Maturities					(48,718	)		(53,611	)
Total Long-Term Capital Lease Obligations					665,299			701,405
LONG-TERM DEBT
Issue	Maturity	Interest Rate
1941 Mortgage Bonds
Industrial Development Revenue Bonds (IDBs)	2006 - 2008	6.10% to 7.50	%		-			53,150
1992 Mortgage IDBs*	2018 - 2022	Variable**			328,600			328,600
Collateral Trust Bonds	2008	7.50	%		138,300			138,300
Unsecured IDBs	2020 - 2033	5.85% to 7.13	%		354,270			579,270
Total Stated Principal Amount					821,170			1,099,320
Less Current Maturities					-			(1,725	)
Total Long-Term Debt					821,170			1,097,595
Total Capitalization				$	2,045,115		$	2,213,510

* The 1992 Mortgage IDBs are backed by $341 million of LOCs under TEP's Credit Agreement which expire in May 2010. TEP's obligations under the Credit Agreement are collateralized with 1992 Mortgage Bonds. At December 31, 2005, the annual LOC
fees (including fronting fees) were 1.125%. At December 31, 2004, the annual LOC fees (including fronting fees) were 2.60%.
See Note 8.

** Weighted average interest rates on variable rate tax-exempt debt (IDBs) ranged from 0.91% to 3.55% during 2005 and 2004, and the average interest rate on such debt was 2.48% in 2005 and 1.25% in 2004.

See Notes to Consolidated Financial Statements.

K-92

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME

										Accumulated
				Capital			Accumulated			Other			Total
		Common		Stock			Earnings			Comprehensive			Stockholders'
		Stock		Expense			(Deficit)			Income (Loss)			Equity
		- Thousands of Dollars -
Balances at December 31, 2002	$	654,405	$	(6,357	)	$	(290,192	)	$	(4,024	)	$	353,832
Comprehensive Income:
2003 Net Income		-		-			128,913			-			128,913
Minimum Pension Liability
(net of $2,639 income taxes)		-		-			-			2,180			2,180
Total Comprehensive Income													131,093
Dividends Paid		-		-			(80,000	)		-			(80,000	)
Capital Contribution from UniSource Energy		1,129		-			-			-			1,129
Balances at December 31, 2003		655,534		(6,357	)		(241,279	)		(1,844	)		406,054
Comprehensive Income:
2004 Net Income		-		-			46,127			-			46,127
Minimum Pension Liability Adjustment
(net of $1,430 income taxes)		-		-			-			(10,460	)		(10,460	)
Unrealized Gain on Cash Flow Hedges
(net of $960 income taxes)		-		-			-			1,465			1,465
Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $68 income taxes)		-		-			-			104			104
Total Comprehensive Income													37,236
Dividends Paid		-		-			(31,500	)		-			(31,500	)
Capital Contribution from UniSource Energy		2,720		-			-			-			2,720
Balances at December 31, 2004		658,254		(6,357	)		(226,652	)		(10,735	)		414,510
Comprehensive Income:
2005 Net Income		-		-			48,267			-			48,267
Minimum Pension Liability Adjustment		-		-			-			(2,101	)		(2,101	)
(net of $1,378 income taxes)
Unrealized Gain on Cash Flow Hedges
(net of $6,503 income taxes)		-		-			-			9,918			9,918
Reclassification of Realized Loss on
Cash Flow Hedges to Net Income
(net of $2,403 income taxes)		-		-			-			(3,665	)		(3,665	)
Total Comprehensive Income													52,419
Dividends Paid		-		-			(46,000	)		-			(46,000	)
Equity Contribution from UniSource Energy		25,261		-			-			-			25,261
Capital Contribution from UniSource Energy		112,456		-			-			-			112,456
Balances at December 31, 2005	$	795,971	$	(6,357	)	$	(224,385	)	$	(6,583	)	$	558,646

We describe limitations on TEP's ability to pay dividends in Note 11.

See Notes to Consolidated Financial Statements.

K-93

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

UniSource Energy Corporation (UniSource Energy) is an exempt holding company under the Public Utility Holding Company Act of 1935. UniSource Energy has no significant operations of its own, but owns substantially all of the common stock of Tucson Electric Power Company (TEP) and all of the common stock of UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy Development Company (UED).

TEP, a regulated public utility incorporated in Arizona since 1963, is UniSource Energy’s largest operating subsidiary and represented approximately 82% of UniSource Energy’s assets as of December 31, 2005. TEP generates, transmits and distributes electricity. TEP serves approximately 385,000 retail electric customers in a 1,155 square mile area in Southern Arizona. TEP also sells electricity to other utilities and power marketing entities primarily located in the western U.S.

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

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

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

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

BASIS OF PRESENTATION

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

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

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

K-94

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

Investee	% of Common Stock Owned
UniSource Energy
Carboelectrica Sabinas, S. de R.L. de C.V.		50.0	%
Haddington Energy Partners II, LP		31.1	%
MicroSat Systems, Inc.		35.0	%
Valley Ventures III, LP		15.0	%
Infinite Power Solutions, Inc.		31.4	%
TEP
Inncom International, Inc.		16.7	%

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

USE OF ACCOUNTING ESTIMATES

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

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

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

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

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

ACCOUNTING FOR RATE REGULATION

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) regulate portions of TEP’s, UNS Gas’ and UNS Electric’s utility accounting practices and rates. The ACC has authority over certain rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. The FERC regulates TEP’s and UNS Electric’s rates for wholesale power sales and transmission services.

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

The conditions a regulated company must satisfy to apply the accounting policies and practices of FAS 71 include:

·   an independent regulator sets rates;

·   the regulator sets the rates to recover specific costs of delivering service; and

·   the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.

K-95

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

CASH AND CASH EQUIVALENTS

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

UTILITY PLANT

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

·   Material and labor costs,

·   Contractor costs,

·   Construction overhead costs (where applicable), and

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

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

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

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

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

Depreciation

TEP and UES compute depreciation for owned utility plant on a straight-line basis at rates based on the economic lives of the assets. See Note 7. The depreciation rates are approved by the ACC for all plant except TEP’s deregulated generation assets. The depreciable lives for TEP’s generation plant are based on remaining useful lives. Changes made to the depreciable lives of TEP’s generation plant are discussed in Note 7. The depreciation rates for generation plant reflect interim retirements. Interim retirements of generation plant, together with removal costs less salvage, are charged to accumulated depreciation. The costs of planned major maintenance activities are recorded as the costs are actually incurred and are not accrued in advance of the planned maintenance. Planned major maintenance activities include the scheduled overhauls at TEP’s generation plants. Minor replacements and repairs are expensed as incurred.

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

K-96

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

Computer Software Costs

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

TEP Utility Plant under Capital Leases

TEP financed the following generation assets with capital leases:

·   Springerville Common Facilities,

·   Springerville Unit 1,

·   Springerville Coal Handling Facilities, and

·   Sundt Unit 4.

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

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

GLOBAL SOLAR PROPERTIES AND EQUIPMENT

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

ASSET RETIREMENT OBLIGATIONS

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

K-97

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

EVALUATION OF ASSETS FOR IMPAIRMENT

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

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

INVESTMENTS IN LEASE DEBT

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

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

DEBT

We defer costs related to the issuance of debt. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting and regulatory fees and printing costs. We amortize these costs over the life of the debt using the straight-line method, which approximates the effective interest method.

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

UTILITY OPERATING REVENUES

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

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

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

REVENUE FROM LONG-TERM RESEARCH AND DEVELOPMENT CONTRACTS

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

K-98

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

2005, $5 million in 2004 and $7 million in 2003. These expenses include both costs associated with revenue producing contracts and internal development costs. Global Solar derives much of its revenue from funding received under research and development contracts with various U.S. governmental agencies.

FUEL AND PURCHASED ENERGY COSTS

TEP

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

UES

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

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

INCOME TAXES

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

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

EMISSIONS ALLOWANCES

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

K-99

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

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

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

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

SHARE-BASED COMPENSATION

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

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

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

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

UniSource Energy:

		Years Ended December 31,
		2004			2003
		-Thousands of Dollars-
		(except per share data)
Net Income - As Reported	$	45,919		$	113,941
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		1,535			850
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,314	)		(1,840	)
Pro Forma Net Income	$	45,140		$	112,951
Earnings per Share:
Basic - As Reported	$	1.34		$	3.37
Basic - Pro Forma	$	1.31		$	3.34
Diluted - As Reported	$	1.31		$	3.32
Diluted - Pro Forma	$	1.29		$	3.29

TEP:

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

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

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

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

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

NEW ACCOUNTING STANDARDS

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

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

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

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

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

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

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

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

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

RECLASSIFICATIONS

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

NOTE 2. REGULATORY MATTERS

TEP RATES AND REGULATION

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

TEP Settlement Agreement

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

The Rules and the Settlement Agreement established:

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

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

·   capped rates for TEP retail customers through 2008;

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

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

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

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

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

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

Recent Court Action

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

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

2004 General Rate Case Information

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

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

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

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

Declaratory Motion Filed with ACC

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

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

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

Motion to Amend the Settlement Agreement

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Transition Recovery Asset

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

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

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

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

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

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

The remaining Transition Recovery Asset balance will be amortized as costs are recovered through rates until TEP has recovered $450 million of transition costs or until December 31, 2008, whichever occurs first.

OTHER REGULATORY ASSETS AND LIABILITIES

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

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

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

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

INCOME STATEMENT IMPACT OF APPLYING FAS 71

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

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

If TEP had not applied FAS 71 in these years, the above amounts would have been reflected in the income statements in prior periods.  The reclassification of TEP’s generation-related regulatory assets to the Transition Recovery Asset shortened the amortization period for these assets to nine years.

FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF FAS 71

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

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

UNS GAS RATES AND REGULATION

Rates and Regulation

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

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

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

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

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

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

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

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

Recent Regulatory Action

The following table shows the balance of purchased gas costs:

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

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

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

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

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

Regulatory Assets and Liabilities

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

Income Statement Impact of Applying FAS 71

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

Future Implications of Discontinuing Application of FAS 71

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

UNS ELECTRIC RATES AND REGULATION

Rates and Regulation

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

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

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

Regulatory Assets and Liabilities

UNS Electric’s regulatory liabilities were as follows:

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

 

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

Income Statement Impact of Applying FAS 71

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

Future Implications of Discontinuing Application of FAS 71

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

NOTE 3. ACCOUNTING CHANGE: ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

UniSource Energy:

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

TEP:

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

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

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

NOTE 4. SEGMENT AND RELATED INFORMATION

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

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

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

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

As discussed in Note 1, we record our percentage share of the earnings of affiliated companies when we hold a 20% to 50% voting interest, except for investments where we provide all of the financing, in which case we recognize 100% of the losses. Our portion of the net income (loss) of the entities in which TEP and Millennium own a 20-50% interest or have the ability to exercise significant influence is shown below in Net Income (Loss) from Equity Method Entities.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

2004
Income Statement
Operating Revenues - External	$	887		$	129		$	144		$	5		$	4		$	-		$	1,169
Operating Revenues - Intersegment		2			-			-			4			14			(20	)		-
Depreciation and Amortization		117			5			9			3			1			-			135
Amortization of Transition Recovery Asset		50			-			-			-			-			-			50
Interest Income		29			-			-			-			-			(9	)		20
Net Income from Equity Method Entities		-			-			-			-			6			-			6
Interest Expense		157			6			5			-			9			(9	)		168
Income Tax Expense (Benefit)		35			4			3			(4	)		(4	)		-			34
Net Income (Loss)		46			6			4			(5	)		(5	)		-			46
Cash Flow Statement
Net Cash Flows - Operating Activities		275			21			19			(10	)		7			(5	)		307
Net Cash Flows - Investing Activities - Capital Expenditures		(130	)		(19	)		(19	)		-			-			1			(167	)
Net Cash Flows - Investing Activities - Investments in and Loans to Equity Method Entities		-			-			-			-			(4	)		-			(4	)
Net Cash Flows - Investing Activities - Other		4			-			-			-			11			-			15
Net Cash Flows - Financing Activities		(101	)		(1	)		(2	)		9			(7	)		4			(98	)
Balance Sheet
Total Assets		2,742			201			135			20			930			(852	)		3,176
Investments in Equity Method Entities		2			-			-			-			34			-			36
2003
Income Statement
Operating Revenues - External	$	851		$	47		$	56		$	2		$	17		$	-		$	973
Operating Revenues - Intersegment		1			-			-			8			9			(18	)		-
Depreciation and Amortization		121			2			3			3			2			-			131
Amortization of Transition Recovery Asset		32			-			-			-			-			-			32
Interest Income		31			-			-			-			-			(11	)		20
Net Loss from Equity Method Entities		-			-			-			-			(3	)		-			(3	)
Interest Expense		161			2			2			1			12			(11	)		167
Income Tax Expense (Benefit)		21			1			1			(5	)		(6	)		-			12
Net Income (Loss)		129			1			2			(7	)		(11	)		-			114
Cash Flow Statement
Net Cash Flows - Operating Activities		261			5			8			(13	)		2			-			263
Net Cash Flows - Investing Activities -   Capital Expenditures		(122	)		(9	)		(5	)		(2	)		1			-			(137	)
Net Cash Flows - Investing Activities -   Investments in and Loans to Equity Method Entities		-			-			-			-			(2	)		-			(2	)
Net Cash Flows - Investing Activities - Other		11			(137	)		(84	)		-			(2	)		-			(212	)
Net Cash Flows - Financing Activities		(141	)		149			93			16			(19	)		-			98
Balance Sheet
Total Assets		2,767			185			125			26			845			(825	)		3,123
Investments in Equity Method Entities		5			-			-			-			31			-			36

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

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

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

TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement which allows for the netting of current period exposures to and from a single counterparty.

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

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

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

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

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

CONCENTRATION OF CREDIT RISK

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

NOTE 6.COMMITMENTS AND CONTINGENCIES

TEP COMMITMENTS

Purchase and Transportation Commitments

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

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

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

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

TEP has several long-term contracts for the purchase and transportation of coal with expiration dates from 2006 through 2020. The total amount paid under these contracts depends on the number of tons of coal purchased and transported. All of these contracts (i) include a price adjustment clause that will affect the future cost of coal and (ii) require TEP to pay a take-or-pay charge or liquidated damages if certain minimum quantities of coal are not purchased and/or transported. TEP’s present fuel requirements are in excess of the take-or-pay minimums. At times, TEP has purchased coal from other suppliers, resulting in take-or-pay minimum charges, but a lower overall cost of fuel. TEP made payments under these contracts of $175 million in 2005 and 2004 and $167 million in 2003.

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

		Minimum
		Purchase
		Obligations
		-Millions of Dollars-
2006	$	107
2007		82
2008		82
2009		79
2010		79
Total 2006 - 2010		429
Thereafter		282
Total	$	711

Operating Leases

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

		UniSource Energy		TEP
	-Millions of Dollars-
2006	$	2	$	1
2007		2		1
2008		2		1
2009		1		1
2010		1		-
Total 2006 - 2010		8		4
Thereafter		3		-
Total	$	11	$	4

Environmental Regulation

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

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

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

Income Tax Assessments

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

Sales Tax Assessments

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

Tucson to Nogales Transmission Line

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

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

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

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

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

UES COMMITMENTS

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

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

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

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

		Minimum
		Purchase
		Obligations
		-Millions of Dollars-
2006	$	18
2007		14
2008		9
2009		9
2010		8
Total 2006 - 2010		58
Thereafter		8
Total	$	66

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

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

MILLENNIUM COMMITMENTS

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

TEP CONTINGENCIES

Litigation and Claims Related to San Juan Generating Station

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

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

Litigation and Claims Related to Navajo Generating Station

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

Postretirement and Pension Benefit Costs at Navajo Generating Station

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

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

Environmental Reclamation at Remote Generating Stations

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

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

RESOLUTION OF SPRINGERVILLE GENERATING STATION COMPLAINT

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

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

GUARANTEES AND INDEMNITIES

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

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

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

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

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

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

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

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

NOTE 7. UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

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

				2005						2004
			- Millions of Dollars -
		TEP		UES		UniSource Energy		TEP		UES		UniSource Energy
Plant in Service:
Electric Generation Plant	$	1,233	$	5	$	1,238	$	1,206	$	5	$	1,211
Electric Transmission Plant		543		15		558		539		13		552
Electric Distribution Plant		883		92		975		823		74		897
Gas Distribution Plant		-		151		151		-		135		135
Gas Transmission Plant		-		18		18		-		12		12
General Plant		140		16		156		146		14		160
Intangible Plant		58		8		66		56		7		63
Electric Plant Held for Future Use		5		1		6		2		1		3
Total Plant in Service	$	2,862	$	306	$	3,168	$	2,772	$	261	$	3,033
Utility Plant under Capital Leases	$	723	$	1	$	724	$	723	$	1	$	724

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

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

The depreciable lives currently used by TEP are as follows:

Major Class of Utility Plant in Service	Depreciable Lives
Electric Generation Plant	23-70 years
Electric Transmission Plant	10-50 years
Electric Distribution Plant	24-60 years
General Plant	5-45 years
Intangible Plant	3-10 years

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

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

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

The depreciable lives currently used by UES are as follows:

Major Class of Utility Plant in Service	Depreciable Lives
Electric Generation Plant	23-40 years
Electric Transmission Plant	11-45 years
Electric Distribution Plant	14-26 years
Gas Distribution Plant	17-48 years
Gas Transmission Plant	37-55 years
General Plant	3-33 years

 JOINTLY-OWNED FACILITIES

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

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	Percent Owned by TEP			Plant in Service *		Construction Work in Progress		Accumulated Depreciation
	-Millions of Dollars-
San Juan Units 1 and 2	50.0	%	$	303	$	3	$	215
Navajo Station Units 1, 2 and 3	7.5			131		3		72
Four Corners Units 4 and 5	7.0			82		-		65
Transmission Facilities	7.5 to 95.0			226		-		154
Luna Energy Facility	33.3			-		36		-
Total			$	742	$	42	$	506

*Included in Utility Plant shown above.

TEP has financed or provided funds for the above facilities and TEP’s share of their operating expenses is reflected in the income statements. See Note 6 for commitments related to TEP’s jointly-owned facilities.

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

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

NOTE 8. CREDIT FACILITIES

UNISOURCE ENERGY CREDIT AGREEMENT

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

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

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

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

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

TEP CREDIT AGREEMENT

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

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

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

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

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

UNS GAS/UNS ELECTRIC REVOLVER

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

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

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

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

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

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

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NOTE 9. DEBT AND CAPITAL LEASE OBLIGATIONS

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

UNISOURCE ENERGY DEBT

Convertible Senior Notes

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

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

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

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

Intercompany Notes Payable

In 1998, TEP and UniSource Energy exchanged all the outstanding common stock of TEP on a share-for-share basis for the Common Stock of UniSource Energy in a transaction which resulted in UniSource Energy becoming a holding company with TEP as its subsidiary. Following the share exchange, TEP transferred the stock of Millennium to UniSource Energy for a $95 million promissory note due in 2008. On March 1, 2005, UniSource Energy used $106 million of the $146 million of net proceeds from the convertible debt offering, see above, to repay the $95 million promissory note to TEP plus accrued interest of $11 million. Approximately $25 million of this note represented a gain to TEP. TEP did not record this gain in income. Instead, this gain was reflected as an increase in TEP’s common stock equity when UniSource Energy repaid the note.

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

TEP DEBT

Bond Repurchase and Redemptions

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

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

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

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

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

First and Second Mortgage Indentures

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

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

TEP CAPITAL LEASE OBLIGATIONS

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

·   The Sundt Lease has an initial term to January 2011 and provides for renewal periods of two or more years through 2020.

·   The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025.

·   The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030.

·   The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for one renewal period of six years, then additional renewal periods of five or more years through 2035.

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

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

Springerville Lease Debt

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

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

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

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

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

UNS GAS AND UNS ELECTRIC LONG-TERM DEBT

Senior Unsecured Notes

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

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

		Required Minimum Net Worth		Actual Net Worth
	-Millions of Dollars-
UES	$	50	$	130
UNS Gas		43		80
UNS Electric		26		50

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

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MATURITIES AND SINKING FUND REQUIREMENTS

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

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

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

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NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

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

The carrying amounts of our current assets and liabilities approximate fair value.

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NOTE 11. STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UniSource Energy

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

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

TEP

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

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

Bank Credit Agreement

TEP’s new Credit Agreement as of May 2005 allows TEP to pay dividends as long as TEP maintains compliance with the agreement and certain financial covenants.

ACC Holding Company Order

The ACC Holding Company Order does not allow TEP to pay dividends in excess of 75% of its annual earnings until TEP’s equity ratio equals 37.5% of total capitalization, excluding capital lease obligations. The UES Settlement Agreement, as approved by the ACC, modifies this dividend limitation so that it will remain in place until TEP’s common equity equals 40% of total capitalization (excluding capital lease obligations). As of December 31, 2005, TEP met this ratio requirement.

Federal Power Act

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

UES

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

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Millennium and UED

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

UNISOURCE ENERGY SHAREHOLDER RIGHTS PLAN

In March 1999, UniSource Energy adopted a Shareholder Rights Plan. As of April 1, 1999, each Common Stock shareholder receives one Right for each share held. Each Right initially allows shareholders to purchase UniSource Energy’s Series X Preferred Stock at a specified purchase price. However, the Rights are exercisable only if a person or group (the “acquirer”) acquires or commences a tender offer to acquire 15% or more of UniSource Energy Common Stock. Each Right would entitle the holder (except the acquirer) to purchase a number of shares of UniSource Energy Common or Preferred Stock (or, in the case of a merger of UniSource Energy into another person or group, common stock of the acquiring person) having a fair market value equal to twice the specified purchase price. At any time until any person or group has acquired 15% or more of the Common Stock, UniSource Energy may redeem the Rights at a redemption price of $0.001 per Right. The Rights trade automatically with the Common Stock when it is bought and sold. The Rights expire on March 31, 2009.

NOTE 12. TEP WHOLESALE ACCOUNTS RECEIVABLE AND ALLOWANCES

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

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

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

NOTE 13. SPRINGERVILLE EXPANSION

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

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

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

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

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

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

NOTE 14. INCOME AND OTHER TAXES

INCOME TAXES

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

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Deferred tax assets (liabilities) consist of the following:

	UniSource Energy						TEP
	December 31,						December 31,
	2005			2004			2005			2004
	-Millions of Dollars-
Gross Deferred Income Tax Liabilities
Plant - Net	$	(435	)	$	(481	)	$	(424	)	$	(473	)
Income Taxes Recoverable Through Future
Revenues Regulatory Asset		(16	)		(18	)		(16	)		(18	)
Transition Recovery Asset		(66	)		(89	)		(66	)		(89	)
Derivative Financial Instruments		(5	)		(2	)		(5	)		(2	)
Pensions		(10	)		(9	)		(10	)		(9	)
Capitalized Repairs		(11	)		(6	)		(11	)		(6	)
Unbilled Revenue		(6	)		-			(6	)		-
Other		(26	)		(15	)		(14	)		(9	)
Gross Deferred Income Tax Liability		(575	)		(620	)		(552	)		(606	)
Gross Deferred Income Tax Assets
Capital Lease Obligations		297			314			297			314
Net Operating Loss Carryforwards (NOL)		7			7			-			-
Investment Tax Credit Carryforwards		-			5			-			5
Alternative Minimum Tax Credit (AMT)		77			100			62			92
Accrued Postretirement Benefits		21			19			21			19
Emission Allowance Inventory		13			14			13			14
Coal Contract Termination Fees		12			14			12			14
Springerville Coal Handling Facility		5			6			5			6
Reserve for Uncollectible Accounts		1			6			1			6
Unregulated Investment Losses		23			30			-			1
Minimum Pension Liability		9			7			9			7
Vacation & Sick Accrual		3			3			3			3
Customer Advances		8			5			3			3
Other		20			20			17			17
Gross Deferred Income Tax Asset		496			550			443			501
Deferred Tax Assets Valuation Allowance		(7	)		(8	)		-			(1	)
Net Deferred Income Tax Liability	$	(86	)	$	(78	)	$	(109	)	$	(106	)

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

	UniSource Energy						TEP
	December 31,						December 31,
	2005			2004			2005			2004
	-Millions of Dollars-
Deferred Income Taxes - Current Assets	$	9		$	24		$	11		$	24
Deferred Income Taxes - Noncurrent Liabilities		(95	)		(102	)		(120	)		(130	)
Net Deferred Income Tax Liability	$	(86	)	$	(78	)	$	(109	)	$	(106	)

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

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

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

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

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

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

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

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

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

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

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

The differences between the income tax expense and the amount obtained by multiplying pre-tax income by the U.S. statutory federal income tax rate of 35% are as follows:

	UniSource Energy									TEP
	Years Ended December 31,
	2005			2004			2003			2005			2004			2003
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	28		$	28		$	21		$	29		$	28		$	29
State Income Tax Expense, Net of Federal Deduction		4			4			3			4			4			4
Depreciation Differences (Flow Through Basis)		3			3			4			3			3			4
Federal/State Credits		(1	)		(1	)		(2	)		(1	)		(1	)		(2	)
Increase (Reduction) in Valuation Allowance		(1	)		1			(15	)		(1	)		1			(15	)
Other		-			(1	)		1			-			-			1
Total Federal and State Income Tax Expense Before Cumulative Effect of Accounting Change	$	33		$	34		$	12		$	34		$	35		$	21

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

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

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

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

OTHER TAX MATTERS

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

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

OTHER TAXES

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

NOTE 15. EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

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

OTHER POSTRETIREMENT BENEFIT PLANS

TEP provides limited health care and life insurance benefits for retirees. All regular employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.

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

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

The ACC allows TEP and UES to recover postretirement costs through rates only as benefit payments are made to or on behalf of retirees. The postretirement benefits are currently funded entirely on a pay-as-you-go basis. Under current accounting guidance, TEP and UES cannot record a regulatory asset for the excess of expense calculated per Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, over actual benefit payments.

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

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

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

		Pension Benefits						Other Postretirement Benefits
		Years Ended December 31,
		2005			2004			2005			2004
		-Millions of Dollars-
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	188		$	162		$	70		$	68
Actuarial (Gain) Loss		9			16			(4	)		(1	)
Interest Cost		11			10			4			3
Service Cost		6			6			2			2
Benefits Paid		(6	)		(6	)		(2	)		(2	)
Benefit Obligation at End of Year		208			188			70			70
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		136			124			-			-
Actual Return on Plan Assets		12			12			-			-
Benefits Paid		(6	)		(6	)		(2	)		(2	)
Employer Contributions		7			6			2			2
Fair Value of Plan Assets at End of Year		149			136			-			-
Reconciliation of Funded Status to Balance Sheet
Funded Status (Difference between Benefit
Obligation and Fair Value of Plan Assets)		(59	)		(52	)		(70	)		(70	)
Contributions After Measurement Date		5			-			-			-
Unrecognized Net Loss		55			50			24			30
Unrecognized Prior Service Cost (Benefit)		10			13			(8	)		(10	)
Net Amount Recognized in the Balance Sheets	$	11		$	11		$	(54	)	$	(50	)
Amounts Recognized in the Balance Sheets
Consist of:
Prepaid Pension Costs Included in Other Assets	$	18		$	17		$	-		$	-
Accrued Benefit Liability Included in Other Liabilities		(37	)		(35	)		(54	)		(50	)
Intangible Asset Included in Other Assets		6			9			-			-
Accumulated Other Comprehensive Income		24			20			-			-
Net Amount Recognized	$	11		$	11		$	(54	)	$	(50	)

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

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

The components of net periodic benefit costs are as follows:

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

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

Additional Information	Pension Benefits				Other Postretirement Benefits
	Years Ended December 31,
	2005		2004		2005		2004
	-Millions of Dollars-
Minimum Pension Liability Included in Other Comprehensive Income	$	24	$	20		N/A		N/A

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

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

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

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

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

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

Pension Plan Assets

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

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

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

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

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

Pension Plan Contributions

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

Estimated Future Benefit Payments

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

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

DEFINED CONTRIBUTION PLANS

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

NOTE 16. SHARE-BASED COMPENSATION PLANS

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

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

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

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

STOCK OPTIONS

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

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

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

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

	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Options Outstanding,
Beginning of Year		2,076,055		$	16.19		2,478,551		$	16.04		2,572,551		$	15.77
Granted		50,000		$	33.55		-			-		120,236		$	17.77
Exercised		(581,549	)	$	16.18		(400,003	)	$	15.29		(199,400	)	$	13.72
Forfeited		(7,465	)	$	17.87		(2,493	)	$	13.66		(14,836	)	$	14.20
Options Outstanding,
End of Year		1,537,041		$	16.75		2,076,055		$	16.19		2,478,551		$	16.04
Options Exercisable,
End of Year		1,479,569		$	16.18		2,053,784		$	16.17		1,676,803		$	15.27

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

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

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

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

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

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

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

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RESTRICTED STOCK AND STOCK UNITS

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

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

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

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

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

PERFORMANCE SHARES

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

NOTE 17. UNISOURCE ENERGY EARNINGS PER SHARE (EPS)

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

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

	Years Ended December 31,
	2005		2004		2003
	-In Thousands-
Numerator
Net Income	$	46,144	$	45,919	$	113,941
Income from Assumed Conversion of Convertible Senior Notes		3,654		-		-
Adjusted Numerator	$	49,798	$	45,919	$	113,941
Denominator:
Weighted-average Shares of Common Stock Outstanding		34,798		34,380		33,828
Effect of Diluted Securities
Convertible Senior Notes		3,345		-		-
Options and Stock Issuable under Employee Benefit Plans and  the Directors’ Plan		708		661		511
Total Shares		38,851		35,041		34,339

There were no antidilutive options outstanding during the years ended December 31, 2005 or 2004. Options to purchase an average of 274,000 shares of Common Stock were outstanding during 2003 but were not included in the computation of diluted EPS because the options’ exercise price was greater than the average market price of the common stock.

NOTE 18. RELATED PARTIES

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

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

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

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

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

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

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

NOTE 19. SUBSEQUENT EVENT

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

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

Assets	-Millions of Dollars-
Property, Plant and Equipment, net	$	10
Inventory		4
Income Tax Receivable - Current		4
Goodwill		3
Other Assets		2
Total Assets	$	23
Liabilities
Long-Term Debt	$	10
Other		5
Total Liabilities		15
Stockholder’s Equity
Investment in Global Solar		8
Total Liabilities & Stockholder’s Equity	$	23

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NOTE 20. SUPPLEMENTAL CASH FLOW INFORMATION

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

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

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	TEP
	Years Ended December 31,
	2005			2004			2003
	-Thousands of Dollars-
Net Income	$	48,267		$	46,127		$	128,913
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Cumulative Effect of Accounting Change-Net of Tax		626			-			(67,471	)
Depreciation and Amortization Expense		114,704			117,109			121,037
Depreciation Recorded to Fuel and Other O&M Expense		6,417			6,175			6,230
Amortization of Transition Recovery Asset		56,418			50,153			31,752
Net Unrealized (Gain) Loss on Forward Electric Sales		(604	)		(1,509	)		761
Net Unrealized Loss (Gain) on Forward Electric Purchases		1,863			250			(378	)
Amortization of Deferred Debt-Related Costs included in
Interest Expense		3,687			3,114			2,921
Loss on Reacquired Debt		5,261			1,990			-
Provision for Bad Debts		1,964			1,691			4,460
Deferred Income Taxes		6,555			(1,011	)		1,136
(Gains) Losses from Equity Method Investment Entities		(338	)		(168	)		(142	)
Interest Accrued on Note Receivable from UniSource Energy		(1,684	)		(9,329	)		(10,242	)
Gain on Sale of Real Estate		-			(725	)		(467	)
Other		(10,932	)		(3,219	)		15,927
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(6,779	)		(23,774	)		(8,717	)
Materials and Fuel Inventory		(6,608	)		(1,100	)		(5,607	)
Accounts Payable		3,804			24,958			8,225
Interest Accrued		5,295			10,264			9,005
Interest Received from UniSource Energy		11,013			-			19,571
Income Taxes Payable		(704	)		6,728			(3,274	)
Taxes Accrued		137			13,303			4,555
Other Current Assets		(676	)		(5,328	)		581
Other Current Liabilities		(1,835	)		4,790			1,468
Other Deferred Credits and Other Liabilities		7,162			17,622			17,785
Deposit - 1992 Mortgage Indenture		-			17,040			(17,040	)
Net Cash Flows - Operating Activities	$	243,013		$	275,151		$	260,989

Non-cash investing and financing activities of UniSource Energy and TEP that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
	2005		2004		2003
	-Thousands of Dollars-
Capital Lease Obligations	$	12,720	$	12,273	$	10,731
Preliminary Engineering Fees		3,691		-		-

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

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

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

	-Thousands of Dollars -
Fair Value of Assets Acquired	$	262,044
Liabilities Assumed		38,648
Assets/Liabilities Purchased	$	223,396
Cash Paid for Citizens Assets	$	218,558
Transaction Costs		4,838
Total Purchase Price	$	223,396

NOTE 21. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

	UniSource Energy
	First			Second		Third		Fourth
	-Thousands of Dollars- (except per share data)
2005
Operating Revenue	$	260,929		$	300,592	$	349,252	$	318,762
Operating Income		29,929			54,594		59,508		66,927
Income (Loss) Before Cumulative Effect of Accounting Change		(3,783	)		9,468		18,397		22,688
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(626	)
Net Income		(3,783	)		9,468		18,397		22,062
Basic EPS
Income (Loss) Before Cumulative Effect of Accounting Change		(0.11	)		0.27		0.53		0.65
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(0.02	)
Net Income		(0.11	)		0.27		0.53		0.63
Diluted EPS
Income (Loss) Before Cumulative Effect of Accounting Change		(0.11	)		0.27		0.49		0.60
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(0.02	)
Net Income		(0.11	)		0.27		0.49		0.58
2004
Operating Revenue	$	270,084		$	290,081	$	335,309	$	273,504
Operating Income		42,710			61,571		75,461		39,648
Net Income		6,421			12,801		23,799		2,898
Basic EPS		0.19			0.37		0.69		0.08
Diluted EPS		0.18			0.37		0.68		0.08

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

	TEP
	First			Second		Third		Fourth
	-Thousands of Dollars-
2005
Operating Revenue	$	181,906		$	236,879	$	282,234	$	236,451
Operating Income		23,121			54,125		58,874		63,221
Interest Income - Note Receivable from UniSource Energy		1,684			-		-		-
Income (Loss) Before Cumulative Effect of Accounting Change		(4,690	)		12,148		20,364		21,071
Cumulative Effect of Accounting Change - Net of Tax		-			-		-		(626	)
Net Income		(4,690	)		12,148		20,364		20,445

2004
Operating Revenues	$	186,974	$	233,742	$	272,085	$	196,497
Operating Income		35,688		62,269		74,531		34,196
Interest Income - Note Receivable from UniSource Energy		2,320		2,319		2,345		2,345
Net Income		794		18,017		26,222		1,094

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

The principal unusual items for TEP and UniSource Energy include:

TEP and UniSource Energy

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

·   Third Quarter 2005: TEP recognized a pre-tax gain of $4 million, which is recorded as an offset to Other Operations and Maintenance expense, for its sale of 5,000 excess SO₂ allowances. TEP recognized a $1 million income tax benefit due to anticipated use of previously reserved ITC carryforwards.

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

UniSource Energy

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

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

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UniSource Energy

Schedule II - Valuation and Qualifying Accounts

Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
Year Ended December 31,	-Millions of Dollars-
Deferred Tax Assets Valuation Allowance (1)
2005	$	8	$	-	$	1	$	7
2004		7		1		-		8
2003		22		-		15		7
Allowance for Doubtful Accounts (2)
2005	$	17	$	3	$	5	$	15
2004		12		7		2		17
2003		9		5		2		12

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

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

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TEP

Schedule II - Valuation and Qualifying Accounts

Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
Year Ended December 31,	-Millions of Dollars-
Deferred Tax Assets Valuation Allowance (1)
2005	$	1	$	-	$	1	$	-
2004		-		1		-		1
2003		15		-		15		-
Allowance for Doubtful Accounts (2)
2005	$	14	$	2	$	1	$	15
2004		11		5		2		14
2003		9		5		3		11

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

⁽²⁾ TEP recorded $7 million of expenses in the first quarter of 2001 and $9 million in the fourth quarter of 2000 to reserve for uncollectible amounts related to sales to the state of California in 2000 and the first quarter of 2001. TEP reversed $8 million of the $16 million reserve in the fourth quarter of 2001. In the first quarter of 2003, TEP increased its reserve for sales to the CPX and the CISO by $2 million by recording a reduction of wholesale revenues. In the second quarter of 2004, TEP increased its reserve for sales to the CPX and the CISO by an additional $3 million based on new FERC orders.Deductions principally reflect amounts charged off as uncollectible, less amounts recovered (see Note 12 of Notes to Consolidated Financial Statements). No large or unusual allowances were recorded or written off during the year ended December 31, 2005.

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ITEM 9. - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. - CONTROLS AND PROCEDURES

UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource Energy and TEP’s evaluation of their disclosure controls and procedures as of December 31, 2005. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UniSource Energy and TEP’s periodic reports filed or submitted under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Based upon the evaluation performed, UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UniSource Energy and TEP’s disclosure controls and procedures are effective.

While UniSource Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UniSource Energy or TEP’s internal control over financial reporting during the fourth quarter of 2005, that has materially affected, or is reasonably likely to materially affect, UniSource Energy or TEP’s internal control over financial reporting.

UniSource Energy’s Management’s Report on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appears as the first report under Item 8 and the Report of Independent Registered Public Accounting Firm appears as the second report under Item 8 in this Annual Report on Form 10-K.

ITEM 9B. - OTHER INFORMATION

None.

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PART III

ITEM 10. - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

DIRECTORS

Certain of the individuals serving as Directors of UniSource Energy also serve as the Directors of TEP. Information concerning Directors will be contained under Election of Directors in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

EXECUTIVE OFFICERS - UNISOURCE ENERGY

Executive Officers of UniSource Energy, who are elected annually by UniSource Energy’s Board of Directors, are as follows:

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

James S. Pignatelli	Mr. Pignatelli joined TEP as Senior Vice President in August 1994 and was elected Senior Vice President and Chief Operating Officer in 1996. He was named Senior Vice President and Chief Operating Officer of UniSource Energy in January 1998, and Executive Vice President and Chief Operating Officer of TEP in March 1998. On June 23, 1998, Mr. Pignatelli was named Chairman, President and CEO of UniSource Energy and TEP. Prior to joining TEP, he was President and Chief Executive Officer from 1988 to 1993 of Mission Energy Company, a subsidiary of SCE Corp.
Michael J. DeConcini	Mr. DeConcini joined TEP in 1988 and served in various positions in finance, strategic planning and wholesale marketing. He was Manager of TEP’s Wholesale Marketing Department in 1994, adding Product Development and Business Development in 1997. In November 1998, he was elected Vice President of MEH, and elected Vice President, Strategic Planning of UniSource Energy in February 1999. He was named Senior Vice President, Investments and Planning of UniSource Energy in October 2000. Mr. DeConcini was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003.
Steven J. Glaser	Mr. Glaser joined TEP in 1990 as a senior attorney in charge of Regulatory Affairs. He was Manager of TEP’s Legal Department from 1992-1994 and Manager of Contracts and Wholesale Marketing from 1994 until elected Vice President, Business Development. In 1995, he was named Vice President Wholesale/Retail Pricing and System Planning. He was named Vice President, Energy Services in 1996 and Vice President, Rates and Regulatory Support and Utility Distribution Company Energy Services Company in November 1998. In October 2000, he was named Senior Vice President and Chief Operating Officer of Transmission and Distribution at TEP. As of September 2005, he carried the same title at UniSource Energy.
Raymond S. Heyman	Mr. Heyman was elected to the position of Senior Vice President and General Counsel of TEP and UniSource Energy in September 2005. Prior to joining TEP, Mr. Heyman was a

K-155

	member from 1995 - 2005 of the Phoenix, Arizona law firm Roshka, Heyman & DeWulf, PLC, and has represented UniSource Energy, TEP and UES in proceedings before the Arizona Corporation Commission, as well as in other legal and regulatory matters.
Kevin P. Larson	Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and at TEP’s investment subsidiaries. In January 1991, he was elected Assistant Treasurer of TEP and named Manager of Financial Programs. He was elected Treasurer of TEP in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer of both UniSource Energy and TEP and remains Treasurer of both organizations. He was named Senior Vice President in September 2005.
Dennis R. Nelson	Mr. Nelson joined TEP as a staff attorney in 1976. He was manager of the Legal Department from 1985 to 1990. He was elected Vice President, General Counsel and Corporate Secretary in January 1991. He was named Vice President, General Counsel and Corporate Secretary of UniSource Energy in January 1998. Mr. Nelson was named Senior Vice President and General Counsel of TEP in November 1998. In December 1998, he was named Chief Operating Officer, Corporate Services of TEP. In October 2000, he was named Senior Vice President, Governmental Affairs of UniSource Energy and Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP. Mr. Nelson was elected Senior Vice President of Utility Services, effective January 1, 2003 and named Senior Vice President and Chief Operating Officer of UES on August 11, 2003.
Karen G. Kissinger	Ms. Kissinger joined TEP as Vice President and Controller in January 1991. She was named Vice President, Controller and Principal Accounting Officer of UniSource Energy in January 1998. In November 1998, Ms. Kissinger was also named Chief Information Officer of TEP. She was named Chief Compliance Officer of UniSource Energy and TEP, effective January 1, 2003.
Steven W. Lynn	Mr. Lynn joined TEP in 2000 as Manager of Corporate Relations for UniSource Energy and was named Manager of Corporate Relations of both TEP and UniSource Energy during 2000. In January 2003, he was elected Vice President of Communications and Government Relations at UniSource Energy and TEP. Prior to joining TEP, Mr. Lynn was an owner-partner from 1984 - 2000 of Nordensson Lynn & Associates, Inc., a Tucson-based advertising, marketing and public relations firm.
Catherine A. Nichols	Ms. Nichols joined TEP as a staff attorney in 1989. She was promoted to Manager of the Legal Department and elected Corporate Secretary of TEP in 1998. She assumed the additional role of Manager of the Human Resources Department in 1999. Ms. Nichols was elected Corporate Secretary of UniSource Energy, effective January 1, 2003, and remains Corporate Secretary of TEP.

K-156

EXECUTIVE OFFICERS - TUCSON ELECTRIC POWER COMPANY

Executive Officers of TEP, who are elected annually by TEP’s Board of Directors, are:

Name	Age	Position(s) Held	Executive Officer Since
James S. Pignatelli	62	Chairman, President and Chief Executive Officer	1994
Michael J. DeConcini	41	Senior Vice President, Chief Operating Officer, Energy Resources	2003
Steven J. Glaser	48	Senior Vice President and Chief Operating Officer, Transmission and Distribution Business Unit	1994
Raymond S. Heyman	50	Senior Vice President and General Counsel	2005
Kevin P. Larson	49	Senior Vice President, Chief Financial Officer and Treasurer	1994
Thomas N. Hansen	55	Vice President / Technical Advisor	1992
Karen G. Kissinger	51	Vice President, Controller and Chief Compliance Officer	1991
Steven W. Lynn	59	Vice President, Communications and Government Relations	2003
Catherine A. Nichols	47	Corporate Secretary	1998

James S. Pignatelli	See description shown under UniSource Energy Corporation above.
Michael J. DeConcini	See description shown under UniSource Energy Corporation above.
Steven J. Glaser	See description shown under UniSource Energy Corporation above.
Raymond S. Heyman	See description shown under UniSource Energy Corporation above.
Kevin P. Larson	See description shown under UniSource Energy Corporation above.
Thomas N. Hansen	Mr. Hansen joined TEP in December 1992 as Vice President, Power Production. Prior to joining TEP, Mr. Hansen was Century Power Corporation’s Vice President, Operations from 1989 and Plant Manager at Springerville from 1987 through 1988. In 1994, he was named Vice President / Technical Advisor.
Karen G. Kissinger	See description shown under UniSource Energy Corporation above.
Steven W. Lynn	See description shown under UniSource Energy Corporation above.
Catherine A. Nichols	See description shown under UniSource Energy Corporation above.

Information required by Items 405 and 406 of SEC Regulation S-K will be included in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

ITEM 11. - EXECUTIVE COMPENSATION

Information concerning Executive Compensation will be contained under Executive Compensation and Other Information in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

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ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

GENERAL

At February 28, 2006 UniSource Energy had outstanding 34.9 million shares of Common Stock. As of February 28, 2006, the number of shares of Common Stock beneficially owned by all directors and officers of UniSource Energy as a group amounted to approximately 5% of the outstanding Common Stock.

At February 28, 2006, UniSource Energy owned greater than 99.9% of the outstanding shares of common stock of TEP.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

Information concerning the security ownership of certain beneficial owners of UniSource Energy will be contained under SecurityOwnership of Certain Beneficial Owners in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

SECURITY OWNERSHIP OF MANAGEMENT

Information concerning the security ownership of the Directors and Executive Officers of UniSource Energy and TEP will be contained under Security Ownership of Management in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Information concerning securities authorized for issuance under equity compensation plans will be contained under Securities Authorized for Issuance under Equity Compensation Plans in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

ITEM 13. - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information concerning certain relationships and related transactions of UniSource Energy and TEP will be contained under Transactions with Management and Others and Compensation Committee Interlocks and Insider Participation in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

ITEM 14. - PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information concerning principal accountant fees and services will be contained in UniSource Energy’s Proxy Statement relating to the 2005 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2005, which information is incorporated herein by reference.

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PART IV

ITEM 15. - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

			Page
(a)	1.	Consolidated Financial Statements as of December 31, 2005
		and 2004 and for Each of the Three Years in the Period
		Ended December 31, 2005
		UniSource Energy Corporation
		Report of Independent Registered Public Accounting Firm	73
		Consolidated Statements of Income	76
		Consolidated Statements of Cash Flows	77
		Consolidated Balance Sheets	78
		Consolidated Statements of Capitalization	79
		Consolidated Statements of Changes in Stockholders’ Equity	80
		Notes to Consolidated Financial Statements	86
		Tucson Electric Power Company
		Report of Independent Registered Public Accounting Firm	74
		Consolidated Statements of Income	81
		Consolidated Statements of Cash Flows	82
		Consolidated Balance Sheets	83
		Consolidated Statements of Capitalization	84
		Consolidated Statements of Changes in Stockholders’ Equity	85
		Notes to Consolidated Financial Statements	86
	2.	Financial Statement Schedule
		Schedule II
		Valuation and Qualifying Accounts	138
	3.	Exhibits

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

K-159

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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

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

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

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

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

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

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

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

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

K-160

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

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

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

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

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

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

K-161

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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

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

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

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

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

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

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

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

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

K-162

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

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

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

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

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

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

K-163

EXHIBIT INDEX

*2(a)	--	Agreement and Plan of Exchange, dated as of March 20, 1995, between TEP, UniSource Energy and NCR Holding, Inc.
*3(a)	--	Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for year ended December 31, 1996, File No. 1-5924 -- Exhibit 3(a).)
*3(b)	--	Bylaws of TEP, as amended May 20, 1994. (Form 10-Q for the quarter ended June 30, 1994, File No. 1-5924 -- Exhibit 3.)
*3(c)	--	Amended and Restated Articles of Incorporation of UniSource Energy. (Form 8-A/A, dated January 30, 1998, File No. 1-13739 -- Exhibit 2(a).)
*3(d)	--	Bylaws of UniSource Energy, as amended December 11, 1997. (Form 8-A, dated December 23, 1997, File No. 1-13739 -- Exhibit 2(b).)
*4(a)(1)	--	Installment Sale Agreement, dated as of December 1, 1973, among the City of Farmington, New Mexico, Public Service Company of New Mexico and TEP. (Form 8-K for the month of January 1974, file No. 0-269 -- Exhibit 3.)
*4(a)(2)	--	Ordinance No. 486, adopted December 17, 1973, of the City of Farmington, New Mexico. (Form 8-K for the month of January 1974, File No. 0-269 -- Exhibit 4.)
*4(a)(3)	--	Amended and Restated Installment Sale Agreement dated as of April 1, 1997, between the City of Farmington, New Mexico and TEP relating to Pollution Control Revenue bonds, 1997 Series A (Tucson Electric Power Company San Juan Project). (Form 10-Q for the quarter ended March 31,1997, File No. 1-5924 -- Exhibit 4(a).)
*4(a)(4)	--	City of Farmington, New Mexico Ordinance No. 97-1055, adopted April 17, 1997, authorizing Pollution Control Revenue bonds, 1997 Series A (Tucson Electric Power Company San Juan Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(b).)
*4(b)(1)	--	Loan Agreement, dated as of October 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(a).)
*4(b)(2)	--	Indenture of Trust, dated as of October 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(b).)
*4(b)(3)	--	First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(3).)
*4(b)(4)	--	First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(4).)
*4(c)(1)	--	Loan Agreement, dated as of December 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(1).)

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*4(c)(2)	--	Indenture of Trust dated as of December 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(2).)
*4(c)(3)	--	First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(3).)
*4(c)(4)	--	First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(4).)
*4(d)(1)	--	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(I)(1).)
*4(d)(2)	--	Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File no. 1-5924 -- Exhibit 4(I)(2).)
*4(d)(3)	--	First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(k)(3).)
*4(d)(4)	--	First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(k)(4).)
*4(d)(5)	--	Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(k)(5).)
*4(d)(6)	--	Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(k)(6).)
*4(e)(1)	--	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(1).)
*4(e)(2)	--	Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds. 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(2).)
*4(e)(3)	--	First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Developmental Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(3).)

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*4(e)(4)	--	First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(4).)
*4(e)(5)	--	Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(5).)
*4(e)(6)	--	Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(6).)
*4(f)(1)	--	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(1).)
*4(f)(2)	--	Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(2).)
*4(f)(3)	--	First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(m)(3).)
*4(f)(4)	--	First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(m)(4).)
*4(f)(5)	--	Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(5).)
*4(f)(6)	--	Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(6).)
*4(g)	--	Reimbursement Agreement, dated as of September 15, 1981, as amended, between TEP and Manufacturers Hanover Trust Company. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 4(o)(4).)
*4(h)(1)	--	Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 4(r)(1).)
*4(h)(2)	--	Indenture of Trust dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds,

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		1985 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 4(r)(2).)
*4(h)(3)	--	First Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(o)(3).)
*4(h)(4)	--	First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(o)(4).)
*4(i)(1)	--	Indenture of Mortgage and Deed of Trust dated as of December 1, 1992, to Bank of Montreal Trust Company, Trustee. (Form S-1, Registration No. 33-55732 -- Exhibit 4(r)(1).)
*4(i)(2)	--	Supplemental Indenture No. 1 creating a series of bonds designated Second Mortgage Bonds, Collateral Series A, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732 -- Exhibit 4(r)(2).)
*4(i)(3)	--	Supplemental Indenture No. 2 creating a series of bonds designated Second Mortgage Bonds, Collateral Series B, dated as of December 1, 1997. (Form 10-K for year ended December 31, 1997, File No. 1-5924 -- Exhibit 4(m)(3).)
*4(i)(4)	--	Supplemental Indenture No. 3 creating a series of bonds designated Second Mortgage Bonds, Collateral Series, dated as of August 1, 1998. (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 -- Exhibit 4(c).)
*4(i)(5)	--	Supplemental Indenture No. 4 creating a series of bonds designated Second Mortgage Bonds, Collateral Series C, dated as of November 1, 2002. (Form 8-K dated November 27, 2002, File Nos. 1-05924 and 1-13739 -- Exhibit 99.2.)
*4(i)(6)	--	Supplemental Indenture No. 5 creating a series of bonds designated Second Mortgage Bonds, Collateral Series D, dated as of March 1, 2004. (Form 8-K dated March 31, 2004, File Nos. 1-05924 and 1-13739 -- Exhibit 10 (b).)
*4(i)(7)	--	Supplemental Indenture No. 6 creating a series of bonds designated Second Mortgage Bonds, Collateral Series E, dated as of May 1, 2005. (Form 10-Q for the quarter ended March 31, 2005, File Nos. 1-5924 and 1-13739 - Exhibit 4(b).)
*4(j)(1)	--	Loan Agreement, dated as of April 1, 1997 between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series A (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(c).)
*4(j)(2)	--	Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series A (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(d).)
*4(k)(1)	--	Loan Agreement, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(e).)
*4(k)(2)	--	Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(f).)

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*4(l)(1)	--	Loan Agreement, dated as of September 15, 1997, between The Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 1997 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended September 30, 1997, File No. 1-5924 -- Exhibit 4(a).)
*4(l)(2)	--	Indenture of Trust, dated as of September 15, 1997, between The Industrial Development Authority of the County of Pima and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1997 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended September 30, 1997, File No. 1-5924 -- Exhibit 4(b).)
*4(m)(1)	--	Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(a).)
*4(m)(2)	--	Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(b).)
*4(n)(1)	--	Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(c).)
*4(n)(2)	--	Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(d).)
*4(o)(1)	--	Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(e).)
*4(o)(2)	--	Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(f).)
*4(p)(1)	--	Indenture of Trust, dated as of August 1, 1998, between TEP and the Bank of Montreal Trust Company. (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 -- Exhibit 4(d).)
*4(q)(1)	--	Rights Agreement dated as of March 5, 1999, between UniSource Energy Corporation and The Bank of New York, as Rights Agent. (Form 8-K dated March 5, 1999, File No. 1-13739 -- Exhibit 4.)
*4(r)(1)	--	TEP Credit Agreement dated as of May 1, 2005, among TEP, the Lenders Party Thereto, the Issuing Banks Party Thereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, and Allied Irish Banks, P.L.C., as Documentation Agent. (Form 8-K dated March 31, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4(a).)
*4(s)(1)	--	Note Purchase and Guaranty Agreement dated August 11, 2003 among UNS Gas, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.2.)

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*4(t)(1)	--	Note Purchase and Guaranty Agreement date August 11, 2003 among UNS Electric, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.3.)
*4(u)(1)	--	Indenture dated as of March 1, 2005, to The Bank of New York, as Trustee. (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.1).
*4(v)(1)	--	Registration Rights Agreement dated as of March 1, 2005, between UniSource Energy Corporation and Credit Suisse First Boston LLC, as representative of the several initial purchasers. (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.2).
*4(w)(1)	--	Credit Agreement dated as of April 15, 2005, among UniSource Energy, the Lenders Party Hereto, The Bank of new York, as Syndication Agent, Commerzbank AG, New York and Grand Cayman Branches, as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent and Lead Arranger. (Form 8-K dated April 18, 2005, File Nos. 1-5924 and 1-1339 - Exhibit 4.1).
*4(x)(1)	--	Credit Agreement dated as of April 15, 2005, among UNS Electric and UNS Gas, UniSource Energy Services as Guarantor, and the Banks Named Herein and the Other Lenders from Time to Time party Hereto, The Bank of New York, as Syndication Agent, Wells Fargo Bank, National Association, as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent and Lead Arranger. (Form 8-K dated April 18, 2005, File Nos. 1-5924 and 1-1339 - Exhibit 4.2 and 4.3).
*10(a)(1)	--	Lease Agreements, dated as of December 1, 1984, between Valencia and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(1).)
*10(a)(2)	--	Guaranty and Agreements, dated as of December 1, 1984, between TEP and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(2).)
*10(a)(3)	--	General Indemnity Agreements, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors; General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc. as Owner Participants; United States Trust Company of New York, as Owner Trustee; Teachers Insurance and Annuity Association of America as Loan Participant; and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(3).)
*10(a)(4)	--	Tax Indemnity Agreements, dated as of December 1, 1984, between General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc., each as Beneficiary under a separate Trust Agreement dated December 1, 1984, with United States Trust of New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia, Lessee, and TEP, Indemnitors. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(4).)
*10(a)(5)	--	Amendment No. 1, dated December 31, 1984, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(5).)
*10(a)(6)	--	Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(6).)
*10(a)(7)	--	Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and

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		Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(7).)
*10(a)(8)	--	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(8).)
*10(a)(9)	--	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(9).)
*10(a)(10)	--	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(10).)
*10(a)(11)	--	Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(11).)
*10(a)(12)	--	Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(12).)
*10(a)(13)	--	Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(13).)
*10(a)(14)	--	Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(14).)
*10(a)(15)	--	Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbell Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar). (Form S-4 Registration No. 33-52860 -- Exhibit 10(f)(15).)
*10(a)(16)	--	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(12).)
*10(a)(17)	--	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine

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		Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(13).)
*10(a)(18)	--	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(14).)
*10(a)(19)	--	Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(19).)
*10(a)(20)	--	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 --Exhibit 10(f)(20).)
*10(a)(21)	--	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(21).)
*10(a)(22)	--	Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(22).)
*10(a)(23)	--	Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(15).)
*10(a)(24)	--	Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(16).)
*10(a)(25)	--	Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(25).)
*10(a)(26)	--	Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at

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		the Springerville Generating Station. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(26).)
*10(a)(27)	--	Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(f)(27).)
*10(b)(1)	--	Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(1).)
*10(b)(2)	--	Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(2).)
*10(b)(3)	--	Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(3).)
*10(b)(4)	--	Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(g)(4).)
*10(b)(5)	--	Lease Supplement No.1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860 -- Exhibit 10(g)(5).)
*10(b)(6)	--	Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(g)(6).)
*10(b)(7)	--	Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and TEP and San Carlos, jointly and severally, as Lessee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(g)(7).)
*10(b)(8)	--	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(8).)
*10(b)(9)	--	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and

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		Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(9).)
*10(b)(10)	--	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(10).)
*10(b)(11)	--	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(11).)
*10(b)(12)	--	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(12).)
*10(b)(13)	--	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(13).)
*10(b)(14)	--	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant.
*10(b)(15)	--	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit, LLC as Owner Participant.
*10(b)(16)	--	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant.
*10(b)(17)	--	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.
*10(b)(18)	--	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit, LLC as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.

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*10(b)(19)	--	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.
*10(c)(1)	--	Amended and Restated Participation Agreement, dated as of November 15, 1987, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Financial Security Assurance Inc., as Surety, Wilmington Trust Company and William J. Wade in their respective individual capacities as provided therein, but otherwise solely as Owner Trustee and Co-Trustee under the Trust Agreement, and Morgan Guaranty, in its individual capacity as provided therein, but Secured Party. (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(1).)
*10(c)(2)	--	Lease Agreement, dated as of January 14, 1988, between Wilmington Trust Company and William J. Wade, as Owner Trust Agreement described therein, dated as of November 15, 1987,between such parties and Ford Motor Credit Company, as Lessor, and TEP, as Lessee. (Form 10-K for the year ended December 31, 1987, File No.1-5924 -- Exhibit 10(j)(2).)
*10(c)(3)	--	Tax Indemnity Agreement, dated as of January 14, 1988, between TEP, as Lessee, and Ford Motor Credit Company, as Owner Participant, beneficiary under a Trust Agreement, dated as of November 15, 1987, with Wilmington Trust Company and William J. Wade, Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(3).)
*10(c)(4)	--	Loan Agreement, dated as of January 14, 1988, between the Pima County Authority and Wilmington Trust Company and William J. Wade in their respective individual capacities as expressly stated, but otherwise solely as Owner Trustee and Co-Trustee, respectively, under and pursuant to a Trust Agreement, dated as of November 15, 1987, with Ford Motor Credit Company as Trustor and Debtor relating to Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (TEP’s Sundt Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(4).)
*10(c)(5)	--	Indenture of Trust, dated as of January 14, 1988, between the Pima County Authority and Morgan Guaranty authorizing Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (Tucson Electric Power Company Sundt Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(5).)
*10(c)(6)	--	Lease Amendment No. 1, dated as of May 1, 1989, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively under a Trust Agreement dated as of November 15, 1987 with Ford Motor Credit Company. (Form 10-K for the year ended December 31, 1990, File No. 1-5924 -- Exhibit 10(i)(6).)
*10(c)(7)	--	Lease Supplement, dated as of January 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(8).)
*10(c)(8)	--	Lease Supplement, dated as of March 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(9).)
*10(c)(9)	--	Lease Supplement No. 4, dated as of December 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(10).)
*10(c)(10)	--	Supplemental Indenture No. 1, dated as of December 1, 1991, between the Pima County Authority and Morgan Guaranty relating to Industrial Lease Development Obligation Revenue

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		Project. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(l)(11).)
*10(c)(11)	--	Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and Morgan Guaranty, as Indenture Trustee and Refunding Trustee, relating to the restructuring of the Registrant’s lease of Unit 4 at the Sundt Generating Station. (Form S-4, Registration No. 33-52860 -- Exhibit 10(i)(12).)
*10(c)(12)	--	Amendment No. 1, dated as of December 15, 1992, to Amended and Restated Participation Agreement, dated as of November 15, 1987, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, Financial Security Assurance Inc., as Surety, and Morgan Guaranty, as Indenture Trustee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(12).)
*10(c)(13)	--	Amended and Restated Lease, dated as of December 15, 1992, between TEP as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(13).)
*10(c)(14)	--	Amended and Restated Tax Indemnity Agreement, dated as of December 15, 1992, between TEP as Lessee and Ford Motor Credit Company, as Owner Participant. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(14).)
*10(d)	--	Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1. (Form S-1, Registration No. 33-55732 -- Exhibit 10(u).)
*10(e)	--	Lease Agreement, dated as of December 15, 1992, between TEP, as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(v).)
*10(f)	--	Tax Indemnity Agreements, dated as of December 15, 1992, between the various Owner Participants parties thereto and TEP, as Lessee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(w).)
*10(g)	--	Restructuring Agreement, dated as of December 1, 1992, between TEP and Century Power Corporation. (Form S-1, Registration No. 33-55732 -- Exhibit 10(x).)
+*10(h)	--	1994 Omnibus Stock and Incentive Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43767.)
+*10(i)	--	Management and Directors Deferred Compensation Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43769.)
+*10(j)	--	TEP Supplemental Retirement Account for Classified Employees. (Form S-8 dated May 21, 1998, File No. 333-53309.)
+*10(k)	--	TEP Triple Investment Plan for Salaried Employees. (Form S-8 dated May 21, 1998, File No. 333-53333.)
+*10(l)	--	UniSource Energy Management and Directors Deferred Compensation Plan. (Form S-8 dated May 21, 1998, File No. 333-53337.)
+10(m)	--	Officer Change in Control Agreement between TEP and Karen G. Kissinger, dated as of December 4, 1998 (including a schedule of other officers who are covered by substantially identical agreements.)

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

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