Uns Energy (UNS) 10-K 2009 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    .

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

Securities registered pursuant toSection 12(b) of the Exchange Act:

		Name of Each Exchange
Registrant	Title of Each Class	on Which Registered
UniSource Energy	Common Stock, no par value	New York Stock Exchange
Corporation

Securities registered pursuant toSection 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.

UniSource Energy Corporation	Yesþ	Noo
Tucson Electric Power Company	Yeso	Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 (Exchange Act).

UniSource Energy Corporation	Yeso	Noþ
Tucson Electric Power Company	Yesþ	Noo

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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.

UniSource Energy Corporation	Yesþ	Noo
Tucson Electric Power Company (1)	Yeso	Noþ

(1) As indicated above, Tucson Electric Power Company is not required to file reports under the Exchange Act. However, Tucson Electric Power Company has filed all Exchange Act reports for the preceding 12 months.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

UniSource Energy Corporation	Yeso	Noo
Tucson Electric Power Company	Yeso	Noo

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.o

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

UniSource Energy Corporation Large Accelerated Filerþ Accelerated Filero Non-accelerated filero Smaller Reporting Companyo

Tucson Electric Power Company Large Accelerated Filero Accelerated Filero Non-accelerated filerþ Smaller Reporting Companyo

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

UniSource Energy Corporation	Yeso	Noþ
Tucson Electric Power Company	Yeso	Noþ

The aggregate market value of UniSource Energy Corporation voting Common Stock held by non-affiliates of the registrant was $933,280,480 based on the last reported sale price thereof on the consolidated tape on June 30, 2009.

At February 23, 2010, 35,941,414 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At February 23, 2010, 32,139,434 shares of Tucson Electric Power Company’s common stock, no par value, were outstanding, all of which were held by UniSource Energy Corporation.

Tucson Electric Power Company meets the conditions set forth in General Instructions (I)(1)(a) and (b) onForm 10-K and is therefore filing this report with the reduced disclosure format.

Documents incorporated by reference: Specified portions of UniSource Energy Corporation’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders are incorporated by reference into Part III.

Table of Contents

Definitions	v
— PART I —
Item 1. — Business	1
Overview of Consolidated Business	1
TEP	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	14
Service Territory and Customers	14
Gas Supply and Transmission	14
Rates and Regulation	15
Environmental Matters	15
UNS Electric	15
Service Territory and Customers	15
Power Supply and Transmission	16
Rates and Regulation	16
Environmental Matters	17
Other	18
Employees	18
Executive Officers of the Registrants	19
SEC Reports Available on UniSource Energy’s Website	20
Item 1A. — Risk Factors	20
Item 1B. — Unresolved Staff Comments	26
Item 2. — Properties	27
TEP Properties	27
UES Properties	28
UED Properties	28
Item 3. — Legal Proceedings	28
Item 4. — Submission of Matters to a Vote of Security Holders	29
— PART II —
Item 5. — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity	29
Item 6. — Selected Consolidated Financial Data	31
UniSource Energy	31
TEP	32
Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
UniSource Energy Consolidated	33
Outlook and Strategies	33
Results of Operations	35
Contribution by Business Segment	36
Liquidity and Capital Resources	36
Tucson Electric Power Company	41
Results of Operations	41

ii

Factors Affecting Results of Operations	49
Liquidity and Capital Resources	53
UNS Gas	60
Results of Operations	60
Factors Affecting Results of Operations	61
Liquidity and Capital Resources	62
UNS Electric	65
Results of Operations	65
Factors Affecting Results of Operations	66
Liquidity and Capital Resources	68
Other Non-Reportable Business Segments	70
Results of Operations	70
Factors Affecting Results of Operations	71
Critical Accounting Policies	71
Recently Issued Accounting Standards	76
Safe Harbor for Forward-Looking Statements	76
Item 7A. — Quantitative and Qualitative Disclosures about Market Risk	77
Item 8. — Consolidated Financial Statements and Supplementary Data	83
Management’s Report on Internal Controls Over Financial Reporting	83
Reports of Independent Registered Public Accounting Firm	84
UniSource Energy Corporation
Consolidated Statements of Income	86
Consolidated Statements of Cash Flows	87
Consolidated Balance Sheets	88
Consolidated Statements of Capitalization	90
Consolidated Statements of Changes in Stockholders’ Equity	91
Tucson Electric Power Company
Consolidated Statements of Income	92
Consolidated Statements of Cash Flows	93
Consolidated Balance Sheets	94
Consolidated Statements of Capitalization	96
Consolidated Statements of Changes in Stockholder’s Equity	97
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies	98
Note 2. Regulatory Matters	108
Note 3. Segment and Related Information	119
Note 4. Commitments and Contingencies	122
Note 5. Utility Plant and Jointly-Owned Facilities	129
Note 6. Debt, Credit Facilities and Capital Lease Obligations	131
Note 7. Fair Value of Financial Instruments Not Carried at Fair Value	138
Note 8. Stockholders’ Equity	139
Note 9. Income Taxes	141
Note 10. Employee Benefit Plans	144
Note 11. Share-Based Compensation Plans	153
Note 12. Fair Value Measurements	157
Note 13. UniSource Energy Earnings Per Share (EPS)	161
Note 14. Related Party Transactions	162
Note 15. Sale of Millennium’s Investment in Sabinas	163
Note 16. Recently Issued Accounting Pronouncements	163
Note 17. Supplemental Cash Flow Information	164
Note 18. Accounting for Derivative Instruments, Trading Activities and Hedging Activities	166
Note 19. Quarterly Financial Data (Unaudited)	169
Item 9. — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	177
Item 9A. — Controls and Procedures	177
Item 9B. — Other Information	177

iii

— PART III —
Item 10. — Directors, Executive Officers and Corporate Governance of the Registrants	178
Item 11. — Executive Compensation	180
Item 12. — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	180
Item 13. — Certain Relationships and Related Transactions, and Director Independence	181
Item 14. — Principal Accountant Fees and Services	181
— PART IV —
Item 15. — Exhibits and Financial Statements Schedules	182
Signatures	183
Exhibit Index	186
Exhibit 4(i)(10)
Exhibit 4(aa)(9)
Exhibit 12(a)
Exhibit 12(b)
Exhibit 21
Exhibit 23
Exhibit 24(a)
Exhibit 24(b)
Exhibit 31(a)
Exhibit 31(b)
Exhibit 31(c)
Exhibit 31(d)
Exhibit 32

iv

DEFINITIONS

The abbreviations and acronyms used in the 2009 Form 10-K are defined below:

1992 Mortgage	TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York Mellon, successor trustee, as supplemented.
1999 Settlement Agreement	TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for electric retail competition and transition asset recovery.
2008 TEP Rate Order	A rate order issued by the ACC resulting in a new retail rate structure for TEP, effective December 1, 2008.
ACC	Arizona Corporation Commission.
ALJ	Administrative Law Judge.
AMT	Alternative Minimum Tax.
APS	Arizona Public Service Company.
BART	Best Available Retrofit Technology.
BMGS	Black Mountain Generating Station.
Btu	British thermal unit(s).
CCB	Coal combustion byproducts.
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.
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.
DSM	Demand side management.
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.
EL Paso	El Paso Electric Company.
EPNG	El Paso Natural Gas Company.
ESP	Energy Service Provider.
Express Line	A dedicated 345-kV transmission line from Springerville Unit 2 to TEP’s retail service area.
FERC	Federal Energy Regulatory Commission.
Fixed CTC	Competition Transition Charge of approximately $0.009 per kWh that was included in TEP’s retail rate for the purpose of recovering TEP’s TRA. Approximately $58 million will be credited to customers through the PPFAC.
Four Corners	Four Corners Generating Station.
GHG	Greenhouse gases.
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.
IRS	Internal Revenue Service.
kWh	Kilowatt-hour(s).
kV	Kilovolt(s).
LIBOR	London Interbank Offered Rate.

v

Luna	Luna Energy Facility.
Mark-to-Market Adjustments	Forward energy sales and purchase contracts that are considered to be derivatives are adjusted monthly by recording unrealized gains and losses to reflect the market prices at the end of each month.
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy.
MMBtu	Million British Thermal Units.
Mortgage Bonds	Bonds issued under the 1992 Mortgage.
MW	Megawatt(s).
MWh	Megawatt-hour(s).
Navajo	Navajo Generating Station.
NERC	North American Electric Reliability Corporation.
NOx	Nitrogen oxide.
PGA	Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers.
Pima Authority	The Industrial Development Authority of the County of Pima.
PNM	Public Service Company of New Mexico.
PNMR	PNM Resources.
PPA	Purchased Power Agreement.
PPFAC	Purchased Power and Fuel Adjustment Clause.
PWMT	Pinnacle West Marketing and Trading.
REST	Renewable Energy Standard and Tariff rules approved by the ACC in October 2006.
Repurchased Bonds	$221 million of fixed-rate tax-exempt bonds that TEP purchased from bondholders on May 11, 2005.
Rules	Retail Electric Competition Rules.
Sabinas	Carboelectrica Sabinas, S. de R.L. de C.V., a Mexican limited liability company. Prior to June 2009, Millennium owned 50% of Sabinas.
San Carlos	San Carlos Resources Inc., a wholly-owned subsidiary of TEP.
San Juan	San Juan Generating Station.
SO2	Sulfur dioxide.
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 Leases	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.
Springerville Unit 3	Unit 3 of the Springerville Generating Station.
Springerville Unit 4	Unit 4 of the Springerville Generating Station.
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.
Sundt Unit 4	Unit 4 of the H. Wilson Sundt Generating Station.
SWG	Southwest Gas Corporation.
TEP	Tucson Electric Power Company, the principal subsidiary of UniSource Energy.
TEP Credit Agreement	Amended and Restated Credit Agreement between TEP and a syndicate of Banks, dated as of August 11, 2006.
TEP Letter of Credit Facility	Letter of credit facility between TEP and a syndicate of Banks, dated as of April 30, 2008.
TEP Revolving Credit Facility	Revolving credit facility under the TEP Credit Agreement.

vi

Therm	A unit of heating value equivalent to 100,000 British thermal units (Btu).
TRA	Transition Recovery Asset, a $450 million regulatory asset established in TEP’s 1999 Settlement Agreement that was fully recovered in May 2008.
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.
UniSource Energy Credit Agreement	Amended and Restated Credit Agreement between UniSource Energy and a syndicate of banks, dated as of August 11, 2006.
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.
UNS Gas/UNS Electric Revolver	Revolving credit facility under the Amended and Restated Credit Agreement among UNS Gas and UNS Electric as borrowers, and UES as guarantor, and a syndicate of banks, dated as of August 11, 2006.
Valencia	Valencia power plant owned by UNS Electric.
WAPA	Western Area Power Administration.

vii

PART I

This combined Form 10-K is being filed separately by UniSource Energy Corporation and Tucson Electric Power Company (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. TEP does not make any representation as to information relating to any other subsidiary of UniSource Energy.

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. (SeeItem 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 the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), UniSource Energy Development Company (UED) and Millennium Energy Holdings, Inc. (Millennium). We conduct our business in three primary business segments — TEP, UNS Gas and UNS Electric.

TEP, an electric utility, provides electric service to the community of Tucson, Arizona. 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.

UED developed and owns the Black Mountain Generating Station (BMGS), a natural gas-fired combustion turbine in Northern Arizona that, through a power sales agreement, provides energy to UNS Electric.

Millennium has existing investments in unregulated businesses that represent 1% of UniSource Energy’s total assets as of December 31, 2009; no new investments are planned in Millennium.

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.

K-1

BUSINESS SEGMENT CONTRIBUTIONS

The table below shows the contributions to our consolidated after-tax earnings by our three business segments.

	2009		2008			2007
	-Millions of Dollars-
TEP	$	89	$	4		$	53
UNS Gas		7		9			4
UNS Electric		6		4			5
Other(1)		2		(3	)		(4	)
Consolidated Net Income	$	104	$	14		$	58

⁽¹⁾ Includes: UniSource Energy parent company expenses; income and losses from Millennium investments and UED and interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement.

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

Rates and Regulation of Business Segments

The Arizona Corporation Commission (ACC) regulates portions of TEP, UNS Gas and UNS Electric’s utility accounting practices and electricity rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. Our regulated utilities’ rates for retail electric and natural gas service are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on rate base. Rate base is generally determined by reference to the original cost and reconstruction (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, additions to utility plant in service increase rate base and depreciation and retirement of utility plant reduce the rate base.

The Federal Energy Regulatory Commission (FERC) regulates the terms and prices of transmission services and wholesale electricity sales, wholesale transport and purchases of natural gas and portions of our accounting practices. TEP and UNS Electric have FERC tariffs to sell power at market based rates.

TEP

TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UniSource Energy. In 2009, TEP’s electric utility operations contributed 79% of UniSource Energy’s operating revenues and comprised 81% of its assets.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to approximately 402,000 retail customers in Southeastern Arizona. TEP’s service territory consists of a 1,155 square mile area and includes a population of approximately 1 million in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP holds franchises 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

TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases and other governmental entities. TEP’s retail sales are influenced by several factors, including seasonal weather patterns and overall economic climate.

K-2

The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years. The retail energy consumption by customer class through 2012 is expected to be similar to the historical distribution.

	2009			2008			2007
Residential		42	%		41	%		42	%
Commercial		21	%		21	%		21	%
Non-mining Industrial		23	%		24	%		24	%
Mining		11	%		11	%		10	%
Public Authority		3	%		3	%		3	%

Two of TEP’s largest retail customers are in the copper mining industry. TEP’s kWh sales to mining customers depend on a variety of factors including changes in supply and demand in the world copper market and the economics of self-generation.

Local, regional, and national economic factors can impact the level of customer growth and the financial condition and operations of TEP’s large commercial and industrial customers and as a result directly impact energy consumption. Economic conditions can also impact sales to residential and small commercial customers if employment and consumer spending levels change.

As a result of weak economic conditions during 2008 and 2009, retail customer growth and energy usage by retail customers at TEP were below the average levels experienced in prior years. In 2008 and 2009, TEP’s average number of retail customers increased by less than 1% per year. This compares with average annual increases of 2% from 2003 to 2007.

TEP’s total retail kWh sales decreased by 1.4% in 2008 compared with 2007. This was the first year-over-year decrease in TEP’s retail kWh sales since 2002. In 2009, TEP’s kWh sales once again declined by 1.4% over the prior year’s levels. This compares with average annual increases in retail kWh sales of 4% from 2003 to 2007. We cannot predict if the customer growth rate or sales volumes will return to historic levels. However, we expect TEP’s customer base to grow at a rate of less than 1% in 2010 and approximately 1% in 2011.

Energy Service Providers

In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP); however, none of TEP’s retail customers are currently being serviced by an alternative ESP. SeeRates and Regulation,below for more information regarding the status of retail competition in Arizona.

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 TEP to supply power on demand (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions. SeePurchases and Interconnections, below.

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

Long-term sales

Long-term wholesale sales contracts are for periods of more than one year. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers. TEP currently has long-term contracts with three entities to sell firm capacity and energy:

• Salt River Project Agricultural Improvement and Power District (SRP), 100 MW, expires in May 2016. Under the current terms of the contract, TEP receives an annual demand charge of approximately $22 million, while the cost of the energy sold is based on TEP’s average generation cost. Beginning in June 2011, SRP will purchase 876 MWhs annually, TEP will not receive a demand charge and the price of energy will be based on a slight discount to the Dow Jones Palo Verde Electricity Price Indexes (Palo Verde Index).

• Navajo Tribal Utility Authority (NTUA) expires in December 2015. TEP serves the portion of NTUA’s load that is not served from NTUA’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225 MWh. Beginning in 2010, the price of 50% of the kWh sales from June to September will be based on the Palo Verde Index.

• Tohono O’odham Utility Authority, 2 MW, expires in 2014.

K-3

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. Beginning January 1, 2009, all revenues from short-term wholesale sales offset fuel and purchased power costs that are passed through to TEP retail customers. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. SeeRates and Regulation,below.

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations,for additional discussion of TEP’s wholesale marketing activities.

GENERATING AND OTHER RESOURCES

At December 31, 2009, TEP owned or leased 2,229 MW of net generating capability, as set forth in the following table:

							Net
	Unit			Date		Fuel	Capability		Operating	TEP’s Share
Generating Source	No.		Location	In Service		Type	MW		Agent	%		MW
Springerville Station(1)		1	Springerville, AZ		1985	Coal		387	TEP		100.0		387
Springerville Station		2	Springerville, AZ		1990	Coal		390	TEP		100.0		390
San Juan Station		1	Farmington, NM		1976	Coal		340	PNM		50.0		170
San Juan Station		2	Farmington, NM		1973	Coal		340	PNM		50.0		170
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
Luna Energy Facility		1	Deming, NM		2006	Gas		570	PNM		33.3		190
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
DeMoss Petrie			Tucson, AZ		1972	Gas/Oil		122	TEP		100.0		122
North Loop			Tucson, AZ		2001	Gas		95	TEP		100.0		95
Springerville Solar Station			Springerville/Tucson, AZ		2002-2005	Solar		5	TEP		100.0		5
Total TEP Capacity(2)													2,229

(1)	Leased assets, as of December 31, 2009.
(2)	Excludes 781MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2009, total owned capacity was 1,686 MW and leased capacity was 543 MW.

Springerville Generating Station

Springerville Unit 1 is leased by TEP. The Springerville Generating Station also includes the Springerville Coal Handling Facilities and the Springerville Common Facilities.

The terms of the Springerville Unit 1 Leases, which include a 50% interest in the Springerville Common Facilities, expire in 2015, but have optional fair market value renewal and purchase provisions. In 1985, TEP sold and leased back a 50% interest in the Springerville Common Facilities. The Springerville Common Facilities Leases, which expire in 2017 and 2021, have a fixed price purchase provision. The fixed prices to acquire the leased interests in the Springerville Common Facilities are $38 million in 2017 and $68 million in 2021. In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. The terms of the Springerville Coal Handling Facilities Leases expire in 2015, but have a fixed price purchase provision of $120 million.

K-4

Since entering into the Springerville leases, TEP has purchased a 14% equity ownership interest in the Springerville Unit 1 Leases and a 13% equity ownership interest in the Springerville Coal Handling Facilities Leases.

Sundt Generating Station

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

Sundt Unit 4 is leased by TEP and the term of the lease expires in 2011. In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4 from the equity owner for approximately $52 million. The purchase price is subject to increase by 0.75% of the purchase price per month in the event that the purchase occurs after March 31, 2010. TEP expects the purchase to occur prior to March 31, 2010. Following the completion of the transaction, TEP expects to redeem the outstanding Sundt Unit 4 lease obligation of $5 million, terminate the lease and cause the title of Sundt Unit 4 to be transferred to TEP.

SeeNote 6 of Notes to Consolidated Financial Statements, Debt, Credit Facilities, and Capital Lease Obligations,andItem 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.

Renewable Energy Resources

Owned Resources

The Springerville Solar Generating Station includes 34,980 photovoltaic (PV) modules located near TEP’s coal-fired Springerville Generating Station in eastern Arizona. TEP began building the system in 2000 and continued to expand it for several years until its capacity reached 4.6 megawatts in 2004. A proposal to expand its capacity to 6.4 MW in 2010 is pending before the ACC.

TEP also has proposed a 1.6 MW PV installation in Tucson, Arizona. If approved by the ACC, the project is expected to be completed in the second half of 2010.

Purchased Power Agreements

In September 2009, TEP filed two 20 year purchased power agreements with the ACC in order to meet the requirements of the ACC’s Renewable Energy Standard and Tariff (REST). The first agreement would provide TEP with 25 MW of energy from a single axis tracking PV installation. The second agreement would provide TEP with 5 MW of energy from a parabolic trough concentrating solar facility. Each agreement contains an option that would allow TEP to purchase all or part of the project at a future period. TEP cannot predict when or if the ACC will approve the agreements. SeeRenewable Energy Standard and Tariff,below for more information.

Purchases and Interconnections

TEP purchases power from other utilities and power marketers. 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 for resale to certain wholesale customers under load and resource management agreements.

TEP typically uses generation from its gas-fired units supplemented by purchased power to meet the summer peak demands of its retail customers. Some of these purchased power contracts are price indexed 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 also purchases 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.

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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.

As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject to mandatory reliability standards that are developed and enforced by the North American Electric Reliability Corporation (NERC) subject to the oversight of the Federal Energy Regulatory Commission (FERC). TEP is reviewing its operating policies and procedures to ensure continued compliance with these standards.

Springerville Units 3 and 4

Springerville Units 3 and 4 are each 400 MW coal-fired generating facilities located at the same site as Springerville Units 1 and 2 that are operated, but not owned by TEP. Tri-State is leasing 100% of Unit 3 from a financial owner. Unit 4 began commercial operation in December 2009 and is owned by SRP. For operating Units 3 and 4, TEP receives rental payments and other fees, including the allocation of a portion of the fixed costs of the existing common facilities to Units 3 and 4. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations. Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4.

Peak Demand and Resources

Peak Demand	2009			2008			2007			2006			2005
							-MW-
Retail Customers		2,354			2,376			2,386			2,365			2,225
Firm Sales to Other Utilities		385			394			369			331			342
Coincident Peak Demand (A)		2,739			2,770			2,755			2,696			2,567
Total Generating Resources		2,229			2,204			2,204			2,194			2,004
Other Resources(1)		781			966			785			719			788
Total TEP Resources (B)		3,010			3,170			2,989			2,913			2,792
Total Margin (B) — (A)		271			400			234			217			225
Reserve Margin (% of Coincident Peak Demand)		10	%		14	%		8	%		8	%		9	%

⁽¹⁾ Other Resources include firm power purchases and interruptible retail and wholesale loads. Additional firm power purchases were made in 2009 to displace more expensive owned gas generation.

Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand varies from year-to-year due to weather, economic conditions and other factors. TEP’s retail demand peaked in 2007 and subsequently declined in 2008 and 2009 due primarily to weak economic conditions.

The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s total 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’s reserve margin in 2009 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.

Forecasted retail peak demand for 2010 is approximately 2,284 MW, compared with actual peak demand of 2,354 MW in 2009. In 2009, cooling degree days were 13% above the ten year average. TEP’s 2010 estimated retail peak demand is based on normal weather patterns and total retail kWh sales similar to 2009 levels. TEP believes it will have sufficient resources to meet expected demand in 2010 with its existing generation capacity and power purchase agreements.

Future Generating Resources

TEP will continue to add peaking resources to serve the Tucson area as needed based upon our forecasts of retail and firm wholesale load, as well as statewide transmission infrastructure. TEP projects that additional import capacity and/or additional local generation resources of 75 to 150 MW may be required in 2015.

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FUEL SUPPLY

Fuel Summary

Fuel cost and usage information is provided below:

	Average Cost per MMBtu						Percentage of Total Btu
	Consumed						Consumed
	2009		2008		2007		2009			2008			2007
Coal	$	2.11	$	2.08	$	1.81		90	%		93	%		92	%
Gas	$	4.51	$	8.02	$	8.30		10	%		7	%		8	%
All Fuels	$	2.34	$	2.52	$	2.30		100	%		100	%		100	%

Coal

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and Colorado. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices. The average cost per ton of coal, including transportation, for 2009, 2008, and 2007 was $39.81, $39.67, and $34.71, respectively.

				Average
		Contract		Sulfur
Station	Coal Supplier	Expiration		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		0.4	%	Navajo and Hopi Indian Tribes
Sundt	Rio Tinto Energy America						Colowyo Mine / McKinley Mine
	/ Chevron Mining Company		—		0.4	%

(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 operator, and the sole owner (or lessee), 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 approximately 200 miles by railroad from Northwestern New Mexico. TEP expects coal reserves to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their presently estimated remaining lives.

The coal supplies for Sundt are transported approximately 1,300 miles by railroad from Colorado and approximately 500 miles from New Mexico. In the past, Sundt Unit 4 has been fueled by coal; however, the generating station can also be operated with natural gas or landfill gas. Both fuels are combined with methane, a renewable energy resource, piped from a nearby landfill. From January through October 2009, TEP used natural gas to fuel Sundt Unit 4. TEP hedged the price of natural gas such that it became more economic to use natural gas instead of coal to fuel the plant. TEP had agreements for the purchase and transportation of coal to Sundt through 2009 and has adequate coal inventory through 2010. TEP will continue to analyze natural gas prices to determine the fuel it will use to run Sundt Unit 4.

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual ObligationsandNote 4 of Notes to Consolidated Financial Statements — Commitments and Contingencies, TEP Commitments, Firm Purchase and Transportation Commitments.

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Generating Facilities Operated by Others

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan. Four Corners and San Juan, operated by PNM, are mine mouth generating stations located adjacent to the coal reserves. Navajo, operated by SRP, obtains its coal supply from a nearby coal mine and a dedicated rail delivery system. The 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 presently estimated lives of the stations.

Natural Gas Supply

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 gas from Southwest Gas Corporation (SWG) under a retail tariff for North Loop, a 95 MW internal combustion turbine located in Tucson, Arizona, and receives distribution service under a transportation agreement for DeMoss Petrie, a 122 MW internal combustion turbine located in Tucson, Arizona. TEP completed a bypass of SWG and connected the Sundt plant directly to El Paso Natural Gas Company (ENPG) in the first quarter of 2008. TEP purchases capacity from EPNG for transportation from the San Juan and Permian Basins to its Sundt plant under a contract that expires in April 2013, with right-of-first refusal for continuation thereafter. TEP buys gas from third party suppliers for Sundt and DeMoss Petrie.

TEP purchases gas transportation for Luna from EPNG from the Permian Basin to the plant site under an agreement that expires in January 2012, with right-of-first refusal for continuation thereafter. TEP purchases gas for its share of Luna from various suppliers in the Permian Basin region.

WATER SUPPLY

The Four Corners region of New Mexico, where the San Juan and Four Corners Generating Stations (San Juan and Four Corners) are located, experiences drought conditions periodically that could affect the water supply for these plants. The operating agents for San Juan and Four Corners have negotiated supplemental water contracts with BHP Billiton and the Jicarilla Apache Nation to assist the generating plants in meeting their water requirements in the event of a shortage.

Drought conditions within the Southwestern United States, combined with increased water usage in Arizona, Nevada and Southern California, have periodically caused water levels to recede at Lake Powell, which supplies operating water for the Navajo Generating Station (Navajo). TEP has a 7.5% ownership interest in Navajo Units 1, 2 and 3 (168 MW capacity). A project was completed in December 2009, which lowered the water intake structures to ensure adequate water supply at Navajo in the event drought conditions adversely affect the water level at Lake Powell.

TRANSMISSION ACCESS

TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers. TEP is taking steps to increase the capacity and reliability of its transmission and distribution system. TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability and efficiency of its existing transmission and distribution systems.

In 2008, TEP completed construction of a new 500 kV transmission line from the Palo Verde regional market hub to the Pinal West substation along with a new 345 kV TEP substation at Pinal West connecting to TEP’s 345kV transmission line between Phoenix and Tucson. These projects provide TEP with additional access to energy resources.

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TEP is participating in the continuation of the 500 kV transmission line from the Pinal West substation to the Pinal Central substation. TEP is also in the process of obtaining permits to construct a 40 mile 500-kV transmission line from the Pinal Central substation to the Tortolita substation northwest of Tucson to further enhance its ability to access the region’s energy resources. TEP expects the transmission lines to be in-service in 2014. As a result of these high voltage transmission additions, TEP anticipates that its ability to import energy into its service territory should increase by at least 250 MW.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement initiated in 2000 for the joint construction of a 62-mile transmission line from Tucson to Nogales, Arizona. The project was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales, Arizona. Since receiving ACC approval of the location and construction of the proposed 345-kV transmission line along a specified route, TEP has been working to obtain all other required permits from state and federal agencies. The Department of Energy completed a Final Environmental Impact Statement (FEIS) for the project accepting any of the routes identified in the FEIS. The U.S. Forest Service, however, prefers a route that was not approved by the ACC.

Based on the alternative proposals and passage of time since the ACC approved the location of the line, in 2006 the Line Siting Committee of the ACC was directed to gather facts related to options for improving service reliability in Nogales, Arizona. TEP continues to evaluate alternatives for improving service reliability in Nogales, Arizona. In 2007 and 2008, TEP met with major property owners and impacted governmental agencies along the proposed transmission line routes to discuss alternatives. If all regulatory approvals are received and the project moves forward, the future costs to construct the transmission line from Tucson to Nogales, Arizona are expected to be approximately $120 million. As of December 31, 2009, TEP had capitalized $11 million related to the project, including $2 million of land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes that cost recovery is probable for prudent and reasonably incurred costs related to the project as a consequence of the ACC’s requirement for a second transmission line serving the Nogales, Arizona area.

TEP met with the Federal Electricity Commission of Mexico (CFE) and other transmission developers in 2009 to develop a schedule for performing transmission studies to interconnect the proposed Tucson to Nogales transmission line to a new CFE proposed 400-kV transmission line in Mexico. The studies are scheduled to be completed in 2010.

RATES AND REGULATION

2008 TEP Rate Order

On November 25, 2008, the ACC issued an order that resolved a rate case filed by TEP in July 2007. The ACC order included an average base retail rate increase of approximately 6% effective December 1, 2008 and a Purchased Power and Fuel Adjustment Clause (PPFAC) that began January 1, 2009. Prior to the 2008 TEP Rate Order, TEP’s rates had remained unchanged since 2000.

The 2008 TEP Rate Order requires TEP to credit $58 million of previously collected Fixed CTC true-up revenues to customers through the PPFAC. TEP expects the PPFAC charge to be zero until the Fixed CTC true-up revenues are fully credited over an estimated period of 36 to 48 months, which began on April 1, 2009.

For a more detailed description of the terms of the 2008 TEP Rate Order, seeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company,Factors Affecting Results of Operations,2008 TEP Rate Order, below.

Renewable Energy Standard and Tariff

The ACC’s REST requires TEP and other affected utilities to generate or purchase at least 15% of their total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years. The REST rules provide for recovery of above market costs a utility incurs in providing the renewable energy. TEP met the 2009 REST rules’ target of generating or purchasing renewable energy for at least 2.0% of TEP’s total retail energy requirements; TEP expects to meet the REST rules’ 2010 target of 2.5%.

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For more information seeRenewable Energy Resources,above, andItem 7. Management’s Discussion and Analysis, Tucson Electric Power, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff.

Electric Energy Efficiency Standards

In December 2009, the ACC established a process to adopt new Electric Energy Efficiency Standards (EE Standards) designed to require TEP, UNS Electric and other affected utilities to implement demand-side management (DSM) programs, to the extent that they are cost effective. If the ACC approves EE Standards, they must be certified by the Arizona Attorney General before taking effect. TEPs DSM programs and customer surcharge to recover the costs incurred to implement these proposed programs are subject to ACC approval. SeeItem 7. – Management’s Discussion and Analysis of Financial ConditionandResults of Operations,TEP, Factors Affecting Results of Operations, Electric Energy Efficiency Standards,for more information.

Retail Electric Competition Rules

In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC rules that enabled ESPs to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2005. In 2008, the ACC opened an administrative proceeding to address the Rules. Unless and until the ACC clarifies the competition rules and ESPs offer to provide energy in TEP’s service area, it is not possible for TEP’s retail customers to use alternative ESPs. We cannot predict what changes, if any, the ACC will make to the Rules. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Competition,for more information.

Line Extension Policy

In 2008, the ACC approved a policy requiring TEP to charge customers for the total cost of line extensions, eliminating TEP’s prior practice of providing a portion of line extensions free of charge to its customers. The policy became effective June 1, 2009. Prior to this ruling by the ACC, a portion of the cost of line extensions was capitalized by TEP and eligible for inclusion in rate base.

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TEP’S UTILITY OPERATING STATISTICS

	For Years Ended December 31,
	2009			2008			2007		2006		2005
Generation and Purchased Power — kWh (000)
Remote Generation (Coal)		9,576,873			10,438,864			11,001,318		10,854,710		10,059,315
Local Tucson Generation (Oil, Gas & Coal)		711,420			1,039,362			1,088,778		966,476		1,165,001
Purchased Power		3,085,805			2,947,749			2,046,864		1,680,495		1,638,737
Total Generation and Purchased Power		13,374,098			14,425,975			14,136,960		13,501,681		12,863,053
Less Losses and Company Use		948,463			954,643			944,024		885,120		806,168
Total Energy Sold		12,425,635			13,471,332			13,192,936		12,616,561		12,056,885
Sales — kWh (000)
Residential		3,905,696			3,852,707			4,004,797		3,778,269		3,633,226
Commercial		1,988,356			2,034,453			2,057,982		1,959,141		1,855,432
Industrial		2,160,946			2,263,706			2,341,025		2,278,244		2,302,327
Mining		1,064,830			1,095,962			983,173		924,898		842,881
Public Authorities		250,915			255,817			247,430		260,767		241,119
Total — Electric Retail Sales		9,370,743			9,502,645			9,634,407		9,201,419		8,874,985
Electric Wholesale Sales		3,054,892			3,968,688			3,558,529		3,415,142		3,181,900
Total Electric Sales		12,425,635			13,471,332			13,192,936		12,616,561		12,056,885
Operating Revenues (000)
Residential	$	377,761		$	351,079		$	362,967	$	343,459	$	330,614
Commercial		219,694			211,639			213,364		203,284		192,966
Industrial		163,720			164,849			168,279		165,068		165,988
Mining		61,033			55,619			48,707		43,724		39,749
Public Authorities		19,865			19,146			18,332		18,935		17,559
REST and DSM		25,443			2,781			—		—		—
EFPS		—			415			4,822		2,684		2,624
Total — Electric Retail Sales		867,516			805,528			816,471		777,154		749,500
CTC To Be Refunded		—			(58,092	)		—		—		—
Wholesale Revenue-Long Term		48,249			57,493			55,788		51,442		54,901
Wholesale Revenue-Short Term		83,456			185,189			125,369		112,309		117,557
California Power Exchange Provision for Wholesale Refunds		(4,172	)		—			—		—		—
Transmission		18,974			17,173			14,842		13,391		7,250
Other Revenues		82,688			71,962			58,033		34,698		8,262
Total Operating Revenues	$	1,096,711		$	1,079,253		$	1,070,503	$	988,994	$	937,470
Customers (End of Period)
Residential		365,157			363,861			361,945		357,646		350,628
Commercial		35,759			35,432			34,759		34,104		33,534
Industrial		629			633			641		664		673
Mining		2			2			2		2		2
Public Authorities		61			61			61		61		61
Total Retail Customers		401,608			399,989			397,408		392,477		384,898
Average Retail Revenue per kWh Sold (cents)
Residential		9.7			9.1			9.1		9.1		9.1
Commercial		11.0			10.4			10.4		10.4		10.4
Industrial and Mining		7.0			6.6			6.6		6.6		6.5
Average Retail Revenue per kWh Sold		9.3			8.5			8.5		8.4		8.4
Average Revenue per Residential Customer	$	1,034		$	965		$	1,003	$	971	$	954
Average kWh Sales per Residential Customer		10,708			10,621			11,129		10,681		10,484

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ENVIRONMENTAL MATTERS

Air and water quality, resource extraction, waste disposal and land use are regulated by federal, state and local authorities. TEP believes that its facilities are in substantial compliance with existing regulations.

Clean Air Act Requirements

TEP generating facilities are subject to EPA limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other emissions into the atmosphere. TEP capitalized $24 million in 2009, $73 million in 2008 and $7 million in 2007 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan described below. TEP expects to capitalize environmental compliance costs of $8 million in 2010 and $5 million in 2011. In addition, TEP recorded operating expenses of $13 million in 2009, $14 million in 2008 and $10 million in 2007 related to environmental compliance. TEP expects environmental expenses to be $11 million in 2010. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may reduce operating efficiency.

As a result of a 2005 settlement agreement between PNM, environmental activist groups, and the New Mexico Environment Department (PNM Consent Decree), the co-owners of San Juan installed new pollution control equipment at the generating station to reduce mercury, particulate matter, NOx, and SO₂ emissions. TEP owns 50% of San Juan Units 1 and 2. The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan. In 2008 and 2007, TEP’s share of stipulated penalties at San Juan was $1 million and $2 million, respectively. TEP’s share of stipulated penalties at San Juan during 2009 was less than $1 million. TEP cannot deduct these penalties for income tax purposes. With the installation of new pollution control equipment designed to remedy emission violations, we do not expect to incur similar penalties in the future.

In April 2009, APS received a request from the EPA under section 114 of the Clean Air Act seeking information about Four Corners. Four Corners, which is operated by APS, is comprised of five coal-fired generating units. TEP has a 7% ownership interest in two units, totaling 110 MW. APS has responded to the EPA’s request. TEP cannot predict the timing or outcome of this matter.

In 1993, the EPA allocated TEP’s generating units SO₂ Emission Allowances based on past operational history. Beginning in 2000, TEP’s generating units were required to hold Emission Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years. To date, TEP has held sufficient Emission Allowances to comply with the SO₂ regulations.

Hazardous Air Pollutant Requirements

The Clean Air Act requires the EPA to develop an emission limit for hazardous air pollutants that represents the maximum achievable control technology. In October 2009, EPA entered into a consent order to develop a final rule by November 2011.

Depending on the stringency of the EPA rule, emission controls for mercury may be required at some or all coal fired units by 2014 or later. Whether controls are required at a particular unit, the level of control required, and the cost to achieve that level of control will not be known until the rule has been promulgated.

As stipulated in the PNM Consent Decree described above, the co-owners of San Juan installed new pollution control equipment at the generating station to reduce mercury emissions. The installation of mercury emissions controls for San Juan Units 1 and 2 were completed in 2009. These controls are expected to be adequate to achieve compliance with the federal standard.

Arizona adopted mercury emission rules in 2007 requiring a 90% reduction in emission from coal fired units. Due to potential inconsistency between the Arizona rule and the pending EPA rule, in January, 2009, TEP and ADEQ reached an agreement that (1) defers the 90% reduction requirement to 2016, (2) improves regulatory certainty regarding mercury compliance obligations under existing Arizona rules, and (3) achieves mercury reductions substantially similar to those that would be required by the existing Arizona rules. This agreement relates to the Springerville and Sundt generating stations.

In order to comply with the Arizona rule, TEP expects mercury emission control equipment may be required at Springerville by 2016. The associated capital cost for this equipment is estimated to be $6 million at Springerville Units 1 and 2. If the emission control equipment is installed, TEP expects the annual operating expenses to be approximately $3 million, once all installations are completed.

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Climate Change

In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al v. EPA, that carbon dioxide (CO₂) and other greenhouse gases (GHG) are air pollutants under the Clean Air Act. In December 2009, EPA issued a final Endangerment Finding, stating that greenhouse gases endanger public health and welfare. This finding allows EPA to promulgate regulations limiting emissions of greenhouse gases. EPA is in the process of developing regulation limiting greenhouse gases, which once finalized, may impact future generation or modifications of existing plants.

Several pieces of legislation have been introduced at the federal level. In June 2009, the House of Representatives passed the American Clean Energy and Security legislation which included a cap and trade program for GHG. The Senate is considering similar cap and trade legislation with the September 2009 introduction of the Clean Energy Jobs and American Power bill. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific policies or regional initiatives to reduce greenhouse gas emissions. In 2007, the governors of several western states, including the then-governor of Arizona, signed the Western Regional Climate Action Initiative (the Western Climate Initiative) that directed their respective states to develop a regional target for reducing greenhouse gases. The states in the Western Climate Initiative announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020. In 2008, the Western Climate Initiative participants submitted their design recommendation for the Western Climate Initiative cap-and-trade program for greenhouse gas emissions, with an implementation date set for 2012. In February 2010, the Governor of Arizona issued an executive order which, among other things, stated that Arizona will not implement the GHG cap-and-trade proposal advanced by the Western Climate Initiative. The executive order expires December 31, 2012.

Based on the competing proposals to regulate greenhouse gas emissions by federal, state, and local regulatory and legislative bodies and uncertainty in the regulatory and legislative processes, the scope of such requirements and initiatives and their effect on our operations cannot be determined at this time.

Regional Haze

The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility. The operators of the San Juan, Four Corners, and Navajo generating stations submitted BART analyses in 2007 and early 2008. PNM, operator of San Juan, believes the controls being installed at San Juan as a result of the PNM Consent Decree constitute BART and did not recommend installation of any additional pollution control equipment. APS and SRP, the operators of the Four Corners and Navajo generating stations, respectively recommended installing certain additional pollution control equipment in their respective BART analyses. TEP’s share of the cost for the APS recommended pollution control upgrades at Four Corners is estimated to be $6 million. SRP has initiated the pollution control upgrades at Navajo on a voluntary basis. TEP’s $3 million share of these costs is included in the cost estimates section on Clean Air Act Requirements above.

In August 2009, EPA issued an Advanced Notice of Proposed Rulemaking requesting comment on the cost effectiveness and expected visibility improvements of different levels of air pollution controls at Four Corners and Navajo including Selective Catalytic Reduction (SCR). If SCR is determined by the EPA to be BART, the capital cost impact to TEP is estimated to be $42 million for Four Corners, and $50 million for Navajo. The exact level and cost of pollution control required will not be known until final determinations are made by the regulatory agencies. Under the current proposal, controls would need to be in place no earlier than five years following the final determination.

The Four Corners and Navajo Plant participants’ obligations to comply with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to meet their obligations and continue their participation in these plants.

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Coal Combustion Byproducts

The EPA is expected to issue proposed regulations governing the handling and disposal of coal combustion byproducts (CCBs), such as fly ash. The EPA is evaluating options that include regulation of CCBs under solid waste standards, hazardous waste standards, or a combination of both. A proposed rule is expected during the first quarter of 2010. The financial impact to TEP, if any, cannot be determined at this time.

Ozone National Ambient Air Quality Standard

In January 2010, EPA issued a proposed rule to reduce the National Ambient Air Quality Standard for Ozone. Based on the proposed standard, certain counties in which TEP conducts operations could be in violation of the standard. The financial impact to TEP, if any, cannot be determined at this time.

UNS GAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 146,000 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 700,000. From 2003 to 2007, customer growth in UNS Gas’ service territory averaged 3% per year, compared with zero growth in 2008 and less than 1% growth in 2009 in the number of retail customers. As a result of weak economic conditions and mild weather, the average energy use by retail customers during 2008 and 2009 was below the average levels experienced by UNS Gas in prior periods.

UNS Gas’ customer base is primarily residential. Revenues derived from residential customers were approximately 61% of total revenues in 2009, while sales to other retail customer classes accounted for approximately 28% of total revenues. Approximately 11% of total revenues in 2009 were derived from gas transportation services and a Negotiated Sales Program (NSP). UNS Gas supplies 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.

In 2008, UNS Gas and UNS Electric entered into a 20-year gas transportation agreement and a 20-year natural gas sales agreement, whereby UNS Gas will purchase natural gas for UNS Electric and transport it to BMGS.

GAS SUPPLY AND TRANSMISSION

UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased. UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers. These purchases and hedges are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month.

UNS Gas buys most of the gas it distributes from the San Juan Basin in the Four Corners region. The gas is delivered on the El Paso Natural Gas Company (EPNG) and Transwestern Pipeline Company (Transwestern) interstate pipeline systems under firm transportation agreements with combined capacity sufficient to meet UNS Gas’ customers’ demands.

With EPNG, the average daily capacity right of UNS Gas is approximately 655,000 therms per day, with an average of 1,095,000 therms per day in the winter season (November through March) to serve its Northern and Southern Arizona service territories. 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.

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UNS Gas signed a separate transportation agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line. The 15-year agreement began in March 2009, when construction of that pipeline was completed. UNS Gas’ average daily capacity right will be 126,100 therms per day, with an average of 221,900 therms per day in the winter season (November through March).

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Liquidity and Capital Resources, Contractual Obligations, UNS Gas Supply Contracts, for more information.

RATES AND REGULATION

The ACC regulates UNS Gas 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 adjustor. The difference between UNS Gas’ actual monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered or returned to customers through the PGA mechanism. SeeItem 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.

2008 General Rate Case

In November 2008, UNS Gas filed a general rate case with the ACC on a cost of service basis. Below is a table that summarizes UNS Gas’ request:

Test year — 12 months ended June 30, 2008	Requested by UNS Gas
Original cost rate base	$182 million
Revenue deficiency	$9.5 million
Total rate increase (over test year revenues)	6%
Cost of long-term debt	6.5%
Cost of equity	11.0%
Actual capital structure	50% equity / 50% debt
Weighted average cost of capital	8.75%
Rate of return on fair value rate base	6.80%

On June 8, 2009, the ACC staff and other intervenors filed testimony in this proceeding. The ACC staff recommended a rate increase of $3.4 million based on an original cost rate base of $178 million and a 10% ROE. Hearings before an administrative law judge concluded in August 2009. UNS Gas expects the ACC to issue a final order in the first half of 2010. UNS Gas cannot predict the outcome of this general rate case proceeding. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Rates,2008 General Rate Case Filing, for more information.

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 its facilities are in substantial compliance with all existing regulations. SeeItem. 1 — Business, TEP, Environmental Matters, for more information.

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is an electric transmission and distribution company serving approximately 90,000 retail customers in Mohave and Santa Cruz counties. These counties have a combined population of approximately 240,000. As a result of weak economic conditions, retail customer growth and average energy use by retail customers is below the average levels experienced by UNS Electric in prior periods. From 2003 to 2007, customer growth in UNS Electric’s service territory averaged 3% per year, compared with no change in the average number of retail customers during 2008 and less than 1% growth 2009. UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers. Peak demand for 2009 was 559 MW.

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POWER SUPPLY AND TRANSMISSION

Power Supply

In 2008, UNS Electric and UED entered into a Power Purchase and Sales Agreement (PPA) under which UED sells all the output of the 90 MW gas-fired Black Mountain Generating Station (BMGS) to UNS Electric over a five-year term. The PPA is a tolling arrangement in which UNS Electric operates BMGS and assumes all risk of operation and maintenance costs, including fuel. Under the terms of the PPA, UNS Electric pays UED a capacity charge. The costs associated with the PPA are recoverable through UNS Electric’s PPFAC.

UNS Gas and UED have a 20-year gas transportation agreement and a 20-year natural gas sales agreement, whereby UNS Gas will purchase and transport natural gas for UED to BMGS.

UNS Electric owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona. Valencia consists of four gas and diesel-fueled combustion turbine units and provides approximately 68 MW of peaking resources. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas.

In addition to the PPA with UED and the output from Valencia, UNS Electric relies on a portfolio of long, intermediate and short-term purchases to meet customer load requirements.

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resources, Contractual Obligations and Other Non-Reportable Business Segments, UED, below for more information.

Transmission

UNS Electric imports the power it purchases from UED into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has a network transmission service agreement for its primary transmission capacity with WAPA for the Parker-Davis system that expires in May 2017. UNS Electric also has a long-term electric point to point transmission capacity agreement with WAPA for the Southwest Intertie system that expires in 2011.

UNS Electric currently plans to upgrade its existing 115 kV transmission line to 138 kV by the end of 2012 to improve the reliability of service in Santa Cruz County. This upgrade is included in UNS Electric’s current capital expenditures forecast. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resourcesfor more information.

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. In 2007, UNS Electric was granted a FERC tariff to sell power at market based rates. UNS Electric’s retail electric rates include a PPFAC, which allows for UNS Electric to recover the actual costs of its fuel and power purchases.

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2009 General Rate Case Filing

In April 2009, UNS Electric filed a rate case application with the ACC, which is summarized below.

Test year — December 31, 2008
Original cost rate base	$176 million
Revenue deficiency	$13.5 million
Total rate increase (over test year revenues)	7.4%
Cost of debt	7.05%
Cost of equity	11.40%
Actual capital structure	46% equity / 54% debt
Weighted average cost of capital	9.04%
Fair Value Rate Base	$265 million
Rate of Return on Fair Value Rate Base	6.88%

The filing also included a proposal to acquire, and put into its rate base, BMGS, the gas-fired facility in UNS Electric’s service territory that is owned by UED. The proposed acquisition and inclusion of BMGS in rate base would not impact the amount of the total rate increase requested by UNS Electric.

On November 6, 2009, the ACC staff and other intervenors filed testimony in this proceeding. The ACC staff recommended a rate increase of $7.5 million based on an original cost rate base of $168 million and a 10% return on equity. A hearing before an ACC administrative law judge concluded in February 2010. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Rates, for more information.

Electric Energy Efficiency Standards

In December 2009, the ACC established a process to adopt new Electric Energy Efficiency Standards (EE Standards) designed to require TEP, UNS Electric and other affected utilities to implement demand-side management (DSM) programs, to the extent that they are cost effective. If the ACC approves EE Standards, they must be certified by the Arizona Attorney General before taking affect. TEP’s DSM programs and customer surcharge to recover the costs incurred to implement these proposed programs are subject to ACC approval.

SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Electric Energy Efficiency Standards, for more information.

Line Extension Policy

As part of the May 2008 ACC order, UNS Electric is required to charge customers for the total cost of line extensions beginning in March 2010. Prior to this ruling by the ACC, a portion of the cost of line extensions was capitalized by UNS Electric and eligible for inclusion in rate base.

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 its facilities are in substantial compliance with all existing regulations and will be in compliance with expected environmental regulations. SeeItem. 1 — Business, TEP, Environmental Matters, for more information.

Renewable Energy Standard and Tariff

The REST rules require UNS Electric to generate or purchase at least 15% of its total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years. UNS Electric began implementing its ACC approved REST plan on June 1, 2008. UNS Electric met the REST rules’ 2009 target of generating or purchasing renewable energy for at least 2% of UNS Electric’s total retail energy requirements; UNS Electric expects to meet the 2010 requirement of 2.5%. See Item 7. —Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff, for more information.

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Renewable Energy Resources

In February 2010, UNS Electric requested the ACC approve a power purchase agreement that would provide UNS Electric with 11 MW of energy from wind turbine installation near Kingman, Arizona over a 20 year period. The above market cost of power under the agreement would be funded through UNS Electric’s REST surcharge. UNS Electric cannot predict when or if the ACC will approve the agreement. SeeRenewable Energy Standard and Tariff,above for more information.

OTHER

UED

UED completed construction of the 90 MW BMGS in May 2008. SeeUNS Electric, Power Supply and Transmission, above for more information regarding BMGS.

Millennium Investments

Through affiliates, Millennium holds investments in unregulated energy and emerging technology companies. At December 31, 2009, Millennium had an investment balance of $10 million, a $7 million cash balance and a $15 million note, which in total represented less than 1% of UniSource Energy’s total consolidated assets. UniSource Energy has ceased making loans or equity contributions to Millennium and has less than $1 million of remaining funding commitments. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other Non-Reportable Business Segments, Millennium Investments,for more information.

Sabinas

In June 2009, Millennium finalized a sale of its 50% interest in Sabinas. Millennium received an upfront $5 million cash payment in January 2009. Other key terms of the transaction included a three year, 6% interest-bearing, collateralized $15 million note. In June 2009, Millennium recorded a $6 million pre-tax gain on the sale.

EMPLOYEES (As of December 31, 2009)

TEP had 1,358 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 expires in January 2013.

UNS Gas had 197 employees, of which 117 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 2012 and February 2011, respectively.

UNS Electric had 167 employees, of which 29 employees were represented by the IBEW Local No. 387 and 107 employees were represented by the IBEW Local No. 769. The existing agreement with the IBEW Local No. 387 and No. 769 expire in February 2011 and August 2010, respectively.

Southwest Energy Solutions, a wholly-owned subsidiary of Millennium, had 254 employees, of which approximately 95% are represented by unions. Of the employees represented by unions, 226 are represented by IBEW Local No. 1116 and 15 by IBEW Local No. 570; these agreements expire on February 2, 2012, and May 31, 2012, respectively.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers — UniSource Energy

Executive Officers of UniSource Energy, who are elected annually by UniSource Energy’s Board of Directors, are as follows:

				Executive Officer
Name	Age		Position(s) Held	Since
Paul J. Bonavia		58	Chairman, President and Chief Executive Officer		2009
Michael J. DeConcini		45	Senior Vice President and Chief Operating Officer, Transmission and Distribution		1999
Raymond S. Heyman		54	Senior Vice President and General Counsel		2005
Kevin P. Larson		53	Senior Vice President, Chief Financial Officer and Treasurer		2000
Philip Dion III		41	Vice President, Legal and Environmental Services		2008
Kentton C. Grant		51	Vice President, Finance and Rates		2007
Arie Hoekstra		62	Vice President, Generation		2007
David G. Hutchens		43	Vice President, Energy Efficiency and Resource Planning		2007
Karen G. Kissinger		55	Vice President, Controller and Chief Compliance Officer		1998
Steven W. Lynn		63	Vice President, Communications and Government Relations		2003
Thomas A. McKenna		61	Vice President, Engineering		2007
Catherine E. Ries		50	Vice President, Human Resources		2007
Herlinda H. Kennedy		48	Corporate Secretary		2006

Paul J. Bonavia	Mr. Bonavia became Chairman, President and Chief Executive Officer of UniSource Energy and TEP in January 2009. Prior to joining UniSource Energy and TEP, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
Michael J. DeConcini	Mr. DeConcini joined TEP in 1988 and was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003. In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution. In May 2009, he was named Senior Vice President and Chief Operating Officer.
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 UniSource Energy and TEP, Mr. Heyman was a member of the Phoenix, Arizona law firm Roshka, Heyman & DeWulf, PLC.
Kevin P. Larson	Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and at TEP’s investment subsidiaries. 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 serves as Treasurer of both organizations. He was named Senior Vice President in September 2005.
Philip Dion III	Mr. Dion was named Vice President of Legal and Environmental Services at UniSource Energy and TEP in February 2008. Prior to joining TEP, Mr. Dion was chief of staff and chief legal advisor to Commissioner Marc Spitzer of the Federal Energy Regulatory Commission. Mr. Dion previously worked in various roles at the ACC, including as an administrative law judge and as an advisor to Mr. Spitzer, prior to his appointment to FERC.
Kentton C. Grant	Mr. Grant joined TEP in 1995. In January 2007, Mr. Grant was elected Vice President of Finance and Rates at UniSource Energy and TEP.

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Arie Hoekstra	Mr. Hoekstra joined TEP in 1979. In January 2007, Mr. Hoekstra was elected Vice President of Generation at UniSource Energy and TEP.
David G. Hutchens	Mr. Hutchens joined TEP in 1995. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Marketing at UniSource Energy and TEP, and Vice President of UNS Gas.
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. She has served as Chief Compliance Officer of UniSource Energy and TEP since 2003.
Steven W. Lynn	Mr. Lynn joined TEP in 2000. In January 2003, he was elected Vice President of Communications and Government Relations at UniSource Energy and TEP.
Thomas A. McKenna	Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of Millennium) in 1998. In May 2009, Mr. McKenna was named Vice President of UNS Gas. This is in addition to his position as Vice President of Engineering at UniSource Energy and TEP, and Vice President of UNS Electric, to which he was elected in January 2007.
Catherine E. Ries	Ms. Ries joined UniSource Energy and TEP in June 2007 as Vice President of Human Resources. Prior to joining UniSource Energy and TEP, Ms. Ries worked for Clopay Building Products, a division of Griffon Corporation, from 2000 to 2007 and held the position of Vice President of Human Resources prior to joining UniSource Energy and TEP.
Herlinda H. Kennedy	Ms. Kennedy joined TEP in 1980. Ms. Kennedy was named assistant Corporate Secretary of TEP and UniSource Energy in 1999 and was elected Corporate Secretary of UniSource Energy and TEP in September 2006.

Executive Officers — TEP

The executive officers of TEP are the same as UniSource Energy. SeeExecutive Officers — UniSource Energy, above,for a listing and description of TEP’s executive officers.

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 Securities and Exchange Commission (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 Investors 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.

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 SEC. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, financial, environmental and operational.

REVENUES

National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TEP, UNS Gas and UNS Electric.

Economic conditions have contributed significantly to a reduction in TEP’s retail customer growth and lower energy usage by the company’s residential, commercial and industrial customers. From 2003 to 2007, customer growth in TEP’s service territory averaged approximately 2% per year. In 2008 and 2009, as economic conditions worsened, TEP’s average retail customer base grew by less than 1%. In 2009, total retail kWh sales were 1.4% below 2008 levels. TEP estimates that a 1% decrease in annual retail sales could reduce pre-tax net income and pre-tax cash flows by approximately $6 million.

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Similar impacts were felt at UNS Gas and UNS Electric. The retail customer bases at both companies did not grow during 2008 or 2009 compared with average annual growth rates of 3 to 4% from 2003 to 2007. We estimate that a 1% decrease in annual retail sales at UNS Gas and UNS Electric could reduce pre-tax net income and pre-tax cash flows by less than $1 million.

TEP’s base rates are frozen through December 31, 2012, which could limit our ability to cope with the impact of risks and uncertainties and negatively affect TEP’s results of operations, net income and cash flows.

Under the terms of the 2008 TEP rate order, TEP is prohibited from submitting a base rate application before June 30, 2012 and new rates cannot go into effect prior to December 31, 2012. If the cost of serving TEP’s customers rises more quickly than the revenues collected from customers, TEP’s results of operations, net income and cash flows could be negatively impacted.

New technological developments and increasing use of more energy efficient products may have a significant impact on retail sales, which could negatively impact UniSource Energy’s results of operations, net income and cash flows.

Heightened awareness of energy costs and general public support for energy efficiency has increased demand for products intended to reduce consumers’ use of electricity. TEP and UNS Electric also are promoting Demand Side Management programs designed to help customers reduce their energy use, and these efforts may increase significantly under new energy efficiency rules given preliminary approval in 2009 by the ACC. Unless the ACC makes specific provision for the recovery of usage-based revenues lost to these energy efficiency programs, the reduced retail sales that would result from the success of these efforts would negatively impact the results of operations, net income and cash flows of TEP and UNS Electric.

The revenues, results of operations and cash flows of TEP, UNS Gas and UNS Electric are seasonal, and are subject to weather conditions and customer usage patterns, beyond the companies’ control.

TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during Tucson’s hot summer weather. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in its retail service territory. UNS Electric’s earnings follow a similar pattern, while UNS Gas’ sales peak in the winter during home heating season. Cool summers or warm winters may affect customer usage at all three companies, adversely affecting operating revenues, cash flows and net income by reducing sales.

REGULATORY

TEP, UNS Gas and UNS Electric are subject to regulation by the ACC, which sets the companies’ retail rates and oversees many aspects of their business in ways that could negatively affect the companies’ results of operations, net income and cash flows.

The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.

The ACC is charged with setting retail electric and gas rates that provide utility companies with an opportunity to recover their costs of service and earn a reasonable rate of return. The decisions these elected officials make on such matters impact the net income and cash flows of TEP, UNS Gas and UNS Electric.

Changes in federal energy regulation may negatively 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 electric utility subsidiaries are subject to regulation by the 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.

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FINANCIAL

Financial market disruptions and volatility may increase our financing costs, limit our access to the credit markets and increase our pension funding obligations, which may adversely affect our liquidity and our ability to carry out our financial strategy.

We rely on access to the bank markets and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. Market disruptions such as those recently experienced in the United States and abroad may increase our cost of borrowing or adversely affect our ability to access sources of liquidity needed to finance our operations and satisfy our obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties we do business with, unprecedented volatility in the markets where our outstanding securities trade, and general economic downturns in our utility service territories. If we are unable to access credit at competitive rates, or if our borrowing costs dramatically increase, our ability to finance our operations, meet our short-term obligations and execute our financial strategy could be adversely affected.

Changing market conditions could negatively affect the market value of assets held in our pension and other postretirement pension plans and may increase the amount and accelerate the timing of required future funding contributions.

Financial market disruptions and volatility may increase our financing costs and adversely affect our ability to refinance debt obligations and credit agreements totaling $671 million that expire or come due in 2011 at UniSource Energy, TEP, UNS Gas and UNS Electric.

UniSource Energy, TEP, UNS Gas and UNS Electric are each party to a revolving credit agreement with a group of lenders. We rely on these agreements for working capital requirements not provided by cash flow from our operations. We cannot be assured that there will be sufficient lender interest and capacity to refinance these facilities prior to their expiration dates. The following credit agreements and debt obligations mature in August 2011:

Description	Amount
UniSource Energy Credit Agreement	$70 million revolving credit facility
TEP Credit Agreement	$491 million, consisting of a $341 million letter of credit facility and a $150 million revolving credit facility
UNS Gas/UNS Electric Revolver	$60 million revolving credit facility
UNS Gas Senior Unsecured Notes	$50 million

UniSource Energy, TEP, UNS Gas and UNS Electric could have difficulty obtaining funding under their respective revolving credit facilities when required if lenders in the bank group file for bankruptcy or refuse to fund when requested. If sufficient liquidity is not available to meet short-term working capital needs, if we are unable pay off or refinance our debt obligations or if borrowing costs dramatically increase, UniSource Energy, TEP, UNS Gas and UNS Electric’s results of operations, net income and cash flows could be negatively impacted.

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

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

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Restrictions include:

• TEP, UNS Gas and UNS Electric are restricted from lending or transferring funds or issuing securities without ACC approval;

• The Federal Power Act 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; and

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

Economic conditions could adversely impact our ability to comply with financial covenants in the UniSource Energy and TEP Credit Agreements.

The UniSource Energy and TEP credit and reimbursement agreements include a minimum cash flow to interest coverage ratio and a maximum leverage ratio. The leverage ratios are calculated as the ratio of total indebtedness to earnings before interest, taxes, depreciation and amortization. The ability to comply with these covenants could be adversely impacted by lower customer growth rates or sales during an economic downturn. In the event that we seek to renegotiate these provisions to provide additional flexibility, we may need to pay fees or increased interest rates on borrowings as a condition to any amendments or waivers.

UniSource Energy’s net income and cash flows can be adversely affected by rising interest rates.

As of February 23, 2010, TEP had $329 million of tax-exempt variable rate debt obligations. The interest rates on these debt obligations are set weekly with a maximum interest rate of 20%. The average weekly interest rate ranged from 0.25% to 0.79% in 2009. A 1% increase in the average interest rates on this debt, over a twelve month period, would result in an increase in interest expense by approximately $3 million.

UniSource Energy, TEP, UNS Gas and UNS Electric also are subject to risk resulting from changes in the interest rate on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on a spread over LIBOR or an Alternate Base Rate. Each of these agreements is a committed facility and expires in August 2011.

If capital market conditions result in rising interest rates, the resulting increase in the cost of variable rate borrowings would negatively impact UniSource Energy, TEP, UNS Gas and UNS Electric results of operations, net income and cash flows.

TEP, UNS Gas and UNS Electric may be required to post margin under their power and fuel supply agreements which could negatively impact their liquidity.

TEP, UNS Gas and UNS Electric secure power and fuel supply resources to serve their respective retail customers. The agreements under which TEP, UNS Gas and UNS Electric contract for such resources include requirements to post credit enhancement in the form of cash or letters of credit under certain circumstances, including changes in market prices which affect contract values, or a change in creditworthiness of the respective companies.

In order to post such credit enhancement, TEP, UNS Gas and UNS Electric would have to use available cash, draw under their revolving credit agreements, or issue letters of credit under their revolving credit agreements.

The maximum amount TEP may use under its revolving credit facility is $150 million. As of February 23, 2010, TEP had $99 million available to borrow under its revolving credit facility. The maximum amount UNS Gas or UNS Electric may use under their revolving credit facility is $45 million, so long as the combined amount does not exceed $60 million. As of February 23, 2010, UNS Gas and UNS Electric had $45 million and $33 million, respectively, to borrow under their revolving credit facility. From time to time, TEP, UNS Gas and UNS Electric use their respective revolving credit facilities to post collateral. If additional collateral is required, it may negatively impact TEP, UNS Gas and/or UNS Electric’s ability to fund their capital requirements. As of December 31, 2009, TEP, UNS Gas and UNS Electric had posted $1 million, $2 million, and $11 million, respectively, with counterparties.

K-23

UniSource Energy and its subsidiaries have substantial debt which could adversely affect their 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, 2009, the ratio of total debt (including capital lease obligations net of investments in lease debt) to total capitalization for UniSource Energy and its subsidiaries was 70%. This substantial debt level:

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

• could limit UniSource Energy and its subsidiaries’ ability to borrow additional amounts for working capital, capital expenditures, acquisitions, dividends, debt service requirements, execution of its business strategy or other purposes.

The cost of renewing leases 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:

Leased Asset	Expiration		Renewal/Purchase Option
Springerville Unit 1		2015	Fair market value purchase option
Springerville Coal Handling Facilities		2015	Fixed price purchase option of $120 million
Springerville Common Facilities		2017 & 2021	Fixed price purchase option of $106 million
Sundt Unit 4		2011	Agreement to purchase equity entered into January 2010

TEP may renew the leases or purchase the assets when the leases expire at various times between 2011 and 2021. The renewal and purchase options for Springerville Unit 1 are generally for fair market value as determined at that time, whereas fixed purchase price options exist for the coal handling and common facilities leases. Upon expiration of the coal handling and common facilities leases (whether at the end of the initial term or any renewal term), TEP has the obligation under agreements with the Springerville Units 3 and 4 owners to purchase such facilities, and each of the owners of Springerville Units 3 and 4 has the obligation to purchase or continue renting from TEP at 14% and 17% interest, respectively, in these facilities.

ENVIRONMENTAL

UniSource Energy’s utility subsidiaries are subject to numerous environmental laws and regulations that 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 laws and regulations affecting present and future operations, including rules regarding air emissions, water quality, wastewater discharges, solid waste and hazardous waste. Many of these regulations arise from TEP’s reliance on coal as its primary fuel for energy generation.

These laws and regulations can contribute to higher capital, operating and other costs, particularly with regard to enforcement efforts focused on existing power plants and compliance plans with regard to new and existing power plants. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, authorizations and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable laws and regulations might result in the imposition of fines and penalties by regulatory authorities. We cannot provide assurance that existing environmental laws and regulations will not be revised or that new environmental laws and regulations will not be adopted or become applicable to us. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on our results of operations, particularly if those costs are not fully recoverable from our ratepayers.

TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which it has a minority interest and may be obliged to pay similar costs 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.

K-24

New federal regulations to limit greenhouse gas emissions could increase TEP’s cost of operations and result in a change in the composition of TEP’s coal-dominated generating fleet.

Based on the finding by the EPA in December 2009 stating that greenhouse gases endanger public health and welfare, the agency is in the process of developing regulations limiting greenhouse gas emissions. In addition, there are proposals and ongoing studies at the state, federal and international levels to address global climate change that could also result in the regulation of carbon dioxide (CO₂) and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. In 2009, 69% of TEP’s total energy resources came from its coal-fueled generating facilities. Reductions in CO₂ emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. Any future legislation or regulation addressing climate change could produce a number of other results including additional costs to fund energy efficiency activities, costly modifications to, or reexamination of the economic viability of, our existing coal plants or changes in the overall fuel mix of our generating fleet. The impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time.

UniSource Energy could be subject to physical risks associated with climate change.

Climate change may cause physical risks, including an increase in sea level, intensified storms, water scarcity and changes in weather conditions, such as changes in precipitation, average temperatures and extreme weather conditions. A significant portion of the nation’s oil and gas infrastructure is located in areas susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes.

These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the company’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region, it may adversely impact customer demand and revenues. Such physical risks could have an adverse effect on our financial condition, results of operations and liquidity.

OPERATIONAL

The operation of electric generating stations involves risks that could result in unplanned outages or reduced generating capability that could adversely affect TEP’s results of operations, net income and cash flows.

The operation of electric generating stations involves certain risks, including equipment breakdown or failure, interruption of fuel supply and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications occur from time to time and are an inherent risk of our business. If TEP’s generating stations operate below expectations, TEP could be adversely affected.

The operation of electric transmission and distribution systems involves a risk of significant unplanned outages that could adversely affect TEP and UNS Electric’s businesses, results of operations, net income and cash flows.

The operation of electric transmission and distribution systems involves certain risks, including equipment failure and damage caused by storms, fires or other hazards. Unplanned outages occur from time to time and are an inherent risk of our business. If TEP or UNS Electric’s transmission and distribution systems experience a significant failure, TEP or UNS Electric could be adversely affected

K-25

TEP could be subject to penalties as a result of mandatory reliability standards.

As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject to mandatory reliability standards that are developed and enforced by NERC, subject to the oversight of FERC. If we fail to comply with the mandatory reliability standards we could be subject to sanctions, including substantial monetary penalties.

UNS Electric may not be able to secure sufficient energy resources to serve its retail customers.

UNS Electric owns 68 MW of peaking generation resources and is purchasing the output of the 90 MW BMGS from UED through a PPA that extends through May 2013. UNS Electric also relies on short and intermediate term purchased power contracts to meet its retail energy demand. In 2009, UNS Electric’s peak retail demand was 559 MW. UNS Electric procures its projected retail peak demand requirements prior to the start of the summer season. In addition to its owned resources and PPA with UED, UNS Electric has acquired other contract capacity to satisfy 90% and 60% of its projected summer peak demand for 2010 and 2011, respectively. However, UNS Electric cannot predict whether it will be able to obtain sufficient resources to meet its retail energy demand for 2010 and beyond. UNS Electric’s cash flows and net income could be negatively impacted if UNS Electric is unable to secure adequate energy resources to sell to its retail customers.

TEP or UNS Electric may not be able to secure adequate right-of-way to construct transmission lines and may be required to find alternate ways to provide adequate sources of energy and maintain reliability in TEP and UNS Electric’s service areas.

TEP and UNS Electric rely on federal, state and local governmental agencies to secure right-of-way and siting permits to construct transmission lines. If adequate right-of-way and siting permits to build new transmission lines cannot be secured:

• TEP and UNS Electric may need to rely on more costly alternatives to provide energy to their customers;

• TEP and UNS Electric may not be able to maintain reliability in their service areas; or

• TEP and UNS Electric’s ability to provide electric service to new customers may be negatively impacted.

TEP may be required to build an estimated $120 million transmission line from Tucson to Nogales or UNS Electric or TEP 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 an approximately 60-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. 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. After a hearing on the issue in February 2006, the ACC directed the ALJ to amend the recommendation to direct the Arizona Power Plant and Transmission Line Siting Committee to gather facts related to options for improving service reliability in Santa Cruz County. If all regulatory approvals are received and the project moves forward, the future costs to construct the transmission line from Tucson to Nogales are expected to be $120 million. If TEP is required to build the transmission line, it may negatively impact TEP’s ability to internally fund substantially all of its capital requirements.

If TEP does not receive required approvals or if the project is abandoned, TEP may be required to expense a portion of the $11 million it has incurred through December 31, 2009, 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 are unable to recover such expenditures, their results of operations and net income could be adversely affected.

ITEM 1B. — UNRESOLVED STAFF COMMENTS

None.

K-26

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, Springerville and Luna to the Tucson area for use by TEP’s retail customers (seeItem 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, 2009, TEP owned or participated in an overhead electric transmission and distribution system consisting of:

• 512 circuit-miles of 500-kV lines;

• 1,087 circuit-miles of 345-kV lines;

• 369 circuit-miles of 138-kV lines;

• 477 circuit-miles of 46-kV lines; and

• 2,622 circuit-miles of lower voltage primary lines.

The underground electric distribution system is comprised of 4,341 cable-miles. TEP owns approximately 76% of the poles on which the lower voltage lines are located. Electric substation capacity consisted of 102 substations with a total installed transformer capacity of 13,170,650 kilovolt amperes.

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.

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, in conjunction with PNM and Phelps Dodge, holds an undivided ownership interest in the property on which Luna is located.

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

• possible conflicting grants or encumbrances due to the absence of or inadequacies in the recording laws or record systems of the Bureau of Indian Affairs and the 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.

K-27

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.

SeeNote 6 of Notes to Consolidated Financial Statements, Debt, Credit Facilities, 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.

UES PROPERTIES

UNS Gas

As of December 31, 2009, UNS Gas’ transmission and distribution system consisted of approximately 58 miles of steel transmission mains, 4,173 miles of steel and plastic distribution mains, and 135,920 customer service lines.

UNS Electric

As of December 31, 2009, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 264 circuit-miles of 69-kV transmission lines, and 3,581 circuit-miles of underground and overhead distribution lines. UNS Electric also owns 39 substations having a total installed capacity of 1,768,050 kilovolt amperes and the 65 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.

UED PROPERTIES

As of December 31, 2009, UED owned a 90 MW gas-fired generation facility in Kingman, Arizona, known as BMGS, that was completed in May 2008. BMGS is located on property that is owned by UNS Electric and currently leased to UED. BMGS is subject to a lien to secure UED’s obligations under its term loan facility.

ITEM 3. — LEGAL PROCEEDINGS

Right of Way Matters

TEP is a defendant in a putative class action filed on February 11, 2009, in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs allege, among other things, that the rights of ways for defendants’ transmission lines on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs are requesting, among other things, that the transmission lines on these lands be removed. In June 2009, TEP and the other defendants filed motions to dismiss the lawsuit on procedural grounds and in September 2009, the plaintiffs filed responses. TEP cannot predict the outcome of this lawsuit.

K-28

Sierra Club San Juan Allegations

In December 2009, the Sierra Club sent TEP, the other owners of the San Juan Generating Station (SJGS), and San Juan Coal Company (SJCC), a Notice of Intent to Sue (RCRA Notice) under the Resource Conservation and Recovery Act (RCRA). The RCRA Notice alleges that certain activities at SJGS and the San Juan mine associated with the treatment, storage and disposal of coal and coal combustion by-products (CCBs) are causing imminent and substantial harm to the environment and that placement of CCBs at the mine constitute “open dumping” in violation of RCRA. Additionally, TEP has been informed that the Sierra Club sent SJCC a separate Notice of Intent to Sue (SMCRA Notice) under the Surface Mine Control and Reclamation Act (SMCRA) in December 2009. The SMCRA Notice similarly alleges damage to the environment due to activities at the San Juan mine, including the placement of CCBs from SJGS in the surface pits at the mine. Both Notices state Sierra Club’s intent to file citizens’ suits to pursue these claims upon expiration of the RCRA and SMRCA statutory notice periods. If suits are filed, potential remedies include the imposition of civil penalties and injunctive relief. TEP and Public Service Company of New Mexico, the SJGS operator, plan an aggressive defense of the RCRA claims. TEP cannot predict the outcome of these matters at this time.

SeeItem 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.

In addition, see legal proceedings described in Note 4 ofNotes to Consolidated Financial Statements, Commitments and Contingencies.

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

Not applicable.

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 and is listed on the New York Stock Exchange. On February 23, 2010, the closing price was $31.37, with 9,375 shareholders of record.

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 Board’s evaluation of our financial condition, earnings, cash flows and dividend policy.

UniSource Energy is the sole shareholder of TEP’s common stock and relies on dividends from its subsidiaries, primarily TEP, to declare and pay dividends. The TEP Board of Directors typically declares a dividend at the end of each year.

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Dividends on Common Stock.

K-29

Common Stock Dividends and Price Ranges

	2009						2008
	Market Price per						Market Price per
	Share of Common						Share of Common
	Stock(1)				Dividends		Stock(1)				Dividends
Quarter:	High		Low		Declared		High		Low		Declared
First	$	29.97	$	22.76	$	0.29	$	32.18	$	21.35	$	0.24
Second		28.76		24.78		0.29		34.49		22.33		0.24
Third		31.11		25.96		0.29		33.42		28.10		0.24
Fourth		33.11		28.04		0.29		29.67		20.91		0.24
Total					$	1.16					$	0.96

⁽¹⁾ UniSource Energy’s Common Stock price as reported by the New York Stock Exchange.

On February 12, 2010, UniSource Energy declared a cash dividend of $0.39 per share on its Common Stock. The dividend will be paid March 8, 2010 to shareholders of record at the close of business February 23, 2010.

TEP’s common stock is wholly-owned by UniSource Energy and is not listed for trading on any stock exchange. TEP declared and paid cash dividends to UniSource Energy of $60 million in 2009, $3 million in 2008, and $53 million in 2007.

Convertible Senior Notes

In 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035. Each $1,000 of Convertible Senior Notes is convertible into 27.427 shares of our Common Stock at any time, representing a conversion price of approximately $36.46 per share of our Common Stock, subject to adjustment in certain circumstances. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Executive Overview, UniSource Energy Consolidated Cash Flows, Financing Activities.

Issuer Purchases of Common Equity

UniSource Energy did not purchase any of its Common Stock during 2009, 2008 or 2007.

K-30

ITEM 6. — SELECTED CONSOLIDATED FINANCIAL DATA

UniSource Energy

	2009			2008			2007			2006			2005
	- In Thousands -
	(except per share data)
Summary of Operations
Operating Revenues	$	1,394,424		$	1,397,511		$	1,381,373		$	1,308,141		$	1,224,056
Income Before Discontinued Operations and Accounting Change	$	104,258		$	14,021		$	58,373		$	69,243		$	52,253
Net Income(1)	$	104,258		$	14,021		$	58,373		$	67,447		$	46,144
Basic Earnings per Share:
Before Discontinued Operations & Accounting Change	$	2.91		$	0.39		$	1.64		$	1.96		$	1.51
Net Income	$	2.91		$	0.39		$	1.64		$	1.91		$	1.33
Diluted Earnings per Share:
Before Discontinued Operations & Accounting Change	$	2.69		$	0.39		$	1.57		$	1.85		$	1.44
Net Income	$	2.69		$	0.39		$	1.57		$	1.80		$	1.28
Shares of Common Stock Outstanding
Average		35,858			35,632			35,486			35,264			34,798
End of Year		35,851			35,458			35,315			35,190			34,874
Year-end Book Value per Share	$	20.94		$	19.16		$	19.54		$	18.59		$	17.69
Cash Dividends Declared per Share	$	1.16		$	0.96		$	0.90		$	0.84		$	0.76
Financial Position
Total Utility Plant — Net	$	2,785,714		$	2,617,693		$	2,407,295		$	2,259,620		$	2,171,461
Investments in Lease Debt and Equity		132,168			126,672			152,544			181,222			156,301
Other Investments and Other Property		60,239			64,096			70,677			66,194			58,468
Total Assets	$	3,601,242		$	3,509,567		$	3,185,716		$	3,187,409		$	3,180,211
Long-Term Debt	$	1,307,795		$	1,313,615		$	993,870		$	1,171,170		$	1,212,420
Non-Current Capital Lease Obligations		488,349			513,517			530,973			588,771			665,737
Common Stock Equity		750,865			679,274			690,075			654,149			616,741
Total Capitalization	$	2,547,009		$	2,506,406		$	2,214,918		$	2,414,090		$	2,494,898
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	347,310		$	277,011		$	322,766		$	282,659		$	273,883
Capital Expenditures	$	(287,104	)	$	(357,324	)	$	(245,366	)	$	(238,261	)	$	(203,362	)
Other Investing Cash Flows(2)		(9,540	)		(95,493	)		27,961			(7,820	)		32,794
Net Cash Flows From Investing Activities	$	(296,644	)	$	(452,817	)	$	(217,405	)	$	(246,081	)	$	(170,568	)
Net Cash Flows From Financing Activities	$	(28,916	)	$	140,605		$	(119,229	)	$	(77,016	)	$	(112,664	)
Ratio of Earnings to Fixed Charges(3)		2.47			1.24			1.68			1.73			1.55

K-31

(1)	Net Income includes an after-tax loss for discontinued operations of $2 million in 2006, and $5 million in 2005. Net income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of asset retirement accounting in 2005.
((2)	Other Investing Cash Flowsin 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bond.
(3)	For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, 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.

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

TEP

	2009			2008			2007			2006			2005
	-Thousands of Dollars-
Summary of Operations
Operating Revenues	$	1,096,711		$	1,079,253		$	1,070,503		$	988,994		$	937,470
Income Before Accounting Change		89,248			4,363			53,456			66,745			48,893
Net Income(1)	$	89,248		$	4,363		$	53,456		$	66,745		$	48,267
Financial Position
Total Utility Plant — Net	$	2,261,325		$	2,120,619		$	1,957,506		$	1,887,387		$	1,866,622
Investments in Lease Debt and Equity		132,168			126,672			152,544			181,222			156,301
Other Investments and Other Property		31,813			31,291			35,460			30,161			27,013
Total Assets	$	2,914,299		$	2,841,771		$	2,573,036		$	2,623,063		$	2,617,219
Long-Term Debt	$	903,615		$	903,615		$	682,870		$	821,170		$	821,170
Non-Current Capital Lease Obligations		488,311			513,370			530,714			588,424			665,299
Common Stock Equity		643,144			583,606			577,349			554,714			558,646
Total Capitalization	$	2,035,070		$	2,000,591		$	1,790,933		$	1,964,308		$	2,045,115
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	268,064		$	268,706		$	264,112		$	227,228		$	243,013
Capital Expenditures	$	(235,485	)	$	(294,940	)	$	(162,539	)	$	(156,180	)	$	(149,906	)
Other Investing Cash Flows(2)		(14,116	)		(95,814	)		25,414			(25,786	)		21,001
Net Cash Flows From Investing Activities	$	(249,601	)	$	(390,754	)	$	(137,125	)	$	(181,966	)	$	(128,905	)
Net Cash Flows From Financing Activities	$	(29,320	)	$	128,713		$	(120,088	)	$	(78,984	)	$	(173,882	)
Ratio of Earnings to Fixed Charges(3)		2.58			1.13			1.75			1.84			1.60

(1)	Net Income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of asset retirement accounting in 2005.
(2)	Other Investing Cash Flowsin 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds.
(3)	For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, 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.

SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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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 three primary business segments and includes the following:

• outlook and strategies,

• operating results during 2009 compared with 2008, and 2008 compared with 2007,

• factors which affect our results and outlook,

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

• dividends, and

• critical accounting policies.

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

TEP, an electric utility, provides electric service to the community of Tucson, Arizona. 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. UED developed and owns the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that provides energy to UNS Electric through a five-year power sale agreement. Millennium has existing investments in unregulated businesses; however no new investments are planned at Millennium. We conduct our business in three primary business segments — TEP, UNS Gas and UNS Electric.

At December 31, 2009, the investment in Millennium represented 1% of UniSource Energy’s total assets.

UNISOURCE ENERGY CONSOLIDATED

OUTLOOK AND STRATEGIES

Our financial prospects and outlook for the next few years will be affected by many factors including: TEP’s 2008 Rate Order that freezes base rates through 2012, the recent national and regional economic downturn, the financial market disruptions and volatility, potential regulations impacting greenhouse gas emissions and other regulatory factors. Our plans and strategies include the following:

• Develop strategic responses to potential new legislation on carbon emissions, including the evaluation of TEP’s existing mix of generation resources, and define steps to achieve environmental objectives that provide an appropriate return on investment and are consistent with earnings growth;

• Obtain ACC approval of rate increases for UNS Gas and UNS Electric to provide adequate revenues to cover the rising cost of providing reliable and safe service to their customers;

• Expand TEP and UNS Electric’s transmission system to meet increasing loads and provide access to renewable energy resources;

• Expand TEP and UNS Electric’s portfolio of renewable energy sources and programs to meet Arizona’s renewable energy standards;

• Create future ownership opportunities for renewable energy projects; and

• Ensure UniSource Energy continues to have adequate liquidity by maintaining sufficient lines of credit and regularly reviewing and adjusting UniSource Energy’s short-term investment strategies in response to market conditions.

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Economic Conditions

Sales and Revenues

As a result of general economic conditions, retail customer growth and energy usage by residential and commercial customers at UniSource Energy’s utility subsidiaries is below the average levels experienced in prior periods. From 2003 to 2007, the growth in number of customers in UniSource Energy’s utility service territories averaged 2% per year for TEP, and 3% per year for UNS Gas and UNS Electric. During 2008 and 2009, UniSource Energy’s results were impacted by slower retail customer growth and lower energy consumption.

TEP and UES experienced retail customer growth of less than 1% during 2009. TEP’s total retail kWh sales decreased by 1.4% in 2008 compared with 2007. This was the first year-over-year decrease in TEP’s retail kWh sales since 2002. In 2009, TEP’s kWh sales declined by 1.4% over the prior year’s levels. This compares with average annual increases in retail kWh sales of 4% from 2003 to 2007. We did not experience a significant increase in uncollectible accounts at TEP, UNS Gas or UNS Electric in 2008 or 2009.

UniSource Energy’s future results of operations may continue to be impacted by weak economic conditions. We cannot predict if the customer growth rate or sales volumes will return to historic levels. We expect TEP’s customer base to grow at a rate of less than 1% in 2010 and approximately 1% in 2011. UES’ customer base is expected to grow at a rate of less than 1% in 2010 and 2011.

Financial Markets

To date, UniSource Energy and its subsidiaries have not been materially impacted by volatility and disruptions in the financial markets. Our banking relationships remain stable. UniSource Energy and its subsidiaries have access to $280 million of revolving credit facilities, of which $202 million was unused as of February 23, 2010, which we believe is sufficient to meet current operating, capital and financing needs. UniSource Energy, TEP, UNS Gas and UNS Electric have not experienced, nor do they expect to experience, any difficulties obtaining funding under their respective revolving credit facilities. None of these credit facilities have any bankrupt financial institutions as lenders, and no lenders in the bank groups have refused to fund when requested.

UniSource Energy and its subsidiaries are also subject to interest rate risk on variable rate revolving credit facility borrowings and outstanding long-term variable rate debt. SeeLiquidity and Capital Resources, Interest Rate Risk; Tucson Electric Power, Liquidity and Capital Resources, Interest Rate Risk; UNS Gas, Liquidity and Capital Resources, Interest Rate Risk; and UNS Electric, Liquidity and Capital Resources, Interest Rate Riskbelow.

Neither UniSource Energy nor any of its subsidiaries have any scheduled long-term debt maturities until 2011 when $50 million of unsecured notes mature at UNS Gas. The UniSource Energy and TEP Credit Agreements and the UNS Gas/UNS Electric Revolver also expire in 2011. UniSource Energy is required to make principal payments on an amortizing term loan, totaling $6 million per year. SeeUniSource Energy Credit Agreement, below.

As of February 23, 2010, TEP, UNS Electric and UNS Gas did not have any material power or gas trading exposure to financially distressed counterparties. We cannot predict whether in the future our financial condition or results of operations will be impacted by current economic conditions or liquidity concerns in the financial markets. SeeLiquidity and Capital Resources,below.

Pension and Post-Retirement Benefits

TEP, UNS Gas and UNS Electric 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, UNS Gas and UNS Electric 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 Internal Revenue Service benefit or compensation limitations.

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The pension assets are invested in a diversified portfolio of domestic and international equity securities, fixed income securities, real estate and alternative investments. As of December 31, 2009, the total value of the pension assets was approximately $184 million, compared with $135 million as of December 31, 2008. Our accumulated benefit obligation at December 31, 2009 and at December 31, 2008 was $210 million and $198 million, respectively. Due to the increase in the plan total asset value during 2009, projected funding levels are expected to be $22 million in 2010, compared with the $23 million contribution that was funded in 2009.

Environmental Matters

UniSource Energy’s utility subsidiaries are subject to numerous federal, state and local environmental laws and regulations affecting present and future operations, including regulations regarding air emissions, water quality, wastewater discharges, solid waste and hazardous waste.

These laws and regulations can result in increased capital, operating and other costs, particularly with regard to enforcement efforts focused on existing power plants and compliance plans with regard to new and existing power plants. There are proposals and ongoing studies at the state, federal and international levels to address global climate change that could result in the regulation of CO₂ and other greenhouse gases. Such legislation or regulation could produce a number of results including additional costs to fund energy efficiency activities, costly modifications to, or reexamination of the economic viability of, our existing coal plants or changes in the overall fuel mix of our generating fleet. The impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time. For further discussion of the possible impact of environmental matters on our business, seeItem 1. Business -Environmental Matters and Item 1A. Risk Factors.

RESULTS OF OPERATIONS

Executive Overview

UniSource Energy recorded Net Income of $104 million in 2009, $14 million in 2008 and $58 million in 2007.

2009 Compared with 2008

The increase in UniSource Energy’s net income in 2009 is due primarily to three factors: 1) a $40 million increase in TEP’s retail revenues (excluding revenues collected from customers for renewable energy and energy efficiency programs) resulting from a 6% base rate increase and hot summer weather during the third quarter of 2009; 2) a $30 million decrease in total fuel and purchased energy expense (net of short-term wholesale revenues); and 3) $50 million of regulatory expenses, revenue deferrals and accounting adjustments in 2008 that did not recur in 2009. Other factors include a $6 million pre-tax gain recorded in 2009 resulting from Millennium’s sale of an investment.See Tucson Electric Power Company, Results of Operations, below.

2008 Compared with 2007

UniSource Energy recorded net income of $14 million in 2008 compared with net income of $58 million in 2007. The decrease in UniSource Energy’s net income in 2008 was due primarily to higher costs at TEP and the impacts resulting from the 2008 TEP Rate Order. TEP incurred higher coal-related fuel expense; higher purchased power costs due partially to plant outages in the first and third quarters of 2008; and higher operations and maintenance (O&M) expense primarily due to generating plant maintenance.

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Results in 2008 were also impacted by: a $54 million decrease in TRA amortization; the 2008 TEP Rate Order that included a credit to retail customers that decreased revenue by $58 million; and adjustments that reduced pre-tax expenses by $32 million related to the reapplication of regulatory accounting to TEP’s generating assets, resulting from the 2008 TEP Rate Order.See Tucson Electric Power Company, Results of Operations, below.

O&M

The table below summarizes the items included in UniSource Energy’s O&M expense.

	2009			2008			2007
	-Millions of Dollars-
TEP Base O&M	$	231		$	219		$	192
UNS Gas Base O&M		25			25			27
UNS Electric Base O&M		21			21			23
Base Utility O&M		277			265			242
Consolidating Adjustments and Other(1)		(7	)		(7	)		(11	)
UniSource Energy Base O&M		270			258			231
Reimbursed Expenses Related to Springerville Units 3 and 4		41			35			24
Gain on the Sale of SO2 Emissions Allowances		—			(1	)		(15	)
Expenses related to customer-funded renewable energy programs(2)		23			5			2
Reinstatement of Regulatory Accounting		—			(1	)		—
Total UniSource Energy O&M	$	334		$	296		$	242

(1)	Includes Millennium, UED and parent company O&M, and inter-company eliminations
(2)	Represents expenses related to customer-funded renewable energy programs; the offsetting funds collected from customers are recorded in other revenue.

CONTRIBUTION BY BUSINESS SEGMENT

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

	2009		2008			2007
	-Millions of Dollars-
TEP	$	89	$	4		$	53
UNS Gas		7		9			4
UNS Electric		6		4			5
Other(1)		2		(3	)		(4	)
Consolidated Net Income	$	104	$	14		$	58

⁽¹⁾ Includes: UniSource Energy parent company expenses; UniSource Energy parent company interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement; and income and losses from Millennium investments and UED.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

The primary source of liquidity for UniSource Energy, the parent company, is dividends from its subsidiaries, primarily TEP. Also, under UniSource Energy’s tax sharing agreement, subsidiaries make income tax payments to UniSource Energy, which makes payments on behalf of the consolidated group. The table below provides a summary of the liquidity position of UniSource Energy on a stand-alone basis and each of its segments.

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				Borrowings		Amount Available
Balances As of	Cash and Cash			under Revolving		under Revolving
February 23, 2010	Equivalents			Credit Facility(3)		Credit Facility
	-Millions of Dollars-
UniSource Energy stand-alone	$	2		$	15	$	55
TEP		26			51		99
UNS Gas		41			—		45	(1)
UNS Electric		6			12		33	(1)
Other		8	(2)		N/A		N/A
Total	$	83

(1)	Currently, either UNS Gas or UNS Electric may borrow up to a maximum of $45 million, but the total combined amount borrowed cannot exceed $60 million.
(2)	Includes cash and cash equivalents at Millennium and UED.
(3)	Includes LOCs issued under Revolving Credit Facilities

Short-term Investments

UniSource Energy has a short-term investment policy which governs the investment of excess cash balances by UniSource Energy and its subsidiaries. We review this policy periodically in response to market conditions to adjust, if necessary, the maturities and concentrations by investment type and issuer in the investment portfolio. As of December 31, 2009, UniSource Energy’s short-term investments include highly-rated and liquid money market funds, certificates of deposit and commercial paper. These short-term investments are classified as Cash and Cash Equivalents on the Balance Sheet.

Access to Revolving Credit Facilities

UniSource Energy, TEP, UNS Gas and UNS Electric are each party to a revolving credit agreement with a group of lenders, which is available to be used for working capital purposes. Each of these agreements is a committed facility and expires in August 2011. The TEP and UNS Gas/UNS Electric Credit Agreements may be used for revolving borrowings, as well as to issue letters of credit. TEP, UNS Gas and UNS Electric each issue letters of credit from time to time to provide credit enhancement to counterparties for their power or gas procurement and hedging activities. The UniSource Energy Credit Agreement may be used only for revolver borrowings.

UniSource Energy and its subsidiaries believe that they have sufficient liquidity under their revolving credit facilities to meet their short-term working capital needs and to provide credit enhancement as may be required under their respective energy procurement and hedging agreements. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Liquidity Outlook

Neither UniSource Energy nor any of its subsidiaries have any long-term debt maturities until 2011 when $50 million of unsecured notes mature at UNS Gas. The UniSource Energy and TEP Credit Agreements and the UNS Gas/UNS Electric Revolver also expire in 2011. UniSource Energy is required to make principal payments on an amortizing term loan, totaling $6 million per year. SeeUniSource Energy Credit Agreement, below.

Executive Overview — UniSource Energy Consolidated Cash Flows

	2009			2008			2007
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$	347		$	277		$	323
Investing Activities		(297	)		(453	)		(217	)
Financing Activities		(29	)		141			(119	)

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 power. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, UniSource Energy, TEP, UNS Gas and UNS Electric use, as needed, their revolving credit facilities to fund their business activities.

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Cash used for investing activities is primarily a result of capital expenditures at TEP, UNS Gas and UNS Electric. Cash used for investing and financing activities can fluctuate year-to-year depending on: capital expenditures, repayments and borrowings under revolving credit facilities; debt issuances or retirements; capital lease payments by TEP; and dividends paid by UniSource Energy to its shareholders.

Operating Activities

In 2009, net cash flows from operating activities were $70 million higher than 2008 primarily due to: lower costs of fuel and purchased energy; increased retail revenues due to base rate increases at TEP and UNS Electric and hot summer weather; lower interest paid on capital leases and long-term debt; partially offset by lower wholesale sales, higher O&M and higher wages paid.

Investing Activities

Net cash used for investing activities was $156 million lower in 2009 compared with 2008 due to: a $133 million deposit made by TEP last year with the trustee for bonds that matured on August 1, 2008; and a $70 million decrease in capital expenditures in 2009; partially offset by a $31 million investment made by TEP in 2009 to purchase Springerville lease debt; and a $12 million decrease in proceeds from investment in lease debt.

Capital Expenditures

	Actual		Estimated
Business Segment	2009			2010		2011		2012		2013		2014
						-Millions of Dollars-
TEP	$	235		$	258	$	217	$	203	$	225	$	209
UNS Gas		14			14		16		16		16		18
UNS Electric		28			26		25		31		13		16
UniSource Energy Stand-Alone		10			16		27		1		—		1
UniSource Energy Consolidated	$	287		$	314	$	285	$	251	$	254	$	244

• Included in TEP’s capital expenditures forecast for 2010 is $52 million for the proposed purchase of Sundt Unit 4.

• Items excluded from TEP’s capital expenditures forecast are: the estimated cost to construct proposed Tucson to Nogales, Arizona transmission line of $120 million; estimated costs of $300 million between 2011-2014 to construct 75 to 150 MW of local generation that may be required in 2015.

• The estimated capital expenditures for UniSource Energy Stand-Alone are for the purchase of land and construction of a new corporate headquarters.

For more information seeTEP, Liquidity and Capital Resources, Investing Activities, Capital Expenditures,below, andItem 1. Business, TEP, Transmission Access, Tucson to Nogales Transmission Line,above.

Financing Activities

Net cash proceeds from financing activities were $170 million lower in 2009 compared with 2008. In 2008, The Industrial Development Authority of Pima County issued, for the benefit of TEP, approximately $221 million of tax-exempt industrial development revenue bonds and UNS Electric issued $100 million of long-term debt used in part to refinance a $60 million debt maturity. Factors affecting proceeds from financing activities in 2009 included: $30 million of proceeds from the issuance of short-term debt at UED; a $70 million decrease in payments of long-term debt compared with 2008; a $50 million decline in payments on capital lease obligations compared with 2008; and a $7 million increase in dividends paid compared with 2008.

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Capital Contributions

In March 2009, UED used loan proceeds to distribute $30 million to UniSource Energy. UniSource Energy used the proceeds to contribute $30 million of capital to TEP. TEP used the proceeds to purchase lease debt related to Springerville Unit 1. In February 2010, UED distributed $9 million to UniSource Energy. SeeOther Non-Reportable Business Segments, UEDandTucson Electric Power Company, Liquidity and Capital Resources, below for more information.

In 2008, UniSource Energy contributed $59 million in capital to UED by canceling an intercompany promissory note in the amount of $59 million. Borrowings under the promissory note were used to finance the development of BMGS.

UniSource Energy Credit Agreement

The UniSource Credit Agreement consists of a $30 million amortizing term loan facility and a $70 million revolving credit facility and matures in August 2011. Principal payments of $1.5 million on the outstanding term loan are due quarterly, with the balance due at maturity. At December 31, 2009, there was $9 million outstanding under the term loan facility and $31 million outstanding under the UniSource Energy revolving credit facility at a weighted average interest rate of 1.48%. We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at adjusted LIBOR plus 1.25% or the sum of the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate and 0.25%.

The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, dividends, 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 stand alone 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.

In September 2008 and February 2009, as a result of higher than expected fuel and purchased power costs, UniSource Energy amended its credit agreements to provide more flexibility to meet the required leverage ratio. Although fuel and purchase power expenses have decreased in recent months, current economic conditions could result in lower customer growth rates and lower sales and could impact our ability to comply with these covenants.

As of December 31, 2009, 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.

Interest Rate Risk

UniSource Energy is subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. Given the recent volatility in LIBOR and other benchmark interest rates, UniSource Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Convertible Senior Notes

UniSource Energy has $150 million of 4.50% Convertible Senior Notes due 2035. Each $1,000 of Convertible Senior Notes is convertible into 27.427 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $36.46 per share of our Common Stock, subject to adjustments. The closing price of UniSource Energy’s Common Stock was $31.37 on February 23, 2010.

Beginning on March 5, 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.

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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 at December 31, 2009 were:

• UES’ guarantee of senior unsecured notes issued by UNS Gas ($100 million) and UNS Electric ($100 million);

• UES’ guarantee of the $60 million UNS Gas/UNS Electric Revolver;

• UniSource Energy’s guarantee of approximately $2 million in building lease payments for UNS Gas; and

• UniSource Energy’s guarantee of the $26 million of outstanding loans under the UED Credit Agreement. In February 2010, UED increased its borrowings under this agreement to $35 million. As a result, UniSource Energy increased its guarantee to $35 million.

To the extent liabilities exist under these contracts, such liabilities are included in the consolidated balance sheets.

In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4. We have indemnified the seller of Sundt Unit 4 from any sales, use, transfer or similar taxes or fees due relating to the purchase. The terms of the indemnification do not include a limit on potential future payments; however, we believe that the parties to the agreement have abided by all tax laws, and we do not have any additional tax obligations. We have not made any payments under the terms of this indemnification to date.

Contractual Obligations

The following chart displays UniSource Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2009.

UniSource Energy’s Contractual Obligations - Millions of Dollars -
											2015
Payment Due in Years											and
Ending December 31,	2010		2011		2012		2013		2014		after		Other		Total
Long Term Debt
Principal(1)	$	32	$	578	$	—	$	—	$	—	$	745	$	—	$	1,355
Interest(2)		59		58		51		51		51		659		—		929
Capital Lease Obligations(3)		93		107		118		123		195		103		—		739
Operating Leases		2		1		1		—		—		1		—		5
Purchase Obligations:
Fuel(4)		108		65		47		42		40		165		—		467
Purchased Power		111		35		18		49		2		2		—		217
Transmission		4		4		3		2		2		2		—		17
Other Long-Term Liabilities(5):
Pension & Other Post Retirement Obligations(6)		28		5		5		6		6		30		—		80
Acquisition of Springerville Coal Handling and Common Facilities		—		—		—		—		—		226		—		226
Building Commitments		2		1		—		—		—		—		—		3
Unrecognized Tax Benefits		—		—		—		—		—		—		19		19
Total Contractual Cash Obligations	$	439	$	854	$	243	$	273	$	296	$	1,933	$	19	$	4,057

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(1)	TEP’s variable rate IDBs are secured by letters of credit issued pursuant to TEP’s Credit Agreement and 2008 Letter of Credit Facility which expire in 2011. Although the variable rate IDBs mature between 2018 and 2029, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the letters of credit terminate without replacement upon expiration of the TEP Credit Agreement and 2008 Letter of Credit Facility. In January 2010, TEP’s 2008 Letter of Credit Facility was terminated on conversion of the 2008 Pima B Bonds to a fixed rate. Effective with the termination of the 2008 Letter of Credit Facility, $130 million of variable rate IDBs mature in 2029. In February 2010, UED amended its $26 million term loan facility (included in 2010 maturity above) to extend the termination date by two years to March 2012 and had net additional borrowings of $9 million bringing the outstanding balance to $35 million.
(2)	Excludes interest on revolving credit facilities.
(3)	Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP are reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including 14% each of the Springerville Common Lease payments and 17% each of the Springerville Coal Handling Facilities Lease payments. TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement. In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4 from the owner participant for approximately $52 million. The purchase price is subject to increase by 0.75% of the purchase price per month in the event that the purchase occurs after March 31, 2010.
(4)	Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the San Juan and Four Corners generating stations as the timing of payment has not been determined. See Note 4.
(5)	Excludes asset retirement obligations expected to occur through 2066.
(6)	These obligations represent TEP and UES’ expected contributions to pension plans in 2010 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 2010 due to the significant impact that returns on plan assets and changes in discount rates might have on such amounts. TEP previously funded the postretirement benefit plan on a pay-as-you-go basis. In 2009, TEP established a VEBA Trust to partially fund expected future benefits for union employees. Benefit payments are not expected to be made from the Trust for several years. The 2010 obligation includes expected VEBA contributions. VEBA contributions for periods beyond 2010 cannot be determined at this time.

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 arrangements contains acceleration clauses or other consequences triggered by changes in our stock price.

Dividends on Common Stock

On February 12, 2010, UniSource Energy declared a first quarter cash dividend of $0.39 per share on its Common Stock. The first quarter dividend, totaling approximately $14 million, will be paid March 8, 2010 to shareholders of record at the close of business February 23, 2010. During 2009, UniSource Energy paid quarterly dividends to its shareholders of 0.29 per share; for all of 2009, total dividends paid were $41 million. In 2008, UniSource Energy paid quarterly dividends to its shareholders of $0.24 per share; for all of 2008, total dividends paid were $34 million.

Income Tax Position

At December 31, 2009, UniSource Energy and TEP had federal AMT credit carryforwards of $43 million and $28 million, respectively, which do not expire. During 2009, UniSource Energy and TEP used all of their capital loss and state net operating loss carryforwards.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

Executive Summary

TEP recorded net income of $89 million in 2009 compared with $4 million in 2008. The improvement in net income during 2009 is due primarily to: TEP’s new retail rate structure; hot summer weather; lower fuel and purchased power costs; no provision for rate refunds recorded in 2009; and the elimination of TRA amortization expense that was incurred in 2008. In addition, 2008 results include a reduction in pre-tax expenses related to the reinstatement of regulatory accounting to TEP’s generating assets resulting from the 2008 TEP Rate Order.

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Beginning on January 1, 2009, TEP implemented a PPFAC. The PPFAC allows recovery of actual fuel and purchased power costs from TEP’s retail customers. The fuel and purchased power costs are off-set by the following, which are credited to the PPFAC: 100% of short-term wholesale revenues, 10% of the profit on trading activity and 50% of the revenues from the sale of SO₂ emission allowances. As a result of the PPFAC, relative to prior periods, TEP’s net income is not as sensitive to changes in fuel and purchased power costs or revenues from short-term wholesale sales.

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.

2009 Compared with 2008

The following factors contributed to the change in TEP’s net income:

• a $62 million increase in retail revenues due primarily to: the 6% base rate increase that took effect in December 2008; a new rate structure that charges higher rates for higher levels of energy usage; a $23 million increase in revenues collected from customers for renewable energy and energy efficiency programs; and hot summer weather during the third quarter of 2009;

• a provision for rate refunds of $58 million recorded in 2008;

• a $9 million decrease in long-term wholesale revenues due primarily to lower kWh sales to Salt River Project (SRP) and Navajo Tribal Utility Authority (NTUA);

• a $30 million decrease in total fuel and purchased energy expense, net of short-term wholesale revenues, due to lower generating output; a decline in the market price of wholesale power and natural gas; and a $24 million gain recorded to fuel expense in 2008 related to the reinstatement of regulatory accounting;

• a $33 million increase in O&M. Excluding a $15 million increase in expenses directly offset by customer surcharges for renewable energy and energy efficiency programs and a $6 million increase third party reimbursements, the increase in O&M was $12 million, which resulted primarily from higher pension-related expenses and plant maintenance expenses.

• a $27 million increase in depreciation and amortization expense due to: additions to plant in service; new depreciation rates for generation assets; and amortization of regulatory assets resulting from the 2008 TEP Rate Order;

• a $24 million decrease in the amortization of TEP’s TRA. In May 2008, the TRA was fully amortized;

• a $6 million increase in taxes other than income taxes due primarily to a $7 million gain recorded in 2008 resulting from the reinstatement of regulatory accounting;

• a $10 million increase in total other income due to interest income related to an income tax refund, income related to an adjustment in the accounting for an investment in lease equity and income related to an increase in the value of a company owned life insurance policy; and

• an $11 million decrease in total interest expense resulting primarily from lower interest rates on variable rate debt and lower interest expense related to capital lease obligations;

In 2009 and 2008, the pre-tax benefit recognized by TEP related to Springerville Units 3 and 4 for operating fees and contributions toward common facility costs was $12 million in each period.

In June 2009, TEP adjusted its accounting for a 2006 investment in 14.14% of Springerville Unit 1 lease equity. As a result, TEP recorded a net increase to the income statement of $0.6 million, before tax. The adjustment recorded in June 2009 for the period from July 2006 through June 2009 included additional depreciation expense of $4 million; a reduction of interest expense on capital leases of $2 million; and $3 million of equity in earnings which is included in Other Income on the income statement.

K-42

2008 Compared with 2007

The following factors contributed to the decrease in TEP’s net income:

• A $9 million increase in total operating revenues due to:

• a $64 million increase in wholesale revenues due to increased short-term wholesale activity and related purchased power volumes, lower retail demand resulting in an increase in the availability of energy to sell into the wholesale market and an increase in the market price of wholesale power. Wholesale sales volumes increased 13% and the average price per MWh of wholesale power sold increased by 16%; and

• a $12 million increase in other revenues due primarily to fees and reimbursements received for fuel and O&M costs related to Springerville Units 3 and 4; partially offset by:

• a $58 million provision for revenues to be credited equivalent to the Fixed CTC revenue that was collected from customers after the TRA was fully amortized in early May 2008; and

• a $9 million decrease in retail revenues due to mild summer weather and a weakening local economy.

• A $92 million increase in fuel and purchased power due to:

• a $98 million increase in purchased power expense. Purchased power volumes increased by 44% as a result of higher wholesale sales activity and replacement power purchases during the first and third quarters. The average price paid per MWh increased by 18% due to higher market prices for wholesale energy; and

• a $6 million decrease in fuel expense. Higher mining costs at San Juan, increased coal costs at Sundt Unit 4 and a 17% increase in the average cost per kWh of gas-fired generation due to higher natural gas prices, were offset by a $25 million gain recorded to fuel expense related to the reinstatement of regulatory accounting.

Other factors impacting the comparability of results for 2008 include:

• a $55 million increase in O&M expense due to: an $11 million increase in O&M related to Springerville Units 3 and 4, which is reimbursed to TEP by the owners of those units and recorded in other revenues; an increase in generation plant maintenance of $18 million; a $13 million decrease in pre-tax gains from the sale of excess SO₂ Emission Allowances which is recorded as an offset to O&M; increased transmission expense; and general cost pressures resulting from inflation and other economic factors;

• a $6 million increase in depreciation and amortization expense due to additions to plant in service;

• a $54 million decrease in the amortization of TEP’s TRA. In May 2008, the TRA was fully amortized;

• a $9 million decrease in taxes other than income taxes due primarily to a $7 million gain resulting from the reinstatement of regulatory accounting;

• a $7 million decrease in other income due in part to lower interest income on investment in lease debt. The interest income declines over time as the lease debt is amortized; and

• a $15 million decrease in total interest expense resulting primarily from lower balances on capital lease obligations.

In 2008 and 2007, the pre-tax benefit recognized by TEP related to Springerville Units 3 and 4 for operating fees and contributions toward common facility costs was $12 million in each period.

K-43

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, the availability of TEP generating resources, and the level of wholesale forward contract activity.

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.

							09-08
Energy Sales, kWh (in millions)	2009			2008			% Change*			2007
Electric Retail Sales:
Residential		3,906			3,852			1.4	%		4,005
Commercial		1,988			2,034			(2.3	%)		2,058
Industrial		2,161			2,264			(4.5	%)		2,341
Mining		1,065			1,096			(2.8	%)		983
Public Authorities		251			256			(1.9	%)		247
Total Electric Retail Sales		9,371			9,502			(1.4	%)		9,634
Electric Wholesale Sales Delivered:
Long-term Contracts		833			1,096			(24.0	%)		1,101
Short-term and Trading		2,222			2,873			(22.8	%)		2,458
Total Electric Wholesale Sales		3,055			3,969			(23.0	%)		3,559
Total Electric Sales		12,426			13,471			(7.8	%)		13,193
Electric Retail Revenues (in millions):
Residential	$	378		$	351			7.6	%	$	363
Commercial		220			212			3.8	%		214
Industrial		164			165			(0.7	%)		168
Mining		61			55			9.7	%		49
Public Authorities		20			19			3.8	%		18
Revenues excluding REST & DSM	$	843			802			5.0	%		812
REST and DSM Revenues		25			3		NM				5
Provision for Rate Refunds		—			(58	)	NM				—
Total Retail Revenues	$	868		$	747			16.2	%	$	817
Electric Wholesale Revenues:
Long-term Contracts		48			58			(17.2	%)		56
Provision for Wholesale Refunds		(4	)		—		NM				—
Other Sales		81			185			(55.1	%)		125
Transmission		19			17			10.5	%		15
Total Wholesale Revenues		146			260			(43.9	%)		196
Total Retail and Wholesale Revenues	$	1,012		$	1,007			0.6	%	$	1,013

					09-08
Weather Data:	2009		2008		% Change			2007
Cooling Degree Days
Actual		1,599		1,336		19.7	%		1,517
10-Year Average		1,419		1,431	NM				1,424
Heating Degree Days
Actual		1,287		1,367		(5.9	%)		1,506
10-Year Average		1,481		1,444	NM				1,497

* Percent change calculated on un-rounded data; may not correspond to data shown in table

K-44

2009 Compared with 2008

Residential and Commercial

Residential kWh sales increased by 1.4% in 2009 due primarily to hotter than normal weather during the third quarter. Residential revenues increased $27 million or 7.6% during 2009, benefitting from hot summer weather, as well as a base rate increase that became effective in December 2008.

Commercial kWh sales during 2009 were 2.3% below 2008. The decrease in commercial kWh sales was driven primarily by weak economic conditions. Revenues from commercial kWh sales increased by $8 million, or 3.8%, as a result of the base rate increase that became effective in December 2008.

Industrial, Mining and Public Authorities

Sales volumes to industrial, mining and public authority customers decreased by a combined 3.8% in 2009 due primarily to the weak economy. Associated revenues were $5 million higher than the same period last year as a result of the base rate increase that became effective in December 2008.

Retail Margin Revenues

The table below provides a summary of the margin revenues (retail revenues excluding base fuel, PPFAC and REST and DSM charges) on TEP’s retail sales for 2009. Comparable data is not available for 2008 since TEP’s new rate structure went into effect in December 2008.

2009 Year-End

	-millions-		-cents / kWh-
Retail Margin Revenues (non-GAAP)*
Residential	$	253		6.48
Commercial		160		8.04
Industrial		99		4.59
Mining		31		2.93
Public Authorities		13		5.00
Retail Margin Revenues (Non-GAAP)*	$	556		5.94
Base Fuel & PPFAC Revenues		287		3.05
REST & DSM Revenues		25		0.27
Net Electric Retail Sales (GAAP)	$	868		9.26

* Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net Electric Retail Sales, which is determined in accordance with GAAP. TEP believes that Retail Margin Revenues, which is Net Electric Retail Sales less base fuel and PPFAC revenues, and revenues for DSM and REST programs, provides useful information to investors as a measure of TEP’s ability to pay for operating expenses with retail revenues, after giving effect to related fuel and purchased power expenses.

Long-Term Wholesale Revenues

Revenues from long-term wholesale contracts decreased by $10 million in 2009 compared with last year primarily due to lower sales volumes to NTUA. In 2009, NTUA received a greater allotment of federal hydro power as hydro conditions in the Colorado River basin have been above normal. In addition, low gas prices made it more economic for one of their major customers to self-generate than to purchase power from NTUA. These factors led NTUA to purchase 17% less energy under its agreement with TEP compared with 2008. The gross margin (long-term wholesale revenues less the cost of energy, which is based on TEP’s average fuel and purchased power costs) on TEP’s long-term wholesale sales for 2009 was $24 million. Prior to the implementation of the PPFAC in January 2009, TEP did not allocate fuel and purchased power costs to long-term wholesale sales.

K-45

2008 Compared with 2007

Residential and Commercial

Residential kWh sales were 4% lower in 2008, resulting in a $12 million or 3% decline in residential revenues. Mild weather accounted for $7 million of the decrease, while other factors such as slower customer growth, economic conditions and customer usage patterns accounted for the remaining decrease.

Commercial kWh sales were 1% lower in 2008, resulting in a $2 million or 1% decline in commercial revenues. Mild weather accounted for most of the decrease, while weak economic conditions and slower customer growth also contributed to the decline.

Industrial, Mining and Public Authorities

Industrial kWh sales were 3% lower in 2008, resulting in a $3 million or 2% decline in industrial revenues. The decrease is due primarily to regional and national economic conditions. kWh sales and revenues to mining customers increased 11% and 12%, respectively, in 2008 compared with 2007. The increase is due to higher mining production as well as an increase in the rate charged to one of TEP’s mining customers.

CTC Revenue to be Refunded

TEP deferred $58 million of retail revenues in 2008 that is being credited to customers according to the 2008 TEP Rate Order. SeeFactors Affecting Results of Operations, 2008 TEP Rate Order, below for more information.

Long-Term Wholesale Revenues

Revenues from long-term wholesale contracts increased by $2 million in 2008 compared with 2007. The average price per MWh sold under long-term contracts averaged $53 per MWh in 2008 compared with $51 per MWh in 2007. SeeFactors Affecting Results of Operations, Long-Term Wholesale Contracts, below for more information.

Short-Term Wholesale and Trading Revenues

Short-term wholesale sales volumes increased 23%, and revenues from short-term wholesale and trading activity increased by $60 million or 48% compared with 2007. In 2008, 405,000 MWh of wholesale sales and purchases were due to a single transaction involving a purchase and resale between TEP and two wholesale counterparties. The wholesale revenues and purchased power expenses associated with this transaction were $34 million and $31 million, respectively. Lower retail demand also contributed to higher sales volumes and a 34% increase in the average market price of wholesale power contributed to higher revenue compared with 2007. All revenues from short-term wholesale sales and 10% of the profit on trading activity is credited to costs included in TEP’s PPFAC.

Other Revenues

	2009		2008		2007
	-Millions of Dollars-
Reimbursements related to Springerville Units 3 and 4(1)	$	59	$	53	$	42
Other		24		19		16
Total Other Revenue	$	83	$	72	$	58

⁽¹⁾ Represents reimbursements from Tri-State and SRP, the owners of Springerville Units 3 and 4, respectively, for expenses incurred by TEP related to the operation of these plants.

In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include: inter-company revenues from UNS Gas and UNS Electric for corporate services provided by TEP; miscellaneous service-related revenues such as power pole attachments; damage claims; and customer late fees.

K-46

Operating Expenses

2009 Compared with 2008

Generation and Purchased Power Summary

TEP’s fuel and purchased power expense, and energy resources for 2009, 2008 and 2007 are detailed below:

	Generation/Purchases						Expense
	2009		2008		2007		2009			2008			2007
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation		9,272		10,573		10,970	$	202		$	235		$	213
Gas-Fired Generation		986		871		1,088		75			74			79
Renewable Generation		30		34		32		1			—			—
Total		10,288		11,478		12,090		278			309			292
Regulatory Accounting Reinstatement(1)		—		—		—		—			(24	)		—
Total Generation(2)		10,288		11,478		12,090		278			285			292
Purchased Power		3,086		2,948		2,047		142			238			140
Transmission		—		—		—		3			11			9
Increase (Decrease) to Reflect PPFAC Recovery Treatment		—		—		—		(20	)		—			—
Total Resources		13,374		14,426		14,137	$	402		$	534		$	441
Less Line Losses and Company Use		948		955		944
Total Energy Sold		12,426		13,471		13,193
									��

(1)	SeeNote 2.Regulatory Matters,for more information.
(2)	Fuel expense excludes $5 million in 2009, 2008 and 2007, related to Springerville Unit 3; the fuel costs incurred on behalf of Unit 3 are recorded in Fuel Expense and the reimbursement by Tri-State is recorded in Other Revenue.

PPFAC

TEP’s PPFAC became effective in January 2009 and allows TEP to pass through its actual fuel, purchased power and transmission costs net of short-term wholesale revenues and other offsets to its retail customers. For comparative purposes, those PPFAC related costs decreased by $30.5 million in 2009 compared with 2008. The decrease was due primarily to lower wholesale market prices for energy and natural gas. See2008 TEP Rate Order,Purchased Power and Fuel Adjustment Clause, below for more information.

Energy Resources

In 2009, coal-fired generation decreased by 12% due to: fuel switching at Sundt Unit 4 from coal to natural gas; a 1% decrease in retail kWh sales; and lower coal plant availability. Coal-related fuel expense, excluding a $24 million gain recorded in 2008 related to the adoption of regulatory accounting, decreased by $33 million during 2009. The lower generating output, as well as $9 million of expenses recorded in the third quarter of 2008 related to a settlement of mining-related costs, led to the decrease in coal-related fuel expense in 2009.

Fuel switching at Sundt Unit 4 led to a 13% increase in gas-fired generating output in 2009 compared with 2008; however, gas-related fuel expense increased by just $1 million due to a decrease in the average price for natural gas. Under TEP’s new rate structure, hedging activities are reflected in the PPFAC.

Purchased power volumes increased by 5% in 2009 compared with 2008, as it was more economic for TEP to purchase power in the wholesale energy market rather than run certain of its less efficient gas-fired units. The average price paid by TEP for purchased power during 2009 was approximately $46 per MWh, compared with an average cost of $76 per MWh for generating output from TEP’s gas-fired generating resources.

K-47

The table below summarizes TEP’s cost per kWh generated or purchased.

	2009		2008		2007
	-cents per
	kWh generated-
Coal		2.18		2.22		1.93
Gas		7.60		8.49		7.26
Purchased Power		4.57		8.07		6.84

Market Prices

As a participant in the Western U.S. wholesale power markets, TEP is directly and indirectly affected by changes in market conditions. The average annual market price for around-the-clock energy based on the Dow Jones Palo Verde Index and the average annual price for natural gas based on the Permian Index were higher in 2009 compared with 2008. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during 2010.

Avg. Market Price for Around-the-Clock Energy — $/MWh	2009		2008		2007
Year ended December 31	$	30	$	63	$	47

Avg. Market Price for Natural Gas — $/MMBtu	2009		2008		2007
Year ended December 31	$	3.34	$	7.41	$	6.11

TRA Amortization

TEP did not record any TRA amortization during 2009, as the TRA balance was amortized to zero in May 2008. TRA amortization was $24 million in 2008. Amortization of the TRA was the result of the 1999 Settlement Agreement with the ACC, which changed the accounting method for TEP’s generation operations. This item reflected the recovery, through 2008, of transition recovery assets which were previously regulatory assets related to the generation business.

O&M

The table below summarizes the items included in TEP’s O&M expense.

	2009		2008			2007
	-Millions of Dollars-
Base O&M	$	231	$	220		$	192
Reimbursed Expenses Related to Springerville Units 3 and 4		41		35			24
Gain on the Sale of SO2 Emissions Allowances		—		(1	)		(15	)
Expenses related to customer-funded renewable energy programs(1)		18		3			2
Reinstatement of Regulatory Accounting		—		(1	)		—
Total O&M	$	290	$	257		$	203

⁽¹⁾ Represents expenses related TEP’s customer-funded renewable energy programs; the offsetting funds collected from customers are recorded in other revenue.

Income Tax Expense

In 2009, TEP’s effective tax rate was 38% compared with 71% in 2008. In 2008, it was determined that the environmental penalties at San Juan would not be deductible for income tax purposes. As a result, an additional $3 million of tax expense was recognized in 2008 for penalties incurred in the current and prior years. Other items included in GAAP expense which will not be deductible for tax were offset by the recognition of income tax credits. SeeNote 9. Income Taxes, for more information.

K-48

Operating Expenses

2008 Compared with 2007

Coal

Coal-fired generating output decreased by 4% compared with 2007, due to lower coal plant availability resulting from planned and unplanned outages. Coal-related fuel expense, excluding the gain related to the reinstatement of regulatory accounting, increased by $22 million due primarily to higher mining-related costs at San Juan and Navajo, and increased coal costs at Sundt Unit 4.

Gas

Gas-fired generating output decreased by 20% due primarily to slower customer growth and mild weather. Gas-related fuel expense was $5 million, or 6%, lower than 2007 due in part to a decrease in realized losses on gas hedging activity. The average cost per kWh generated by TEP’s gas-fired fleet for 2008 increased 17% compared with 2007.

Purchased Power

Power purchase volumes increased 42% in 2008 compared with 2007, leading to a $98 million increase in purchased power expense. The higher purchased power volume and expense is due partially to higher short-term wholesale sales activity and replacement power purchases related to lower coal plant availability. In 2008, 405,000 MWh of wholesale sales and purchases were due to a single transaction involving a purchase and resale between TEP and two wholesale counterparties. The wholesale revenues and purchased power expenses associated with this transaction were $34 million and $31 million, respectively.

FACTORS AFFECTING RESULTS OF OPERATIONS

2008 TEP Rate Order

Base Rate Increase

TEP received a base rate increase, effective December 1, 2008, of approximately 6% over its previous average retail rate of 8.4 cents per kWh. TEP’s new base rates are expected to increase retail revenue by approximately $50 million annually. The average base rate is 8.8 cents per kWh and includes approximately 2.9 cents per kWh for fuel and purchased power costs.

Purchased Power and Fuel Adjustment Clause

The PPFAC became effective starting January 1, 2009. The PPFAC allows recovery of fuel and purchased power costs, including demand charges, transmission costs and the prudent costs of contracts for hedging fuel and purchased power costs. The PPFAC consists of a forward component and a true-up component.

• The forward component was established as of April 1, 2009 and will be updated on April 1 of each year. The forward component is based on the forecasted fuel and purchased power costs for the 12-month period from April 1 to March 31, less the base cost of fuel and purchased power of 2.9 cents per kWh, which is embedded in base rates. The ACC approved a forward component of 0.18 cents per kWh, effective April 1, 2009.

• The true-up component will reconcile any over/under collected amounts from the preceding 12 month period and will be credited to or recovered from customers in the subsequent year.

As part of the reconciliation of fuel and purchased power costs and PPFAC revenues, TEP credits the following against the recoverable costs: 100% of short-term wholesale revenues; 10% of the profit on trading activity; and 50% of the revenues from the sales of SO₂ emission allowances.

On a cash basis, Fixed CTC revenue to be refunded ($58 million collected from May 2008 to November 30, 2008) will be credited to customers as an offset to the PPFAC. This credit will off-set the forward and true-up components of the PPFAC, resulting in a PPFAC charge of zero until the Fixed CTC revenue to be refunded is fully credited, which is expected to occur over 36 to 48 months beginning April 1, 2009.

K-49

Base Rate Increase Moratorium

TEP’s base rates are frozen through December 31, 2012. TEP is prohibited from submitting a base rate application before June 30, 2012. The test year to be used in TEP’s next base rate application must be no earlier than December 31, 2011.

Notwithstanding the rate increase moratorium, base rates and adjustor mechanisms may be changed in emergency conditions which are beyond TEP’s control if the ACC concludes such changes are required to protect the public interest. The moratorium does not preclude TEP from seeking rate relief in the event of the imposition of a federal carbon tax or related federal carbon regulations.

Springerville Units 3 and 4

TEP operates Springerville Unit 3 on behalf of Tri-State and receives annual benefits in the form of rental payments and other fees and cost savings. TEP recorded pre-tax benefits of $12 million in 2009 and 2008.

Springerville Unit 4 was completed in December 2009. TEP operates Springerville Unit 4 on behalf of SRP and expects to receive annual pre-tax benefits beginning in 2010 of approximately $8 million in the form of rental payments and other fees and cost savings.

Depreciation

In January 2010, TEP completed an updated depreciation study which indicated that its transmission assets’ depreciable lives should be extended. As a result, TEP adopted new transmission depreciation rates effective January 2010 which will have the effect of reducing depreciation expense by approximately $14 million in 2010.

Sundt Unit 4

Sundt Unit 4 is leased by TEP and the term of the lease expires in January 2011. In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4 from the equity owner for approximately $52 million. The purchase price is subject to increase by 0.75% of the purchase price per month in the event that the purchase occurs after March 31, 2010. TEP expects to finalize the purchase prior to March 31, 2010. Following the completion of the transaction, TEP expects to redeem the outstanding Sundt Unit 4 lease debt of $5 million, terminate the lease agreement and cause title of Sundt Unit 4 to be transferred to TEP.

Refinancing Activity

The TEP Credit Agreement, which consists of a $150 million revolving credit facility and a $341 million letter of credit facility, matures in August 2011. 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 0.45% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.45% per annum. Based on our current estimates, we believe that the interest costs associated with TEP’s credit agreement after it is refinanced will increase over current levels. At December 31, 2009, there were $35 million of borrowings at an interest rate of 0.68% and $1 million in letters of credit outstanding under the Revolving Credit Facility. We are continuously monitoring conditions in the capital markets in order to achieve favorable terms and conditions. SeeLiquidity and Capital Resources, TEP Credit Agreement,below for more information.

Pension and Postretirement Benefit Expense

In 2009 and 2008, TEP charged $17 million and $10 million, respectively, of pension and postretirement benefit expenses to O&M expense. In 2010, TEP expects to charge $15 million of pension and postretirement benefit expense to O&M expense. The expected decrease in 2010 compared with 2009 is due primarily to the increase in the market value of the pension asset values. SeeNote 10. Employee Benefit Plans, for more information.

K-50

El Paso Electric Dispute

TEP was a party to a proceeding at FERC that involved the interpretation of the 1982 Power Exchange and Transmission Agreement (1982 Agreement) between TEP and El Paso. The dispute related to TEP’s ability to use existing rights for the transmission of power from Luna into TEP’s system. On November 13, 2008, the FERC issued a decision that supported TEP’s position. As a result of the ruling, El Paso refunded to TEP pre-tax amounts of $10 million in disputed transmission charges and $1 million of accrued interest. TEP is no longer accruing transmission charges under this agreement. In January 2009, FERC granted El Paso’s request for a rehearing in this matter. As a result of the pending appeal process, TEP’s net income in 2008 or 2009 does not reflect the refund made by El Paso. TEP does not expect to recognize any income related to this refund until the appeals process is fully resolved.

In December 2008, TEP filed a complaint in the U.S. Federal District Court against El Paso seeking a $2 million reimbursement for transmission charges paid by TEP to PNM for transmission service in an attempt to mitigate TEP’s damages before FERC issued its decision in November 2008. On February 23, 2009, El Paso filed a motion to dismiss TEP’s complaint, or in the alternative, requested a stay in the proceeding pending further resolution by FERC. In April 2009, TEP filed a response requesting that the court deny El Paso’s motion, followed by an El Paso reply in May 2009. On September 10, 2009, the District Court denied El Paso’s motion to dismiss and stayed the proceeding pending a final resolution of the FERC proceeding and any appeal. TEP cannot predict the timing or outcome of this lawsuit.

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. The table below summarizes sales made since 2007.

			Pre-tax Gain
Delivery	Allowances Sold		(millions)
2007		22,000	$	15
2008		4,000		1
2009		—		—

Existing regulations call for a reduction to the EPA SO₂ Emissions Allowances allocation beginning in 2010. As a result, starting in 2010 and for the remaining life of the program, TEP’s annual SO₂Emissions Allowance allocation will be approximately 28,000 allowances. The exact number of excess allowances for future years cannot be determined until the SO₂ allowance consumption for each year is verified by EPA. TEP expects to have approximately 13,000 excess SO₂ Emission Allowances annually beginning in 2010 and for the remaining life of the program. The decline in sales of SO₂ allowances from 2007 to 2009 is a result of a decrease in the market price for the allowances.

As part of the 2008 TEP Rate Order, TEP will credit 50% of the revenue from the sales of its SO₂ Emissions Allowances to the PPFAC. As of January 1, 2010, the average market price of SO₂ Emissions Allowances was $59. On December 31, 2008 and 2007, the market price of SO₂ Emissions Allowances was $205 and $534, respectively.

Competition

TEP’s customers have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP’s services in the future. Self-generation by TEP’s customers 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.

Renewable Energy Standard and Tariff

TEP began implementing its ACC approved REST plan on June 1, 2008. In 2009 and 2008 TEP collected $29 and $9 million in REST surcharges, of which $25 million and $3 million, respectively, were expensed for REST projects, respectively. Any surcharge collections above or below the amount of renewable expenditures will be deferred and reflected in TEP’s financial statements as a regulatory liability or asset. In 2010, TEP expects to collect $32 million from customers through the REST. REST implementation plans and the associated surcharge must be submitted annually to the ACC for review and approval. For more information, seeItem 1. Business, TEP, Renewable, Energy Standard and Tariff, above.

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Electric Energy Efficiency Standards

In December 2009, the ACC established a process to adopt new Electric Energy Efficiency Standards (EE Standards) designed to require TEP, UNS Electric and other affected utilities to implement DSM programs, only to the extent that they are cost effective. The proposed EE Standards target cost effective total kWh savings in 2011 of 1.25% and ramping up each year to reach a targeted cumulative annual reduction in retail kWh sales of 22% by 2020. Savings from Direct Load Control programs, previously implemented DSM programs and from a portion of energy efficient building codes may be counted towards meeting the target. The proposed EE Standards provide for recovery of costs incurred to implement cost effective DSM programs. TEP’s DSM programs and rates charged to customers for such programs are subject to ACC approval. If the ACC approves EE Standards, they must be certified by the Arizona Attorney General before taking affect.

Rosemont Copper Mine

In 2007, Augusta Resources Corporation (Augusta) filed a plan of operations with the United States Forest Service (USFS) for the proposed Rosemont Copper Mine near Tucson, Arizona. Augusta is waiting for an environmental impact statement from the USFS before it can begin construction and operation of the mine. If the Rosemont Copper Mine begins full production, it would become TEP’s largest retail customer, with an estimated annual load of up to 110 MW. TEP cannot predict if or when the mine will commence operations.

Fair Value Measurements

As described in Note 12 to the Notes to Consolidated Financial Statements, TEP adopted fair value accounting, on January 1, 2008 which, among other things, establishes a three-tier value hierarchy, based on the valuation techniques used to determine the fair value of derivative assets and liabilities.

The following table sets forth, by level within the fair value hierarchy, TEP’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009. As required by fair value accounting, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	TEP
	Quoted Prices in		Significant Other			Significant
	Active Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2009
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	8	$	—		$	—		$	8
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		14			—			14
Energy Contracts(3)		—		1			5			6
Total Assets		8		15			5			28
Liabilities
Energy Contracts(3)		—		(5	)		(9	)		(14	)
Interest Rate Swaps(4)		—		(6	)		—			(6	)
Total Liabilities		—		(11	)		(9	)		(20	)
Net Total Assets and (Liabilities)	$	8	$	4		$	(4	)	$	8

(1)	Cash Equivalents are based on observable market prices and are comprised of the fair value of money market funds and certificates of deposit.
(2)	Level 2 investments comprise amounts held in mutual and money market funds related to deferred compensation and Supplemental Executive Retirement Plan (SERP) benefits. The valuation is based on quoted prices, traded in active markets. These investments are included in Investments and Other Property — Other in the UniSource Energy and TEP balance sheets.
(3)	Energy contracts include gas swap agreements (Level 2), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to take advantage of favorable market conditions and reduce exposure to energy price risk. The valuation techniques are described below.
(4)	Interest Rate Swaps are valued based on the six month LIBOR index or the Securities Industry and Financial Markets Association (SIFMA) Municipal Swap Index.

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TEP recorded in 2009, net unrealized losses of $2 million in net Regulatory Assets and $1 million as other comprehensive income due to the change in the fair value of commodity derivative contracts classified as Level 3 in the fair value hierarchy.

Valuation Techniques

TEP values its energy derivative contracts by obtaining market quotes for periods and delivery points where an active market exists. For both power and gas prices, TEP obtains quotes from brokers, major market participants, exchanges or industry publications. TEP primarily uses one set of quotations each for power and for gas, and then use the other sources as validation of those prices. The broker providing quotes for power prices states that the market information provided is indicative only, but believes it to be reflective of market conditions as of the time and date indicated.

TEP’s Level 3 derivatives include certain energy contracts where published prices are not readily available. These include contracts for delivery periods during non-standard time blocks, contracts for delivery during only a few months of a given year when prices are quoted only for the annual average, or contracts for delivery at illiquid delivery points. In these cases, TEP applies certain management assumptions to value such contracts. These assumptions include applying percentage multipliers to value non-standard time blocks, applying historical price curve relationships to calendar year quotes, and including adjustments for transmission and line losses to value contracts at illiquid delivery points. We also consider the impact of counterparty credit risk using current and historical default and recovery rates as well as our own credit risk using credit default swap data. The fair value of TEP’s purchase power call option is estimated using an internal pricing model which includes assumptions about market risks such as liquidity, volatility, and contract valuation. TEP’s model also considers credit and non-performance risk. TEP reviews these assumptions on a quarterly basis.

LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

The table below shows the cash available to TEP after capital expenditures, scheduled debt payments and payments on capital lease obligations:

	2009			2008			2007
	-Millions of Dollars-
Net Cash Flows — Operating Activities (GAAP)	$	268		$	269		$	264
Amounts from Statements of Cash Flows:
Less: Capital Expenditures		(235	)		(295	)		(163	)
Net Cash Flows after Capital Expenditures (non-GAAP)*		33			(26	)		101
Amounts from Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations		(24	)		(74	)		(71	)
Plus: Proceeds from Investment in Lease Debt		13			25			28
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)*	$	22		$	(75	)	$	58

	2009			2008			2007
Net Cash Flows — Operating Activities (GAAP)	$	268		$	269		$	264
Net Cash Flows — Investing Activities (GAAP)		(250	)		(391	)		(137	)
Net Cash Flows — Financing Activities (GAAP)		(29	)		129			(120	)
Net Cash Flows after Capital Expenditures (non-GAAP)*		33			(26	)		101
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)*		22			(75	)		58

* Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows - Operating Activities, which is determined in accordance with GAAP as a measure of liquidity. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments provide useful information to investors as measures of liquidity and our ability to fund our capital requirements, make required payments on debt and capital lease obligations, and pay dividends to UniSource Energy.

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Liquidity Outlook

During 2010, TEP expects to generate sufficient internal cash flows to fund the majority of its capital expenditures and operating activities. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to fund its business activities.

Operating Activities

In 2009, net cash flows from operating activities decreased by $1 million compared with 2008. Net cash flows were impacted by:

• a $65 million increase in cash receipts from retail and wholesale electric sales, less fuel and purchased power costs, due to: an increase in retail electric cash receipts resulting from the rate increase that became effective in December 2008 and cash collections from retail customers that are used to offset expenses related to renewable energy and energy efficiency programs; and lower market prices for natural gas and purchased power;

• an $11 million decrease in total interest paid resulting from lower rates on variable rate debt and lower capital lease interest paid; offset by

• a $39 million increase in O&M costs related to: costs associated with renewable energy and energy efficiency programs that are offset by funds collected from retail customers; an increase in pension-related costs; extensive planned generating plant outage and maintenance costs; general cost pressures resulting from inflation; and O&M related to Springerville Units 3 and 4 that is reimbursed by the plant owners;

• a $27 million increase in total taxes paid (net of refunds received) due primarily to higher taxable income; and

• a $12 million increase in wages paid.

Investing Activities

Net cash used for investing activities was $141 million lower in 2009 compared with 2008 primarily due to: a $133 million deposit made last year by TEP to the trustee for bonds that matured in August 2008; and a $59 million decrease in capital expenditures; partially offset by a $31 million investment in Springerville Unit 1 lease debt; and a $12 million decrease in proceeds from investments in lease debt and equity. SeeFinancing Activities,Investments in Springerville Lease Debt and Equity,below for more information.

Capital Expenditures

TEP’s forecasted capital expenditures are summarized below:

Category	2010		2011		2012		2013		2014
			-Millions of Dollars-
Transmission and Distribution	$	107	$	117	$	91	$	99	$	73
Generation Facilities		108		65		65		72		64
Environmental		8		5		11		24		44
General and Other		35		30		36		30		28
Total	$	258	$	217	$	203	$	225	$	209

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• Included in TEP’s capital expenditures forecast for 2010 is $52 million for the proposed purchased of Sundt Unit 4. SeeSundt Unit 4, above, for more information.

• Items excluded from TEP’s capital expenditures forecast are: the estimated cost to construct proposed Tucson to Nogales, Arizona transmission line of $120 million; estimated costs of $300 million between 2011-2014 to construct 75 to 150 MW of local generation that may be required in 2015.

See Item 1. Business, Tucson Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Linefor more information.

All of these estimates are subject to continuing review and adjustment. Actual capital 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 its capital expenditures through internally generated cash flow.

Investments in Springerville Lease Debt

At December 31, 2009, TEP had $95 million of investments in lease debt on its balance sheet. In March 2009, TEP made a $31 million purchase of Springerville Unit 1 lease debt. The table below provides a summary of the investment balances in lease debt.

	Lease Debt Investment Balance
Leased Asset	December 31, 2009		December 31, 2008
	- In Millions -
Investments in Lease Debt:
Springerville Unit 1	$	88	$	59
Springerville Coal Handling Facilities		7		20
Total Investment in Lease Debt	$	95	$	79

Unless TEP makes new investments in lease debt, the investment in lease debt balance declines over time due to the amortization of lease debt that occurs as a result of the normal payments TEP makes on its capital lease obligations. The Springerville Unit 1 and Springerville Coal Handling Facilities leases expire in 2015.

SeeNote6of Notes to Consolidated Financial Statements — Debt, Credit Facilities and Capital Lease Obligations

Financing Activities

Net cash proceeds from financing activities were $158 million lower in 2009 compared with 2008 due to: proceeds of $221 million received in 2008 related to long-term debt issuances; and a $58 million increase in dividends paid to UniSource Energy in 2009; partially offset by a $25 million increase in net proceeds from revolving credit facility borrowings; a $30 million capital contribution from UniSource Energy; a decrease in payments for capital lease obligations of $50 million; and a $10 million decrease in repayments of long-term debt.

TEP Credit Agreement

The TEP Credit Agreement consists of a $150 million revolving credit facility and a $341 million letter of credit facility which supports $329 million of tax-exempt variable rate bonds. The TEP Credit Agreement matures in 2011 and is secured by $491 million of Mortgage Bonds. At December 31, 2009, there were $35 million of borrowings at an interest rate of 0.68% and $1 million in letters of credit outstanding under the Revolving Credit Facility.

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 0.45% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.45% per annum. TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.45% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.

The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leaseback 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, it may pay dividends to UniSource Energy.

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In September 2008, as a result of higher than expected fuel and purchased power costs, TEP amended its credit agreements to provide more flexibility to meet the required leverage ratio. The leverage ratio is calculated as a ratio of total indebtedness to earnings before interest, taxes, depreciation and amortization. Although fuel and purchase power expenses have decreased in recent months, current economic conditions could result in lower customer growth rates and lower sales. If TEP’s financial results are impacted by the economic downturn, our ability to comply with financial covenants could be jeopardized and we may seek waivers or amendments of the covenants.

As of December 31, 2009, 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.

TEP Letter of Credit Facility

In 2008, TEP entered into a three-year $132 million letter of credit and reimbursement agreement (2008 TEP Letter of Credit Facility). The 2008 TEP Letter of Credit Facility supported $130 million aggregate principal amount of variable rate tax-exempt IDBs that were issued on behalf of TEP in June 2008.

The 2008 TEP Letter of Credit Facility was terminated in January 2010 upon the conversion of the interest rate mode on the tax-exempt IDBs from variable to fixed rate, and the mortgage bonds securing the facility were cancelled. SeeBond Issuances, below.

Capital Contribution from UniSource Energy

In March 2009, UniSource Energy contributed $30 million of capital to TEP. TEP used the proceeds to purchase Springerville Unit 1 lease debt. There were no capital contributions from UniSource Energy to TEP in 2008.

Bond Issuances

In October 2009, the Pima Authority issued approximately $80 million of its 2009 Series A tax-exempt pollution control bonds (2009 Pima A San Juan Bonds) for TEP’s benefit. At the same time, the Coconino County, Arizona Pollution Control Corporation issued approximately $15 million of its 2009 Series A tax-exempt pollution control bonds (2009 Coconino A Bonds) for TEP’s benefit. The 2009 Pima A San Juan bonds are unsecured, bear interest at a rate of 4.95%, mature on October 1, 2020, and are not callable prior to maturity. The 2009 Coconino A Bonds are unsecured, bear interest at 5.125%, mature on October 1, 2032, and are callable at par beginning October 1, 2019. Semi-annual interest payments on both series of bonds are payable beginning April 1, 2010. TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs for each through the respective maturity dates.

The proceeds from the issuance of the 2009 Pima A San Juan Bonds and the 2009 Coconino A Bonds were deposited with a trustee and were used in November 2009 to redeem approximately $80 million of 6.95% 1997 Series A City of Farmington, New Mexico Pollution Control Bonds and approximately $15 million of 7.0% 1997 Series B Coconino County Pollution Control Bonds, respectively. The average annual interest savings is expected to be approximately $2 million.

In March 2008, the Pima Authority issued approximately $91 million of its 2008 Series A tax-exempt IDBs (2008 Pima A Bonds) for TEP’s benefit. The proceeds were used to redeem a corresponding principal amount of bonds previously issued by the Pima Authority for TEP’s benefit which TEP repurchased in 2005. TEP did not cancel the Repurchased Bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. As holder of the Repurchased Bonds being redeemed, TEP received the payment of the redemption price. TEP used $75 million of the redemption price proceeds to repay loans outstanding under its revolving credit facility and $10 million to redeem a portion of TEP’s Collateral Trust Bonds that matured on August 1, 2008. The 2008 Pima A Bonds are unsecured, bear interest at the rate of 6.375%, mature on September 1, 2029 and are callable at par in March 2013.

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In June 2008, the Pima Authority issued $130 million of its 2008 Series B tax-exempt IDBs (2008 Pima B Bonds) for TEP’s benefit. The proceeds were used to redeem a corresponding principal amount of bonds previously issued by the Pima Authority for TEP’s benefit which TEP repurchased in 2005. TEP did not cancel the Repurchased Bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. As holder of the Repurchased Bonds being redeemed, TEP received the payment of the redemption price. TEP used $128 million of the redemption price proceeds to redeem the remaining 7.5% Collateral Trust Bonds that matured on August 1, 2008. The 2008 Pima B Bonds were supported by a letter of credit (LOC) issued under the 2008 TEP Letter of Credit Facility. SeeTEP Letter of Credit Facility, above.

In January 2010, TEP converted the interest mode on the 2008 Pima B Bonds to a fixed rate. The 2008 Pima B bonds were reoffered in January 2010 with a term rate of 5.75% through maturity of September 2029. Interest is payable semi-annually beginning June 1, 2010. The bonds are callable at par beginning January 2015. Although the fixed interest rate is higher than the variable interest rate that was in effect at the time of the conversion, the fixed rate conversion reduced TEP’s future interest rate risk and allowed TEP to terminate the LOC and cancel the mortgage bonds. SeeInterest Rate RiskandTax Exempt Local Furnishing Bonds,below for additional information.

Interest Rate Risk

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under its revolving credit facility. At December 31, 2009 and December 31, 2008, TEP had $459 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds was 10% on the $130 million of 2008 Pima B Bonds and is 20% on the other $329 million in IDBs. During 2008, the average rates paid ranged from 0.55% to 8.09%. During 2009, the average rates paid have ranged from 0.25% to 0.79%. At February 23, 2010, the average rate on the debt was 0.24%.

In August 2009, TEP reduced its exposure to variable interest rate risk by entering into an interest rate swap that had the effect of converting $50 million of its variable rate IDBs to a fixed interest rate from September 2009 to September 2014. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.

In January 2010, TEP completed a transaction that converted the interest rate on the $130 million of 2008 Pima B Bonds to a fixed rate of 5.75%. SeeBond Issuances, above.

Interest Rate Swaps — Springerville Common Facilities Lease Debt

In 2006 and May 2009, TEP entered into interest rate swaps to hedge the floating interest rate risk associated with the Springerville Common Facilities Lease Debt. Interest on the lease debt is payable at six-month LIBOR plus a spread. The applicable spread was 1.625% as of December 31, 2009 and 1.5% as of December 31, 2008. The swaps have the effect of fixing the interest rates on $65 million of the lease debt outstanding at December 31, 2009 at rates ranging from 3.18% to 5.77%.

Mortgage Indenture

TEP’s Mortgage 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. The Mortgage 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 Mortgage.

TEP’s Credit Agreement, which totals $491 million and is secured by Mortgage Bonds, limits the amount of mortgage bonds that may be outstanding to no more than $840 million. At December 31, 2009, TEP had a total of $623 million in outstanding Mortgage Bonds, consisting of $491 million in bonds securing the TEP Credit Agreement, and $132 million in bonds securing the 2008 TEP Letter of Credit Facility. The $132 million in bonds securing the TEP 2008 Letter of Credit Facility were cancelled in January 2010 when the LOC was terminated. Although the 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. SeeBond Issuances, above.

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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. During 2008, the Pima Authority issued $221 million of tax-exempt local furnishing bonds for TEP’s benefit. SeeBond Issuances,above.

As of December 31, 2009, TEP had approximately $580 million of tax-exempt local furnishing bonds outstanding. Approximately $331 million in principal amount of such bonds financed Springerville Unit 2 and the Express Line. In addition, approximately $11 million of remaining lease debt related to the Sundt Unit 4 lease obligation was issued as tax-exempt local furnishing bonds.

In December 2008, the Arizona Department of Commerce allocated $200 million of tax-exempt financing volume cap to TEP for purposes of financing local furnishing transmission and distribution projects in Pima County, Arizona. Any new IDBs issued under this allocation would be issued in one or more series by the Pima Authority for the benefit of TEP. TEP has until December 2011 to use this volume cap allocation. Upon receipt of this allocation in December 2008, TEP paid a $2 million security deposit to the Arizona Department of Commerce. This security deposit is refundable on a pro rata basis after each new series of IDBs is issued.

Capital Lease Obligations

At December 31, 2009, TEP had $529 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease amounts in each of the obligations.

	Capital Lease Obligation
	Balance			Renewal/Purchase
Leased Asset	at December 31, 2009		Expiration	Option
	- In Millions -
Springerville Unit 1	$	321	2015	Fair market value purchase option
Springerville Coal Handling Facilities		85	2015	Fixed price purchase option of $120 million
Springerville Common Facilities		110	2017 & 2021	Fixed price purchase option of $106 million
Sundt Unit 4		13	2011	Agreement to purchase equity entered into January 2010
Total Capital Lease Obligations	$	529

In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4. SeeSundt Unit 4, above, for more information.

Except for Sundt Unit 4, TEP’s 14% equity ownership in the Springerville Unit 1 Leases and its 13% equity ownership in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases. The renewal and purchase option for Springerville Unit 1 is for fair market value as determined at that time, while the purchase price option is fixed for the Springerville Coal Handling Facilities and Common Facilities.

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TEP’s capital lease obligation balances decline over time due to the normal capital lease payments made by TEP. SeeNote 6. Debt, Credit Facilities and Capital Lease Obligationsfor more information about the fixed purchase price amounts.

The following chart displays TEP’s contractual obligations as of December 31, 2009 by maturity and by type of obligation.

TEP’s Contractual Obligations
- Millions of Dollars -

Payment Due in Years											2015
Ending December 31,	2010		2011		2012		2013		2014		and after		Other		Total
Long Term Debt
Principal	$	—	$	494	$	—	$	—	$	—	$	445	$	—	$	939
Interest		39		38		34		34		34		484		—		663
Capital Lease Obligations		93		107		118		123		195		103		—		739
Operating Leases		1		—		—		—		—		—		—		1
Purchase Obligations:
Fuel (including Transportation)		89		51		42		39		37		142		—		400
Purchased Power		44		12		4		2		2		2		—		66
Transmission		2		2		2		2		2		2		—		12
Other Long-Term Liabilities:
Pension & Other Post Retirement Obligations		26		5		5		6		6		30		—		78
Acquisition of Springerville Coal Handling and Common Facilities		—		—		—		—		—		226		—		226
Unrecognized Tax Benefits		—		—		—		—		—		—		19		19
Total Contractual Cash Obligations	$	294	$	709	$	205	$	206	$	276	$	1,434	$	19	$	3,143

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

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

• TEP’s Credit Agreement contains pricing 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, and the amount of fees it pays for its letters of credit and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facility.

• 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, 2009, TEP was in compliance with these covenants. SeeTEP Credit Agreement above.

• TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or a letter of credit due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings or if there has been a material change in TEP’s creditworthiness. As of December 31, 2009, TEP had posted a $1 million letter of credit as collateral with counterparties for credit enhancement.

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Dividends on Common Stock

TEP declared and paid dividends to UniSource Energy of $60 million in 2009, $3 million in 2008, and $53 million in 2007.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2009, TEP was in compliance with the terms of the TEP Credit Agreement.

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 for TEP to pay dividends from current year earnings.

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported net income of $7 million in 2009, $9 million in 2008, and $4 million in 2007. We expect operations at UNS Gas to vary with the seasons, with peak energy usage occurring in the winter months.

The table below provides summary financial information for UNS Gas.

	2009		2008		2007
	-Millions of Dollars-
Gas Revenues	$	149	$	172	$	149
Other Revenues		4		2		2
Total Operating Revenues		153		174		151
Total Purchased Gas and PGA Expense		99		117		101
Other Operations and Maintenance Expense		25		25		27
Depreciation and Amortization		7		7		8
Taxes other than Income Taxes		3		3		3
Total Other Operating Expenses		134		152		139
Operating Income (Loss)		18		22		12
Total Interest Expense		6		7		7
Total Other Income		—		—		2
Income Tax Expense (Benefit)		5		6		3
Net Income (Loss)	$	7	$	9	$	4

The table below shows UNS Gas’ therm sales and revenues for 2009, 2008 and 2007.

	Gas Sales (Millions of Therms)									Gas Revenues (Millions of Dollars)
					09-08									09-08
	2009		2008		%Chng			2007		2009		2008		% Chng			2007
Retail Therm Sales:
Residential		70		72		(3.4	%)		71	$	91	$	97		(6.5	%)	$	90
Commercial		30		31		(4.4	%)		31		32		36		(9.1	%)		34
Industrial		2		2		15.4	%		2		2		2		7.6	%		2
Public Authorities		6		7		(7.7	%)		8		7		8		(11.4	%)		7
Total Retail Therm Sales		108		112		(3.6	%)		112		132		143		(7.3	%)		133
Transport		36		40		(7.0	%)		25		4		4		(2.7	%)		3
Negotiated Sales Program (NSP)		30		32		(7.7	%)		19		13		25		(48.7	%)		13
Total Therm Sales		174		184		(5.1	%)		156	$	149	$	172		(13.1	%)	$	149

Retail therm sales in 2009 decreased by 3.6% compared with 2008 due to mild weather and weak economic conditions. Heating degree days were down 3% compared with 2008 and use per customer also decreased. Economic conditions have resulted in lower customer growth rates than experienced in prior years. As of December 31, 2009, UNS Gas had approximately 145,000 retail customers, which represents an increase of less than 1% compared with year end 2008. The lower gas sales volumes resulted in an $11 million, or 7.3%, decrease in retail revenues.

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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. SeeFactors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.

FACTORS AFFECTING RESULTS OF OPERATIONS

Rates

Energy Cost Adjustment Mechanism

UNS Gas’ retail rates include a 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 monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered from or returned to customers 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 calculates the twelve-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month period. In 2007, the ACC increased the annual cap on the maximum increase in the PGA factor from $0.10 per therm to $0.15 per therm in a twelve month period.

At any time UNS Gas’ PGA bank balance is under-recovered, UNS Gas may request a PGA surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed to customers basis, UNS Gas is required to make a filing so that the ACC can determine how the over-collected balance should be returned to customers. On December 31, 2009, the PGA bank balance was over-collected by $10 million. In October 2009, the ACC approved a $0.08 cent per therm PGA surcredit, effective November 2009 through October 2010 or until the balance reaches zero.

2008 General Rate Case Filing

Due to increases in capital and operating costs related to providing safe and reliable service to customers of UNS Gas, UNS Gas believes the rates approved by the ACC in 2007 are inadequate for UNS Gas to recover its costs and earn a reasonable return on its investments.

In November 2008, UNS Gas filed a general rate case with the ACC on a cost of service basis. Below is a table that summarizes UNS Gas’ request:

Test year — 12 months ended June 30, 2008	Requested by UNS Gas
Original cost rate base	$182 million
Revenue deficiency	$9.5 million
Total rate increase (over test year revenues)	6%
Cost of long-term debt	6.5%
Cost of equity	11.0%
Actual capital structure	50% equity / 50% debt
Weighted average cost of capital	8.75%
Rate of return on fair value rate base	6.80%

In June 2009, ACC staff recommended a rate increase of $3.4 million based on an original cost rate base of $178 million and a 10% return on equity. Hearings before the ALJ concluded in August 2009. UNS Gas expects the ACC to issue a final order in the first half of 2010. UNS Gas cannot predict the outcome of this general rate case proceeding.

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Fair Value Measurements

UNS Gas adopted fair value measurements, on January 1, 2008. SeeTucson Electric Power,Factors Affecting Results of Operations, above, for more information about fair value measurements.

The following table sets forth, by level within the fair value hierarchy, UNS Gas’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

UNS Gas
December 31, 2009
- - Millions of Dollars -

	Quoted Prices in
	Active Markets		Significant Other			Significant
	for Identical		Observable			Unobservable
	Assets (Level 1)		Inputs (Level 2)			Inputs (Level 3)		Total
Cash Equivalents(1)	$	25	$	—		$	—	$	25
Cash Collateral(2)		—		2			—		2
Energy Contracts(3)		—		(7	)		—		(7	)
Total	$	25	$	(5	)	$	—	$	20

(1)	Cash Equivalents are based on observable market prices and are comprised of the fair value of money market funds and certificates of deposit.
(2)	Collateral provided to energy contract counterparties to reduce credit risk exposure.
(3)	Energy contracts include gas swap agreements (Level 2) entered into to take advantage of favorable market conditions and reduce exposure to energy price risk. The amounts include current and non-current assets and are net of current and non-current liabilities.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas’ capital requirements consist primarily of capital expenditures. In 2009, capital expenditures were $13 million. UNS Gas expects internal cash flows to fund its future operating activities and a large portion of its construction expenditures. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements. Sources of funding future capital expenditures could include draws on the revolving credit facility, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy. The rate increase approved by the ACC in November 2007 covers some, but not all, of UNS Gas’ higher costs and capital investments.

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Operating Cash Flow and Capital Expenditures

The table below provides summary cash flow information for UNS Gas.

	2009			2008			2007
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities		37		$	3		$	28
Investing Activities		(13	)		(16	)		(22	)
Financing Activities		—			1			(6	)
Net Increase (Decrease) in Cash		24			(12	)		—
Beginning Cash		7			19			19
Ending Cash		31			7			19

Operating cash flows increased in 2009 due to a net over-recovery of PGA gas costs and cash inflows related to the return of cash collateral deposited in prior periods with gas supply and hedging counterparties.

Forecasted capital expenditures for UNS Gas are as follows:

	2010		2011		2012		2013		2014
	- Millions of Dollars -
UNS Gas	$	14	$	16	$	16	$	16	$	18

UNS Gas/UNS Electric Revolver

The UNS Gas/UNS Electric Revolver is a $60 million unsecured revolving credit facility which matures in August 2011. Either borrower may borrow up to a maximum of $45 million so long as the combined amount borrowed does not exceed $60 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 Gas/UNS Electric Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric.

UNS Gas and UNS Electric have the option of paying interest on borrowings at LIBOR plus 1.0% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate. Letter of credit fees are 1.0% per annum.

The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, dividends, mergers and sales of assets; it also contains a maximum leverage ratio and a minimum cash flow to interest coverage ratio for each borrower. As of December 31, 2009, 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, to fund a portion of its capital expenditures, or to issue letters of credit to provide credit enhancement for its natural gas procurement and hedging activities. As of February 23, 2010, UNS Gas had no outstanding letters of credit under the UNS Gas/UNS Electric Revolver.

Interest Rate Risk

UNS Gas is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. As a result of recent volatility in interest rates, UNS Gas may be required to pay higher rates of interest on borrowings under its revolving credit facility. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

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Senior Unsecured Notes

UNS Gas has $100 million of 6.23% senior unsecured notes outstanding of which $50 million matures in 2011 and $50 million matures in 2015. These notes are guaranteed by UES. The note purchase agreement for UNS Gas restricts transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness, and also contains a minimum net worth test. As of December 31, 2009, UNS Gas was in compliance with the terms of its note purchase agreement.

UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Gas may, without meeting these tests, refinance existing debt and incur up to $7 million in short-term debt.

Contractual Obligations

UNS Gas Supply Contracts

UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased. UNS Gas has firm transportation agreements with capacity sufficient to meet its current load requirements. These contracts expire in various years between 2011 and 2023. These costs are passed through to UNS Gas’ customers via the PGA.

UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers. These purchases and hedges are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month. UNS Gas hedged approximately 45% of its expected monthly consumption for the 2009/2010 winter season (November through March). Additionally, UNS Gas has approximately 40% of its expected gas consumption hedged for April through October 2010, and 35% hedged for the period November 2010 through March 2011.

The following table displays UNS Gas’ contractual obligations as of December 31, 2009 by maturity and by type of obligation.

UNS Gas’ Contractual Obligations
- -Millions of Dollars-

											2015
Payment Due in Years											and
Ending December 31,	2010		2011		2012		2013		2014		after		Total
Long Term Debt
Principal	$	—	$	50	$	—	$	—	$	—	$	50	$	100
Interest		6		6		3		3		3		4		25
Purchase Obligations — Fuel		19		14		5		3		3		23		67
Pension & Other Post Retirement Obligations		1		—		—		—		—		—		1
Total Contractual Cash Obligations	$	26	$	70	$	8	$	6	$	6	$	77	$	193

UNS Gas conducts certain of its gas procurement and risk management activities under certain agreements whereby UNS Gas may be required to post margin due to changes in contract values, a change in UNS Gas’ creditworthiness or exposures exceeding credit limits provided to UNS Gas. As of December 31, 2009, UNS Gas had posted $2 million in such credit enhancements.

Dividends on Common Stock

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. As of December 31, 2009, UNS Gas was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above.

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UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $6 million in 2009, $4 million in 2008 and $5 million in 2007. 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.

The table below provides summary financial information for UNS Electric.

	2009		2008		2007
	-Millions of Dollars-
Retail Electric Revenues	$	180	$	183	$	165
Wholesale Electric Revenues		5		10		—
Other Revenues		2		2		4
Total Operating Revenues		187		195		169
Purchased Energy and Fuel Expense		128		143		118
Other Operations and Maintenance Expense		25		22		23
Depreciation and Amortization		14		14		13
Taxes other than Income Taxes		4		4		3
Total Other Operating Expenses		171		183		157
Operating Income		16		12		12
Total Other Income		1		1		2
Total Interest Expense		7		7		6
Income Tax Expense		4		2		3
Net Income	$	6	$	4	$	5

The table below shows UNS Electric’s kWh sales and revenues for 2009, 2008 and 2007.

	Electric Sales - Millions of kWh									Electric Revenues - Millions of Dollars
					09-08									09-08
	2009		2008		%Chng			2007		2009		2008		%Chng			2007
Electric Retail Sales:
Residential		814		822		(1.1	%)		854	$	82	$	92		(10.6	%)	$	86
Commercial		608		620		(1.9	%)		627		63		70		(9.9	%)		64
Industrial		197		189		4.2	%		199		17		17		(2.2	%)		15
Mining		163		30	NM				—		12		3	NM				—
Other		2		2		(0.8	%)		2		—		—		—			—
Total Electric Retail Sales		1,784		1,663		7.3	%		1,682	$	174	$	182		(4.4	%)	$	165
REST & DSM		—		—		—			—		6		1	NM				—
Wholesale Electric Sales		154		153		(0.5	%)		—		5		10	NM				—
Total Electric Sales		1,938		1,816		6.7	%		1,682	$	185	$	193		(4.0	%)	$	165

In 2009, retail kWh sales increased by 7.3% compared to 2008. The increase is due primarily to increased usage by a new copper mining customer in UNS Electric’s service area. Excluding mining sales, UNS Electric’s retail kWh sales decreased by 0.8% compared with last year as a result of weak economic conditions.

UNS Electric’s retail customer base did not increase during 2009. As of December 31, 2009, UNS Electric had approximately 90,000 retail customers, which is comparable with the prior year.

Wholesale revenues decreased by $5 million in 2009 due to lower market prices for wholesale power. Wholesale sales are made primarily from contract and resource capacity agreements that became effective June 1, 2008, subsequent to the expiration of UNS Electric’s full requirements contract with Pinnacle West Marketing and Trading (PWMT). All revenues from wholesales sales are credited against costs recovered through UNS Electric’s PPFAC.

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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 2003 UNS Electric filed with the ACC a plan to open its service territories to retail competition by December 31, 2003. 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 Rules, we are unable to predict when and how the ACC will address this plan. SeeItem 1. — Business, TEP, Rates and Regulation, Retail Electric Competition Rules,for more information.

Rates

2008 UNS Electric Rate Order

In May 2008, the ACC issued an order authorizing a 2.5%, or $4 million base rate increase effective June 1, 2008. UNS Electric had requested a 5.5%, or $8.5 million base rate increase.

Purchased Power and Fuel Adjustment Clause

As part of the 2008 ACC order, a new PPFAC mechanism took effect on June 1, 2008. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected/credited from/to customers. The ACC approved a cap on the PPFAC forward component of 1.73 cents per kWh, resulting in total fuel and purchased power recovery of approximately 8.7 cents per kWh, an increase of approximately 1.7 cents per kWh in UNS Electric’s average retail rate. On April 1, 2009, UNS Electric filed a request with the ACC for a PPFAC rate that credits 1.06 cents per kWh. This results in a total fuel and purchased power recovery of approximately 6.06 cents per kWh that became effective on June 1, 2009.

2009 General Rate Case Filing

On April 30, 2009, UNS Electric filed a rate case application with the ACC seeking a base rate increase of 7.4% or $13.5 million. UNS Electric’s filing also included a proposal to acquire, and put into its rate base, BMGS, the gas-fired facility in UNS Electric’s service territory that is owned and operated by UED. The proposed acquisition and inclusion of BMGS in rate base would not impact the amount of the total rate increase requested by UNS Electric. The ACC staff testimony recommended a base revenue increase of approximately $8 million. A hearing before an ACC administrative law judge concluded in February 2010.

Electric Energy Efficiency Standards

In December 2009, the ACC established a process to adopt new Electric Energy Efficiency Standards (EE Standards) designed to require UNS Electric, TEP and other affected utilities to implement DSM programs, only to the extent that they are cost effective.  The proposed EE Standards target cost effective total kWh savings in 2011 of 1.25% and ramping up each year to reach a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.  Savings from Direct Load Control programs, previously implemented DSM programs and from a portion of energy efficient building codes may be counted towards meeting the target.  The proposed EE Standards provide for recovery of costs incurred to implement cost effective DSM programs. UNS Electric’s DSM programs and rates charged to customers for such programs are subject to ACC approval. If the ACC approves EE Standards, they must be certified by the Arizona Attorney General before taking affect. 

Purchased Power Agreement

In May 2008, UNS Electric and UED entered into a Power Purchase and Sales Agreement (PPA) under which UED sells all the output of the 90 MW gas-fired Black Mountain Generating Station (BMGS) to UNS Electric over a five-year term. The PPA is a tolling arrangement in which UNS Electric takes operational control of BMGS and assumes all risk of operation and maintenance costs, including fuel. Under the terms of the PPA, UNS Electric pays UED a capacity charge. The costs associated with the PPA are recoverable through UNS Electric’s PPFAC.

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Renewable Energy Standard and Tariff

UNS Electric began implementing its ACC approved REST plan on June 1, 2008. In 2009 and 2008, UNS Electric collected $5 million and $3 million in REST surcharges, of which $6 million and $1 million were expensed for REST projects, respectively. Any surcharge collections above or below the amount of renewable expenditures will be deferred and reflected in UNS Electric’s financial statements as a regulatory liability or asset. In 2010, UNS Electric expects to collect $8 million from customers through the REST surcharge. REST implementation plans and the associated surcharge must be submitted annually to the ACC for review and approval. For more information, seeItem 1. Business, UNS Electric, Renewable, Energy Standard and Tariff, above.

Fair Value Measurements

UNS Electric adopted fair value measurements on January 1, 2008. SeeTucson Electric Power,Factors Affecting Results of Operations, above, for more information about fair value measurements.

The following table sets forth, by level within the fair value hierarchy, UNS Electric’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

UNS Electric
December 31, 2009
- - Millions of Dollars -

	Quoted Prices in
	Active Markets		Significant Other			Significant
	for Identical		Observable			Unobservable
	Assets (Level 1)		Inputs (Level 2)			Inputs (Level 3)			Total
Cash Equivalents(1)	$	9	$	—		$	—		$	9
Energy Contracts(2)		—		(3	)		(9	)		(12	)
Total	$	9	$	(3	)	$	(9	)	$	(3	)

(1)

Cash Equivalents are based on observable market prices and are comprised of the fair value of money market funds and certificates of deposit.

(2)

Energy contracts include gas swap agreements (Level 2), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to take advantage of favorable market conditions and reduce exposure to energy price risk. The amounts include current and non-current assets and are net of current and non-current liabilities. The level 3 valuation techniques are described below.

UNS Electric recorded in 2009, net unrealized gains of $7 million in net Regulatory Assets due to the change in the fair value of forward power purchase contracts classified as Level 3 in the fair value hierarchy. These changes in fair value were primarily due to older fixed price contracts settling during the year and entering into new fixed price forward power contracts at lower prices.

UNS Electric’s Level 3 derivatives include certain energy contracts where published prices are not readily available. These include contracts for delivery periods during non-standard time blocks, contracts for delivery during only a few months of a given year when prices are quoted only for the annual average, or contracts for delivery at illiquid delivery points. In these cases, UNS Electric applies certain management assumptions to value such contracts. These assumptions include applying percentage multipliers to value non-standard time blocks, applying historical price curve relationships to calendar year quotes, and including adjustments for transmission and line losses to value contracts at illiquid delivery points. We also consider the impact of counterparty credit risk using current and historical default and recovery rates as well as our own credit risk using credit default swap data. UNS Electric reviews these assumptions on a quarterly basis.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

In 2009, UNS Electric’s capital expenditures were $28 million. UNS Electric expects internal cash flows to fund a portion of its construction expenditures. Additional sources of funding future capital expenditures could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy. In April 2007, UniSource Energy contributed $10 million of capital to UNS Electric.

UNS Electric implemented an average base rate increase of approximately 2.5% in June 2008, however the increase does not provide sufficient cash flow to cover UNS Electric’s higher costs and fund all of its capital expenditures. UNS Electric may need to rely more heavily on external funding sources for capital expenditures until it receives a decision in the rate case filed in April 2009. SeeUniSource Energy Consolidated,Outlook and Strategies, Economic Conditions and UniSource Energy Consolidated, Liquidity and Capital Resources, Liquidity, Access to Revolving Credit Facilities, above for more information regarding the potential impact of current financial market conditions.

In August 2008, UNS Electric issued $100 million of unsecured debt. A portion of the proceeds was used to redeem $60 million of notes that matured on August 11, 2008. The remaining proceeds were used to repay outstanding borrowings by UNS Electric under the UNS Gas/UNS Electric Revolver and for general corporate purposes. SeeSenior Unsecured Notes,below.

Operating Cash Flow and Capital Expenditures

The table below provides summary cash flow information for UNS Electric.

	2009			2008			2007
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$	37		$	14		$	22
Investing Activities		(28	)		(30	)		(36	)
Financing Activities		(8	)		22			12
Net Increase (Decrease) in Cash		1			6			(2	)
Beginning Cash		9			3			5
Ending Cash		10			9			3

Operating cash flows increased in 2009 because of the higher mining kWh sales, an increase in base rates, and the PPFAC charge that went into effect on June 1, 2008.

Forecasted capital expenditures for UNS Electric are as follows:

	2010		2011		2012		2013		2014
	- Millions of Dollars -
UNS Electric	$	26	$	25	$	31	$	13	$	16

UNS Gas/UNS Electric Revolver

SeeUNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolverabove 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, to fund a portion of its capital expenditures or to issue letters of credit to provide credit enhancement for its energy procurement and hedging activities. At February 23, 2010, UNS Electric had $12 million outstanding under the UNS Gas/UNS Electric Revolver.

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Senior Unsecured Notes

UNS Electric has $100 million of senior unsecured notes outstanding, consisting of $50 million of 6.50% notes due in 2015 and $50 million of 7.10% notes due August 2023. The notes are guaranteed by UES. The note purchase agreement for UNS Electric contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness. As of December 31, 2009, UNS Electric was in compliance with the terms of its note purchase agreement.

UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.

Contractual Obligations

UNS Electric Power Supply and Transmission Contracts

UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.

UNS Electric’s power purchase contracts and risk management activities are subject to master agreements whereby UNS Electric may be required to post margin due to changes in contract values or if there has been a material change in UNS Electric’s creditworthiness, or exposures exceeding credit limits provided to UNS Electric. As of December 31, 2009, UNS Electric had posted $11 million of such credit enhancements in the form of letters of credit.

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 2017 and 2011.

The following table displays UNS Electric’s contractual obligations as of December 31, 2009 by maturity and by type of obligation.

UNS Electric’s Contractual Obligations
- -Millions of Dollars-

											2015
Payment Due in Years											and
Ending December 31,	2010		2011		2012		2013		2014		after		Total
Long Term Debt
Principal	$	—	$	—	$	—	$	—	$	—	$	100	$	100
Interest		7		7		7		7		7		34		69
Purchase Obligations:
Purchased Power		67		23		14		47		—		—		151
Transmission		2		2		1		—		—		—		5
Pension & Other Post Retirement Obligations		1		—		—		—		—		—		1
Total Contractual Cash Obligations	$	77	$	32	$	22	$	54	$	7	$	134	$	326

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Dividends on Common Stock

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. As of December 31, 2009, UNS Electric was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above. As of December 31, 2009, UNS Electric has not paid dividends to UniSource Energy. UNS Electric’s ability to pay dividends will depend on the outcome of the rate case filed in April 2009, the need for capital expenditures and various other factors.

OTHER NON-REPORTABLE BUSINESS SEGMENTS

RESULTS OF OPERATIONS

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

	2009			2008			2007
	- Millions of Dollars -
UniSource Energy Parent Company	$	(6	)	$	(5	)	$	(5	)
Millennium		3			—			1
UED		5			3			—
Total Other Net Loss	$	2		$	(2	)	$	(4	)

UniSource Energy Parent Company

UniSource Energy parent company expenses include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes and the UniSource Credit Agreement. In 2009, UniSource Energy had capital expenditures of $8 million related to the purchase of land and site development to construct a new headquarters building.

UED

UED completed the construction of the 90 MW BMGS in Kingman, Arizona in May 2008. UED sells the output of BMGS to UNS Electric through a PPA. SeeUNS Electric, Factors Affecting Results of Operation, Purchased Power Agreement, above.

In December 2008, UniSource Energy contributed $59 million of equity to UED by canceling an intercompany promissory note in the amount of $59 million. Borrowings under the promissory note were used to finance the development of BMGS.

In March 2009, UED entered into a 364-day $30 million term loan facility that is guaranteed by UniSource Energy and is secured by substantially all of the assets of UED, which primarily consist of BMGS and a mortgage on UED’s leasehold interest in the real property on which BMGS is located. UED used the loan proceeds to pay a $30 million dividend to UniSource Energy, which in turn made a capital contribution to TEP. UED has the option of paying interest at LIBOR plus 3% or an alternate base rate plus 2%. As of December 31, 2009, UED owed $26 million under this term loan facility. In February 2010, UED made an additional borrowing under the facility, resulting in $35 million of outstanding debt, and extended the maturity of the debt for two years to March 2012. The loan proceeds were used to pay a $9 million dividend to UniSource Energy.

In 2009 and 2008, UED recorded after-tax income of $5 million and $3 million, respectively, related to the operation of BMGS.

In 2008, UED made distributions to UniSource Energy of less than $1 million. The $30 million dividend paid in 2009 represented a return of capital distribution, as did $4 million of the $9 million dividends paid in February 2010.

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FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

Millennium is in the process of exiting its remaining investments which may yield gains or losses. At December 31, 2009, Millennium’s key assets included: a $15 million note receivable related to the sale of Sabinas; a $10 million investment balance in various energy technology projects; and $7 million in cash.

In June 2009, Millennium finalized a sale of its 50% interest in Sabinas to Mimosa. The terms called for an upfront $5 million payment to Millennium which was received in January 2009. Other key terms of the transaction include a three year, 6% interest-bearing, collateralized $15 million note from Mimosa. In June 2009, Millennium recorded a $6 million pre-tax gain on the sale.

Millennium made $3 million in dividend payments to UniSource Energy in 2009, $25 million in 2008 and $15 million in 2007. In January 2010, Millennium made a $4 million dividend payment to UniSource Energy. All of these dividends represented return of capital distributions. Millennium’s remaining commitment for all of its investments combined is less than $1 million, which is expected to be funded over the next one to two years.

The following table sets forth, by level within the fair value hierarchy, Millennium’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

December 31, 2009
- - Millions of Dollars -

	Quoted Prices in
	Active Markets		Significant Other		Significant
	for Identical		Observable		Unobservable
	Assets (Level 1)		Inputs (Level 2)		Inputs (Level 3)		Total
Investments	$	4	$	—	$	6	$	10

Level 1 Investments represent the fair value of money market funds based on observable market prices. Level 3 Investments represent Millennium’s equity investment in unregulated businesses that, in the absence of readily ascertainable market values, is based on the investment partners’ valuations.

CRITICAL ACCOUNTING POLICIES

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 Policies 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 Policies below. Other significant accounting policies and recently issued accounting standards are discussed in Note 1 ofNotes 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 require special accounting treatment for regulated companies to show the effect of regulation. For example, in setting retail rates for TEP, UNS Gas and UNS Electric, 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, regulatory accounting 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.

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TEP

Upon approval by the ACC of a settlement agreement in November 1999, TEP discontinued application of regulatory accounting for its generation operations. Beginning in December 2008, as a result of the 2008 TEP rate order, TEP reapplied regulatory accounting to its generation related operations. Throughout this period, TEP continued to apply regulatory accounting to its transmission and distribution operations.

TEP’s generation, transmission and distribution regulatory liabilities, net of regulatory assets, totaled $42 million at December 31, 2009. If TEP stopped applying regulatory accounting 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. TEP regularly assesses whether it can continue to apply regulatory accounting to its cost-based rate regulated operations. Expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets.

UNS Gas and UNS Electric

UNS Gas’s regulatory liabilities, net of regulatory assets, totaled $19 million at December 31, 2009. UNS Electric’s regulatory liabilities, net of regulatory assets, totaled $4 million at December 31, 2009. UNS Gas and UNS Electric regularly assess whether they can continue to apply regulatory accounting to their cost-based rate regulated operations. If UNS Gas and UNS Electric stopped applying regulatory accounting 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. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets.

Accounting for Asset Retirement Obligations

TEP

TEP is required 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 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. TEP incurs legal obligations as a result of environmental and other governmental regulations, contractual agreements and other factors. To estimate the liability, management must use significant judgment and assumptions in: determining whether a legal obligation exists to remove assets; estimating the probability of a future event for a conditional obligation; estimating the fair value of the cost of removal; estimating when final removal will occur; and estimating the credit-adjusted risk-free interest rates to be used to discount the 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.

The initial liability is recorded 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 of the long-lived asset is depreciated over the useful life of the related asset. Upon settlement of the liability, TEP will pay the recorded liability or incur a gain or loss if the actual costs differ from the recorded amount. If TEP retires any asset at the end of its useful life, without a legal obligation to do so, TEP will record retirement costs at that time as incurred or accrued.

TEP has identified legal obligations to retire generation plant assets specified in land leases for its jointly-owned Navajo and Four Corners Generating Stations. The land on which these stations reside is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. TEP also has certain environmental obligations at the San Juan Generating Station. TEP has estimated that its share of the cost to remove the Navajo and Four Corners facilities and settle the San Juan environmental obligations will be approximately $40 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 natural gas-fired Luna Energy Facility (Luna) in Southern New Mexico. Luna is a 570-MW combined cycle plant and was placed into commercial operation in April 2006. SeeItem 1. — Business, TEP, Generating and Other Resources, Future Generating Resources. 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 of the obligations will be approximately $2 million at the date of retirement.

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As of December 31, 2009, TEP had a liability of $5 million associated with its final asset retirement obligations.

TEP has various transmission and distribution lines that operate under leases and rights-of-way that contain end dates and restrictive 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 such there are no legal obligations that require application of the accounting requirements for asset retirement obligations. Nevertheless, included in the revenue requirement underlying the Company’s electric service rates is a component of depreciation expense intended to enable TEP to accrue for such future costs of retiring assets for which no legal obligations exists. The accumulated balance of such accruals, less actual removal costs incurred, net of salvage proceeds realized, is reported as a regulatory liability. As of December 31, 2009, such liability is reported as $163 million.

UNS Gas and UNS Electric

UNS Gas and UNS Electric have various transmission and distribution lines that operate under land leases and rights-of-way that contain end dates and restorative clauses. UNS Gas and UNS Electric operate their 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, UNS Gas and UNS Electric are not recognizing the cost of final removal of the transmission and distribution lines in the financial statements.

For the net cost of removal for interim retirements from transmission, distribution and general plant, UNS Gas accrued $20 million as of December 31, 2009. UNS Electric accrued $12 million as of December 31, 2009. The amounts are recorded as regulatory liabilities.

Pension and Other Postretirement Benefit Plan Assumptions

We record plan assets, obligations, and expenses related to pension and other postretirement benefit plans based on actuarial valuations, which 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 is required to recognize the underfunded status of its defined benefit pension and other postretirement plans as a liability. The underfunded status is measured as the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated postretirement benefit obligation for other postretirement benefit plans. We expect volatility in the liability recognized in the balance sheet in future years as the funded status of our plans can change significantly due to discount rate changes and investment and actuarial experience. TEP recorded the underfunded amount at December 31, 2009 of $58 million for its pension obligations and $69 million for its other post-retirement obligations as a liability and a regulatory asset to reflect expected recovery of pension and other post-retirement costs through rates.

TEP is required to measure the funded status of its pension plans as of the date of its year-end balance sheet, beginning with the year ended December 31, 2008. On January 1, 2008, TEP recorded a reduction to retained earnings of less than $1 million to move the measurement date from December 1 to December 31 for all of its pension and other postretirement plans.

TEP discounted its future pension plan obligations at 6.3% at December 31, 2009 and its other postretirement plan obligations at a rate of 6%. TEP determines the discount rate annually based on the rates currently available on high-quality, non-callable, long-term bonds. TEP looks to bonds that receive one of the two highest ratings given by a recognized rating agency whose future cash flows match the timing and amount of expected future benefit payments. For TEP’s pension plans, a 25-basis point change in the discount rate would increase or decrease the projected benefit obligation (PBO) by approximately $7 million and the 2010 plan expense by $1 million. For TEP’s other postretirement benefit plan, 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 impact plan expense by less than $1 million.

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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 7.5% at December 31, 2009. 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 decreases as the expected rate of return on plan assets increases. A 25-basis point change in the expected return on plan assets would impact pension expense in 2010 by less than $1 million.

TEP used a current year health care cost trend rate of 7.9% in valuing its postretirement benefit obligation at December 31, 2009. 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 one-percentage point change in assumed health care cost trend rates would change the postretirement benefit obligation by approximately $5 million and the related plan expense in 2010 by less than $1 million.

TEP will record pension expense of approximately $12 million and other postretirement benefit expense of $5 million ratably through 2010, of which approximately $2 million will be capitalized. TEP expects to make pension plan contributions of $20 million in 2010. In 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA) to fund its other postretirement benefit plan. TEP expects to make benefit payments to retirees under the postretirement benefit plan of approximately $5 million in 2010 and contributions to the VEBA trust of $1 million in 2010.

UNS Gas and UNS Electric

UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 6.3% at December 31, 2009. For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2010 pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2010, of which less than $1 million will be capitalized. UNS Gas and UNS Electric expects to make combined pension plan contributions of $2 million in 2010.

UNS Gas and UNS Electric discounted their other postretirement plan obligations using a rate of 6% at December 31, 2009. UNS Gas and UNS Electric will record postretirement medical benefit expense and make benefit payments to retirees under the postretirement benefit plan of less than $1 million in 2010.

Accounting for Derivative Instruments, Trading Activities and Hedging Activities

Commodity Derivative Contracts

TEP, UNS Electric and UNS Gas enter 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. TEP and UNS Gas also enter into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted summer gas purchases.

As a result of the 2008 TEP Rate Order, which permits recovery in the PPFAC of hedging transactions, unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or regulatory liability. UNS Electric and UNS Gas are also permitted to record unrealized gains and losses on commodity derivative contracts as either a regulatory asset or regulatory liability. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC or PGA mechanisms.

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Interest Rate Swaps

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to LIBOR on the Springerville Common Facilities Lease. TEP entered into swaps that had the effect of converting approximately $30 million and $35 million of variable rate lease debt payments for the Springerville Common Facilities Lease to a fixed rate from May 2009 through July 1, 2014, and June 2006 through January 2, 2020, respectively. In August 2009, TEP entered into a swap that had the effect of converting $50 million of variable rate industrial development bonds to a fixed rate from September 2009 through September 2014. At December 31, 2009, the fair value of these interest rate swaps is a liability of $6 million.

Commodity Cash Flow Hedge

TEP hedges the cash flow risk associated with a six-year power wholesale supply agreement using a six-year power purchase swap agreement. Unrealized gains and losses are recorded in Accumulated Other Comprehensive Income (AOCI). At December 31, 2009, the fair value of this contract is a liability of $1 million.

The market prices used to determine fair values for TEP, UNS Electric and UNS Gas’ derivative instruments at December 31, 2009, are estimated based on various factors including broker quotes, exchange prices, over the counter prices and time value.

TEP, UNS Gas and UNS Electric manage 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.

SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Commodity Price Risk.

Unbilled Revenue — TEP, UNS Gas and UNS Electric

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, UNS Gas and UNS Electric

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

In January 2010, TEP obtained an updated depreciation study which indicated that its transmission assets depreciable lives should be extended. As a result, TEP adopted new transmission depreciation rates effective January 2010 which will have the effect of reducing depreciation expense by approximately $14 million annually.

Deferred Tax Valuation

Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. This difference is accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using the income tax rates in effect on the balance sheet date.

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Federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises.

Prior to 1990, we flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on the income tax return. Income Taxes Recoverable Through Future Rates on the balance sheet reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 2.

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income and deductions as reported in the consolidated tax return.

UniSource Energy and TEP record net interest expense associated with uncertain tax positions as Interest Expense in the income statements. No income tax penalties have been accrued.

At December 31, 2009, TEP had no valuation allowance. SeeNote 9 of Notes to Consolidated Financial Statements.

As of December 31, 2009, UniSource Energy’s deferred income tax assets include $8 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 these deferred tax assets.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The following recently issued accounting standards are not yet reflected in the UniSource Energy and TEP financial statements:

• The FASB issued authoritative guidance for transfers of financial assets that clarify and change the criteria for a transfer to be accounted for as a sale, change the amount of a recognized gain/loss on a sale when beneficial interests are received by the transferor, and requires extensive disclosures. This standard is effective for interim and annual periods beginning January 1, 2010. To date, we have not participated in any transfers to which this guidance is applicable.

• The FASB issued authoritative guidance for variable interest entities requiring an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. This standard did not have a material impact on our financial statements on adoption on January 1, 2010.

• The FASB issued authoritative guidance for multiple deliverable revenue arrangements that provides another alternative for determining the selling price of deliverables and eliminates the residual method of allocating consideration. In addition, this pronouncement requires expanded Quantitative and Qualitative disclosures and is effective for revenue arrangements entered into after January 1, 2011. We are evaluating the impact of this pronouncement.

• The FASB issued amendments that require some new disclosures and clarify some existing disclosure requirements about fair value measurements. The amendments are effective for interim and annual reporting periods beginning January 1, 2010, except for disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in level 3 fair value measurements, which are effective for interim and annual reporting periods beginning January 1, 2011. We are evaluating the impact of these new and revised disclosures 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 Item 1A. Risk Factors, Item 7. Management’s Financial Discussion and Analysis, and other parts of this report: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of the company’s pension and other postretirement benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; and performance of TEP’s generating plants.

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 SafeHarbor for Forward-Looking Statements, above.

Risk Management Committee

We have a Risk Management Committee responsible for the oversight of commodity price risk and credit risk related to the wholesale energy marketing activities of TEP and the fuel and power procurement activities at TEP, UNS Gas and UNS Electric. 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 generation operations departments of UniSource Energy. To limit TEP, UNS Gas and UNS Electric’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, UNS Gas and UNS Electric’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.

Interest Rate Risk

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. At December 31, 2009 and December 31, 2008, TEP had $459 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest rate payable under the indentures for these bonds is 10% on the 2008 Pima B Bonds and 20% on the other $329 million in IDBs. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 0.41% in 2009 and 2.11% in 2008. The average weekly interest rate ranged from 0.25% to 0.79% in 2009 and 0.55% to 8.09% during 2008. The peak average interest rate of 8.09% occurred in September 2008 when the short-term debt markets began to experience significant disruptions following the bankruptcy filing of Lehman Brothers Holdings, Inc. and the deterioration of creditworthiness of other large financial institutions. Although short-term markets were less volatile in 2009, TEP may still be subject to volatility in its tax-exempt variable rate debt. A 100 basis point increase in average interest rates on this debt, over a twelve month period, would result in a decrease in TEP’s pre-tax net income of approximately $5 million.

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To reduce its exposure to variable interest rate risk, in August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate industrial revenue bonds to a fixed rate of 2.4% from September 2009 through September 2014. To further reduce its variable interest rate exposure, in January 2010, TEP converted the interest rate on its $130 million principal amount of 2008 Pima B Bonds from a variable rate to a fixed rate of 5.75% through maturity in 2029.

At December 31, 2009 and 2008, TEP’s debt also included variable rate lease debt totaling $65 million related to its Springerville Common Facilities Leases. The notes underlying the leases mature in June 2017 and January 2020. Interest is payable at six-month LIBOR plus an applicable spread. The applicable spread was 1.625% at December 31, 2009 and 1.5% at December 31, 2008.

In June 2006 and May 2009, TEP entered into interest rate swaps to hedge the floating interest rate risk associated with the Springerville Common Facilities lease debt. The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

Outstanding at Dec. 31, 2009	Fixed Rate			LIBOR Spread
$35 million		5.77	%		1.625	%
$23 million		3.18	%		1.625	%
$7 million		3.32	%		1.625	%

To adjust the value of TEP’s interest rate swaps, classified as a cash flow hedge, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains (losses):

	2009		2008			2007
	- In Millions-
Unrealized Gains (Losses)	$	1	$	(5	)	$	(1	)

UniSource Energy, TEP, UNS Gas and UNS Electric are also subject to interest rate risk resulting from changes in interest rates on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on the basis of a spread over LIBOR or an Alternate Base Rate. With the recent disruptions in the financial markets, the spread between LIBOR and other similar maturity short-term rates, such as U.S. Treasury securities, has been significantly higher than historical relationships. As a result, UniSource Energy, TEP, UNS Gas and UNS Electric may experience significant volatility in the rates paid on LIBOR borrowings under their revolving credit facilities.

Marketable Securities Risk

UniSource Energy has a short-term investment policy which governs the investment of excess cash balances by UniSource Energy and its subsidiaries. We review this policy periodically in response to market conditions to adjust, if necessary, the maturities and concentrations by investment type and issuer in the investment portfolio. As of December 31, 2009, UniSource Energy’s short-term investments consisted of highly-rated and liquid money market funds, commercial paper, and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the Balance Sheet.

At December 31, 2009 and 2008, TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $132 million and $127 million, respectively. At December 31, 2009 and 2008, the fair value exceeded the carrying value by $8 million and $17 million, respectively. These securities represent TEP’s investments in lease debt and equity 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.

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Commodity Price Risk

TEP

TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, coal and emission allowances. Beginning January 1, 2009, this risk is mitigated through a PPFAC mechanism which fully recovers the actual retail fuel and purchased power costs incurred on a timely basis from TEP’s retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, TEP is exposed to the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference. In 2009, the ACC approved a PPFAC rate of 0.18 cents per kWh, resulting in total fuel and purchased power recovery of approximately 3.08 cents per kWh.

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 physical position in the third quarter and must have owned generation backing up all physical 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.

TEP’s risk management policies also allow for financial purchases and sales of energy subject to specified risk parameters established and monitored by the Risk Management Committee. These include financial trades in a futures account on an exchange, with the intent of optimizing market opportunities.

The majority of TEP’s forward contracts are considered to be “normal purchases and sales” of electric energy and are therefore not accounted for as derivatives. 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. 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.

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.

As required by fair value accounting rules, for the year ended December 31, 2009, TEP considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for TEP was less than $0.5 million at December 31, 2009.

K-79

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, TEP recorded the following net unrealized gains (losses):

	2009		2008			2007
	- In Millions-
Unrealized Gains (Losses)	$	11	$	(19	)	$	—

The chart below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts.

Unrealized Gain (Loss) of TEP’s
Hedging and Trading Activities
- - Millions of Dollars -

										Total
	Maturity 0–6			Maturity 6–12			Maturity			Unrealized
Source of Fair Value At Dec. 31, 2009	months			months			over 1 yr.			Gain (Loss)
Prices actively quoted	$	(1	)	$	(3	)	$	(1	)	$	(5	)
Prices based on models and other valuation methods		—			—			(4	)		(4	)
Total	$	(1	)	$	(3	)	$	(5	)	$	(9	)

Sensitivity Analysis of Derivatives

TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its derivative forward contracts. Beginning in December 2008, as a result of the 2008 TEP Rate Order, which permits the recovery of prudent costs associated with hedging contracts through the PPFAC, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. The chart below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%.

	- Millions of Dollars -
Change in Market Price As of December 31, 2009	10% Increase		10% Decrease
Non-Cash Flow Hedges
Forward power sales and purchase contracts	$	—	$	—
Gas swap agreements		3		(3	)
Cash Flow Hedges
Forward power sales and purchase contracts	$	1	$	(1	)
Gas swap agreements		—		—

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 and 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 from 2011 through 2020, the coal price will be determined by the cost of Powder River Basin coal delivered to Springerville 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 in 2010, the initial contract expiration date, and $14 million from 2011 through 2020. TEP’s coal transportation contract at Springerville runs through June of 2011. TEP estimates minimum annual payments under this contract to be $13 million in 2010 and $7 million in 2011.

TEP does not have a long-term coal supply contract from Sundt Unit 4, however it has adequate coal inventory through 2010. Coal burned at Sundt Unit 4 represents less than 10% of TEP’s total coal consumption. The long-term rail contract for Sundt Unit 4 is in effect until the earliest of 2015, the remaining life of Sundt Unit 4 or the life of the coal mine. 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.

K-80

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.

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 $23 million for the next five years. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual Obligations and Note 4 of Notes to Consolidated Financial Statements — Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.

UNS Gas

UNS Gas is subject to commodity price risk, primarily from the changes in the price of natural gas purchased for its 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 or entering into financial gas swaps for a portion of its projected gas needs under its Price Stabilization Plan. UNS Gas purchases at least 45% of its estimated gas needs in this manner.

As required by fair value accounting rules, for the year ended December 31, 2009, UNS Gas considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Gas was less than $0.5 million at December 31, 2009.

For UNS Gas’ forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $3 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a regulatory asset of $3 million.

UNS Electric

UNS Electric is exposed to commodity price risk from changes in the price for electricity and natural gas. This risk is mitigated through a PPFAC mechanism which fully recovers the costs incurred on a timely basis. As part of the May 2008 ACC order, a new PPFAC mechanism took effect on June 1, 2008. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, UNS Electric is exposed to the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference. The ACC approved a PPFAC rate of 1.73 cents per kWh, resulting in total fuel and purchased power recovery of approximately 8.7 cents per kWh, an increase of approximately 1.7 cents per kWh in UNS Electric’s average retail rate.

UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. UNS Electric estimates its future minimum payments under these contracts to be $67 million in 2010, $23 million in 2011, $14 million in 2012, and $47 million in 2013, based on natural gas prices at the date of the contracts.

Because a portion of the costs under these contracts will vary from period to period based on the market price of gas, the PPFAC, as currently structured, may not provide recovery of the costs incurred under these new contracts on a timely basis.

For UNS Electric’s forward power sales and purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $11 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a regulatory asset of $11 million.

UNS Electric hedges a portion of its natural gas exposure from gas-indexed purchase power agreements with fixed price contracts. In addition, UNS Electric hedges a portion of its anticipated natural gas exposure from plant fuel. UNS Electric currently has approximately 53% of this aggregate summer exposure hedged for the summer of 2010. UNS Electric will obtain its remaining gas and purchased power needs through a combination of additional forward purchases and purchases in the short-term and spot markets.

K-81

As required by fair value accounting rules, for the year ended December 31, 2009, UNS Electric considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Electric was less than $0.5 million at December 31, 2009.

For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $1 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a regulatory asset of $1 million.

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 standard agreements which allow 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. A positive number means that we are exposed to the creditworthiness of our counterparties. If exposure exceeds credit limits or contractual collateral thresholds, we may request that a counterparty provide credit enhancement in the form of cash collateral or a letter of credit. Conversely, a negative exposure means that a counterparty is exposed to the creditworthiness of TEP, UNS Gas or UNS Electric. If such exposure exceeds credit limits or collateral thresholds, we may be required to post collateral in the form of cash or letters of credit.

During the last three years, financial institution counterparties have become active participants in the wholesale energy markets. TEP, UNS Electric and UNS Gas have each entered into short-term and long-term transactions with several financial institution counterparties with terms of one month through five years. Due to the recent turmoil in the financial and credit markets, we have been closely monitoring our transactions with financial institutions. As of December 31, 2009, the combined credit exposure to TEP, UNS Electric and UNS Gas from financial institution counterparties was less than $1 million.

As of December 31, 2009, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $20 million, including $7 million of inter-company exposure to UNS Electric. TEP had 2 non-investment grade counterparties with exposure of greater than 10% of its total credit exposure, totaling approximately $6 million. TEP’s total exposure to non-investment grade counterparties was $7 million.

TEP maintains a margin account with a broker to support certain risk management and trading activities. At December 31, 2009, TEP had less than $1 million in that margin account. At December 31, 2009, TEP had $1 million in credit enhancements posted with counterparties, and did not hold any collateral from its counterparties.

UNS Gas is subject to credit risk from non-performance by its supply and hedging counterparties to the extent that these contracts have a mark-to-market value in favor of UNS Gas. As of December 31, 2009, UNS Gas had purchased under fixed price contracts approximately 35% of its expected consumption for the 2010/2011 winter season. At December 31, 2009, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts.As of December 31, 2009, UNS Gas had posted $2 million in cash collateral and no letters of credit as credit enhancements with its counterparties, and did not hold any collateral from counterparties.

UNS Electric enters into energy purchase agreements as well as gas hedging contracts to hedge the risk in its gas-indexed power purchase agreements. To the extent that such contracts have a positive mark-to-market value, UNS Electric is exposed to credit risk under those contracts. At December 31, 2009, UNS Electric had no credit exposure under such contracts. As of December 31, 2009, UNS Electric had posted $11 million in letters of credit and no cash collateral as credit enhancements with its counterparties and had not collected any collateral margin from its counterparties.

K-82

ITEM 8. — CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

UniSource Energy — 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, 2009. 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, 2009, UniSource Energy Corporation’s internal control over financial reporting was effective.

Tucson Electric Power Company — Management’s Report on Internal Controls Over Financial Reporting

Tucson Electric Power Company’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 Tucson Electric Power Company’s internal control over financial reporting as of December 31, 2009. 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, 2009, Tucson Electric Power Company’s internal control over financial reporting was effective.

This annual report does not include an attestation report of Tucson Electric Power Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Tucson Electric Power Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit Tucson Electric Power Company to provide only management’s report in this annual report.

K-83

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of
UniSource Energy Corporation:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of UniSource Energy Corporation and its subsidiaries at December 31, 2009 and December 31, 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in Note 9 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

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.

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.

/s/ PricewaterhouseCoopers LLPPricewaterhouseCoopers LLP

Phoenix, Arizona

February 25, 2010

K-84

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), present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s 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 9 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

February 25, 2010

K-85

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2009			2008			2007
	- Thousands of Dollars -
	(Except Per Share Amounts)
Operating Revenues
Electric Retail Sales	$	1,047,619		$	988,612		$	983,993
Provision for Rate Refunds — CTC Revenue		—			(58,092	)		—
Net Electric Retail Sales		1,047,619			930,520			983,993
Electric Wholesale Sales		128,627			236,300			196,233
California Power Exchange (CPX) Provision for Wholesale Refunds		(4,172	)		—			—
Gas Revenue		144,609			163,977			148,598
Other Revenues		77,741			66,714			52,549
Total Operating Revenues		1,394,424			1,397,511			1,381,373
Operating Expenses
Fuel		298,655			299,987			297,037
Purchased Energy		294,584			442,210			347,377
Transmission		10,181			19,214			15,648
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		(17,091	)		(10,975	)		5,259
Total Fuel and Purchased Energy		586,329			750,436			665,321
Other Operations and Maintenance		333,887			295,658			242,264
Depreciation and Amortization		176,018			147,690			140,638
Amortization of Transition Recovery Asset		—			23,945			77,681
Taxes Other Than Income Taxes		45,857			39,339			47,836
Total Operating Expenses		1,142,091			1,257,068			1,173,740
Operating Income		252,333			140,443			207,633
Other Income (Deductions)
Interest Income		12,072			11,011			18,828
Other Income		18,063			7,838			7,622
Other Expense		(5,292	)		(9,286	)		(4,380	)
Total Other Income (Deductions)		24,843			9,563			22,070
Interest Expense
Long-Term Debt		58,134	��		70,227			73,095
Capital Leases		49,270			52,511			59,227
Other Interest Expense		3,468			1,837			5,480
Interest Capitalized		(2,302	)		(5,565	)		(5,551	)
Total Interest Expense		108,570			119,010			132,251
Income Before Income Taxes		168,606			30,996			97,452
Income Tax Expense		64,348			16,975			39,079
Net Income	$	104,258		$	14,021		$	58,373
Weighted-Average Shares of Common Stock Outstanding (000)		35,858			35,632			35,486
Basic Earnings per Share	$	2.91		$	0.39		$	1.64
Diluted Earnings per Share	$	2.69		$	0.39		$	1.57
Dividends Declared per Share	$	1.16		$	0.96		$	0.90

See Notes to Consolidated Financial Statements.

K-86

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2009			2008			2007
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,145,051		$	1,079,964		$	1,061,994
Cash Receipts from Electric Wholesale Sales		175,679			353,618			301,616
Cash Receipts from Gas Sales		163,441			182,271			165,678
Cash Receipts from Operating Springerville Unit 3		49,386			53,495			38,887
Cash Receipts from Operating Springerville Unit 4		19,565			4,162			—
Interest Received		13,470			17,246			19,197
Performance Deposits Received		34,630			34,404			12,549
Income Tax Refunds Received		20,242			22,355			1,016
Other Cash Receipts		15,441			15,137			14,603
Sale of Excess Emission Allowances		24			1,494			14,861
Refund of Disputed Transmission Costs		—			10,665			—
Purchased Energy Costs Paid		(334,481	)		(577,588	)		(450,197	)
Fuel Costs Paid		(300,810	)		(292,646	)		(283,439	)
Payment of Other Operations and Maintenance Costs		(236,184	)		(196,860	)		(158,057	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(161,574	)		(154,548	)		(151,074	)
Wages Paid, Net of Amounts Capitalized		(122,245	)		(108,504	)		(106,097	)
Interest Paid, Net of Amounts Capitalized		(54,641	)		(58,774	)		(68,446	)
Performance Deposits Paid		(22,260	)		(48,520	)		(7,900	)
Capital Lease Interest Paid		(38,598	)		(43,828	)		(54,315	)
Income Taxes Paid		(9,050	)		(9,900	)		(20,923	)
Excess Tax Benefit from Stock Options Exercised		(3,256	)		(633	)		(541	)
Other Cash Payments		(6,520	)		(5,999	)		(6,646	)
Net Cash Flows — Operating Activities		347,310			277,011			322,766
Cash Flows from Investing Activities
Capital Expenditures		(287,104	)		(357,324	)		(245,366	)
Payments for Investment in Springerville Lease Debt		(31,375	)		—			—
Prepayment Deposit on UED Short-Term Debt		(3,625	)		—			—
Deposit — Collateral Trust Bond Trustee		—			(133,111	)		—
Proceeds from Investment in Springerville Lease Debt		12,736			24,918			27,732
Other Proceeds from Investing Activities		331			5,137			4,475
Return of Investment from Millennium Energy Businesses		8,333			839			12
Insurance Proceeds for Replacement Assets		4,928			8,035			—
Investment in and Loans to Equity Investees		(207	)		(600	)		(845	)
Other Payments for Investing Activities		(661	)		(711	)		(3,413	)
Net Cash Flows — Investing Activities		(296,644	)		(452,817	)		(217,405	)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities		203,000			242,000			205,000
Proceeds from Issuance of Short-Term Debt		30,000			—			—
Proceeds from Stock Options Exercised		3,441			1,969			1,980
Excess Tax Benefit from Stock Options Exercised		3,256			633			541
Other Cash Receipts		5,681			6,028			8,210
Proceeds from Issuance of Long-Term Debt		—			320,745			—
Repayments of Borrowings Under Revolving Credit Facilities		(198,000	)		(237,000	)		(218,000	)
Payments of Capital Lease Obligations		(24,192	)		(74,316	)		(71,549	)
Common Stock Dividends Paid		(41,429	)		(34,043	)		(31,784	)
Repayment of Long-Term Debt		(6,000	)		(76,000	)		(6,000	)
Payment of Debt Issue/Retirement Costs		(2,268	)		(3,739	)		(465	)
Other Cash Payments		(2,405	)		(5,672	)		(7,162	)
Net Cash Flows — Financing Activities		(28,916	)		140,605			(119,229	)
Net Increase(Decrease) in Cash and Cash Equivalents		21,750			(35,201	)		(13,868	)
Cash and Cash Equivalents, Beginning of Year		55,172			90,373			104,241
Cash and Cash Equivalents, End of Year	$	76,922		$	55,172		$	90,373
Non-Cash Financing Activity
Repayment of UED Short-Term Debt	$	(3,625	)	$	—		$	—
Repayment of Collateral Trust Bonds	$	—		$	(128,300	)	$	—

See Note 17 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-87

UNISOURCE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,147,268		$	3,870,493
Utility Plant Under Capital Leases		720,628			702,337
Construction Work in Progress		144,551			171,996
Total Utility Plant		5,012,447			4,744,826
Less Accumulated Depreciation and Amortization		(1,652,296	)		(1,580,308	)
Less Accumulated Amortization of Capital Lease Assets		(574,437	)		(546,825	)
Total Utility Plant — Net		2,785,714			2,617,693
Investments and Other Property
Investments in Lease Debt and Equity		132,168			126,672
Other		60,239			64,096
Total Investments and Other Property		192,407			190,768
Current Assets
Cash and Cash Equivalents		76,922			55,172
Accounts Receivable — Retail and Other		64,230			74,288
Accounts Receivable — Wholesale Sales		18,288			44,725
Unbilled Accounts Receivable		53,361			60,146
Allowance for Doubtful Accounts		(5,977	)		(19,684	)
Materials and Fuel Inventory		116,791			92,170
Prepayments		6,759			7,893
Derivative Instruments		2,653			3,437
Regulatory Assets — Derivative Instruments		17,841			38,276
Regulatory Assets — Other		23,931			23,299
Deferred Income Taxes — Current		52,355			61,398
Income Tax Receivable		620			12,720
Interest Receivable on Capital Lease Debt Investment		5,081			4,491
Collateral Posted		1,750			14,120
Other		11,700			9,635
Total Current Assets		446,305			482,086
Regulatory and Other Assets
Income Taxes Recoverable Through Future Revenues		18,144			19,814
Regulatory Assets — Pension and Other Postretirement Benefits		84,149			112,035
Regulatory Assets — Derivative Instruments		9,503			18,324
Regulatory Assets — Other		35,529			39,395
Derivative Instruments		4,498			3,113
Other Assets		24,993			26,339
Total Regulatory and Other Assets		176,816			219,020
Total Assets	$	3,601,242		$	3,509,567

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-88

UNISOURCE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009		2008
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	750,865	$	679,274
Capital Lease Obligations		488,349		513,517
Long-Term Debt		1,307,795		1,313,615
Total Capitalization		2,547,009		2,506,406
Current Liabilities
Current Obligations Under Capital Leases		40,441		18,334
Short-Term Borrowings		35,000		10,000
Current Maturities of Long-Term Debt		12,195		6,000
Accounts Payable		54,152		62,514
Accounts Payable — Purchased Power		44,838		49,146
Interest Accrued		41,396		43,440
Accrued Taxes Other than Income Taxes		36,698		36,746
Accrued Employee Expenses		27,545		26,859
Customer Deposits		25,978		22,656
Regulatory Liabilities — Over-Recovered Purchased Energy Costs		24,258		25,665
Regulatory Liabilities — Other		17,971		8,161
Derivative Instruments		21,186		41,076
Other		3,960		1,460
Total Current Liabilities		385,618		352,057
Deferred Credits and Other Liabilities
Deferred Income Taxes — Noncurrent		227,199		178,089
Regulatory Liabilities — Net Cost of Removal for Interim Retirements		195,177		151,796
Regulatory Liabilities — Over-Recovered Purchased Energy Costs		16,714		44,469
Derivative Instruments		19,489		29,849
Pension and Other Postretirement Benefits		123,476		157,769
Customer Advances for Construction		31,803		31,062
Other		54,757		58,070
Total Deferred Credits and Other Liabilities		668,615		651,104
Commitments and Contingencies (Note 4)
Total Capitalization and Other Liabilities	$	3,601,242	$	3,509,567

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-89

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31,
					2009			2008
					- Thousands of Dollars -
COMMON STOCK EQUITY
Common Stock-No Par Value					$	696,206		$	687,360
	2009		2008
Shares Authorized		75,000,000		75,000,000
Shares Outstanding		35,851,185		35,457,780
Accumulated Earnings (Deficit)						60,461			(1,231	)
Accumulated Other Comprehensive Loss						(5,802	)		(6,855	)
Total Common Stock Equity						750,865			679,274
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding						—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1						320,843			306,553
Springerville Coal Handling Facilities						85,224			90,812
Springerville Common Facilities						109,499			108,516
Sundt Unit 4						13,077			25,400
Other						147			570
Total Capital Lease Obligations						528,790			531,851
Less Current Maturities						(40,441	)		(18,334	)
Total Long-Term Capital Lease Obligations						488,349			513,517
LONG-TERM DEBT
Issue	Maturity		Interest Rate
UniSource Energy:
Convertible Senior Notes		2035		4.50%		150,000			150,000
Credit Agreement		2011	Variable			40,000			58,000
Tucson Electric Power Company:
Variable Rate IDBs		2011	Variable			458,600			458,600
Unsecured IDBs		2020 – 2033	4.95% to 7.13%			445,015			445,015
UNS Gas and UNS Electric:
Senior Unsecured Notes		2011 – 2023	6.23% to 7.1%			200,000			200,000
Credit Agreement		2011	Variable			—			8,000
UED:
Secured Term Loan		2010	Variable			26,375			—
Total Stated Principal Amount						1,319,990			1,319,615
Less Current Maturities						(12,195	)		(6,000	)
Total Long-Term Debt						1,307,795			1,313,615
Total Capitalization					$	2,547,009		$	2,506,406

See Notes to Consolidated Financial Statements.

K-90

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

									Accumulated
	Common								Other			Total
	Shares		Common			Accumulated			Comprehensive			Stockholders’
	Outstanding*		Stock			Earnings (Deficit)			Loss			Equity
Balances at December 31, 2006		35,190	$	697,426		$	(27,913	)	$	(15,364	)	$	654,149
Implementation of FIN 48							696						696
Comprehensive Income:
2007 Net Income							58,373						58,373
Decrease in Pension and Other Post-Retirement Benefit Liabilities (net of $3,929 income taxes)										5,993			5,993
Unrealized Loss on Cash Flow Hedges (net of $2,500 income taxes)										(3,813	)		(3,813	)
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $996 income taxes)										1,519			1,519
Total Comprehensive Income													62,072
Dividends		—		—			(31,784	)					(31,784	)
Shares Issued under Stock Compensation Plans		125		1,980									1980
Tax Benefit Realized from Stock-Based Compensation Plans		—		540									540
Other		—		2,422									2,422
Balances at December 31, 2007		35,315		702,368			(628	)		(11,665	)		690,075
Impact of Change in Pension Plan Measurement Date							(603	)					(603	)
Comprehensive Income (Loss):
2008 Net Income							14,021						14,021
Unrealized Loss on Interest Rate Swap
(net of $2,181 income taxes)										(3,326	)		(3,326	)
Reclassification of Unrealized Gain on Cash Flow Hedges to Regulatory Asset (net of $1,370 income taxes)										(2,089	)		(2,089	)
Reclassification of Unrealized Loss on Cash Flow Hedges to Net Income (net of $1,569 income taxes)										2,393			2,393
Employee Benefit Obligations
Amortization of net actuarial loss and prior service credit included in net periodic benefit cost (net of $158 income taxes)										(242	)		(242	)
Increase in SERP Liability (net of $108 income taxes)										(165	)		(165	)
Reclassification of Pension and Other Postretirement Benefit to Regulatory Asset (net of $5,401 income taxes)										8,239			8,239
Total Comprehensive Income													18,831
Dividends		—		(20,017	)		(14,021	)		—			(34,038	)
Shares Issued under Stock Compensation Plans		143		1,969			—			—			1,969
Tax Benefit Realized from Stock-Based Compensation Plans		—		633			—			—			633
Other		—		2,407			—			—			2,407
Balances at December 31, 2008		35,458		687,360			(1,231	)		(6,855	)		679,274
Comprehensive Income:
2009 Net Income							104,258						104,258
Unrealized Loss on Cash Flow Hedges (net of $33 income taxes)										51			51
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $690 income taxes)										1,053			1,053
Employee Benefit Obligations
Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $33 income taxes)										(51	)		(51	)
Total Comprehensive Income													105,311
Dividends							(42,566	)					(42,566	)
Shares Issued under Deferred Compensation Plans		10		279									279
Shares Issued under Stock Compensation Plans — (net of shares redeemed for taxes)		383		2,541									2,541
Tax Benefit Realized from Stock-Based Compensation Plans				3,256									3,256
Other Stock-Based Compensation				2,770									2,770
Balances at December 31, 2009		35,851	$	696,206		$	60,461		$	(5,802	)	$	750,865

*	UniSource Energy has 75 million authorized shares of Common Stock.
We describe limitations on our ability to pay dividends in Note 8.
See Notes to Consolidated Financial Statements.

K-91

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2009			2008			2007
	- Thousands of Dollars -
Operating Revenues
Electric Retail Sales	$	867,516		$	805,528		$	816,471
Provision for Rate Refunds — CTC Revenue		—			(58,092	)		—
Net Electric Retail Sales		867,516			747,436			816,471
Electric Wholesale Sales		150,679			259,855			195,999
California Power Exchange (CPX) Provision for Wholesale Refunds		(4,172	)		—			—
Other Revenues		82,688			71,962			58,033
Total Operating Revenues		1,096,711			1,079,253			1,070,503
Operating Expenses
Fuel		281,710			289,985			296,511
Purchased Power		142,252			238,024			140,498
Transmission		3,066			10,515			9,014
Increase (Decrease) to Reflect PPFAC Recovery Treatment		(20,724	)		���			—
Total Fuel and Purchased Energy		406,304			538,524			446,023
Other Operations and Maintenance		289,765			256,584			202,837
Depreciation and Amortization		152,901			126,040			119,811
Amortization of Transition Recovery Asset		—			23,945			77,681
Taxes Other Than Income Taxes		37,618			31,650			40,366
Total Operating Expenses		886,588			976,743			886,718
Operating Income		210,123			102,510			183,785
Other Income (Deductions)
Interest Income		11,471			9,900			16,073
Other Income		10,991			5,708			3,665
Other Expense		(2,904	)		(6,249	)		(3,296	)
Total Other Income (Deductions)		19,558			9,359			16,442
Interest Expense
Long-Term Debt		36,226			47,456			50,230
Interest on Capital Leases		49,258			52,491			59,205
Other Interest Expense		1,571			1,367			4,538
Interest Capitalized		(1,752	)		(4,675	)		(2,744	)
Total Interest Expense		85,303			96,639			111,229
Income Before Income Taxes		144,378			15,230			88,998
Income Tax Expense		55,130			10,867			35,542
Net Income	$	89,248		$	4,363		$	53,456

See Notes to Consolidated Financial Statements.

K-92

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2009			2008			2007
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	944,873		$	883,423		$	883,885
Cash Receipts from Electric Wholesale Sales		199,918			377,579			301,616
Cash Receipts from Operating Springerville Unit 3		49,386			53,495			38,887
Cash Receipts from Operating Springerville Unit 4		19,565			4,162			—
Interest Received		12,768			15,849			16,284
Income Tax Refunds Received		14,462			20,902			—
Reimbursement of Affiliate Charges		19,998			16,534			—
Refund of Disputed Transmission Costs		—			10,665			—
Performance Deposits Received		14,000			10,150			—
Sale of Excess Emission Allowances		24			1,494			16,975
Other Cash Receipts		10,101			7,774			7,931
Fuel Costs Paid		(282,653	)		(284,830	)		(283,440	)
Purchased Power Costs Paid		(185,129	)		(364,356	)		(245,439	)
Payment of Other Operations and Maintenance Costs		(223,760	)		(185,206	)		(144,753	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(124,053	)		(117,611	)		(116,641	)
Wages Paid, Net of Amounts Capitalized		(97,289	)		(84,857	)		(82,661	)
Capital Lease Interest Paid		(38,586	)		(43,807	)		(54,293	)
Interest Paid, Net of Amounts Capitalized		(33,128	)		(38,467	)		(47,050	)
Income Taxes Paid		(14,606	)		—			(23,609	)
Performance Deposits Paid		(14,000	)		(10,150	)		—
Other Cash Payments		(3,827	)		(4,037	)		(3,580	)
Net Cash Flows — Operating Activities		268,064			268,706			264,112
Cash Flows from Investing Activities
Capital Expenditures		(235,485	)		(294,940	)		(162,539	)
Payments for Investments in Lease Debt and Equity		(31,375	)		—			—
Deposit — Collateral Trust Bond Trustee		—			(133,111	)		—
Proceeds from Investments in Springerville Lease Debt		12,736			24,918			27,732
Insurance Proceeds for Replacement Assets		4,928			8,035			—
Other Cash Receipts		6			5,055			650
Other Cash Payments		(411	)		(711	)		(2,968	)
Net Cash Flows — Investing Activities		(249,601	)		(390,754	)		(137,125	)
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt		—			220,745			—
Proceeds from Borrowings Under Revolving Credit Facility		171,000			170,000			160,000
Repayments of Borrowings Under Revolving Credit Facility		(146,000	)		(170,000	)		(180,000	)
Payments of Capital Lease Obligations		(24,091	)		(74,228	)		(71,464	)
Repayments of Long-Term Debt		—			(10,000	)		—
Dividends Paid to UniSource Energy		(60,000	)		(2,500	)		(53,000	)
Equity Investment from UniSource Energy		30,000			—			18,000
Other Cash Receipts		2,447			1,237			7,795
Payment of Debt Issue/Retirement Costs		(1,329	)		(3,120	)		(451	)
Other Cash Payments		(1,347	)		(3,421	)		(968	)
Net Cash Flows — Financing Activities		(29,320	)		128,713			(120,088	)
Net Increase (Decrease) in Cash and Cash Equivalents		(10,857	)		6,665			6,899
Cash and Cash Equivalents, Beginning of Year		33,275			26,610			19,711
Cash and Cash Equivalents, End of Year	$	22,418		$	33,275		$	26,610
Non-Cash Financing Activity — Repayment of Collateral Trust Bonds	$	—		$	(128,300	)	$	—

See Note 17 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-93

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	3,584,308		$	3,351,474
Utility Plant Under Capital Leases		719,922			701,631
Construction Work in Progress		113,390			145,457
Total Utility Plant		4,417,620			4,198,562
Less Accumulated Depreciation and Amortization		(1,582,442	)		(1,531,611	)
Less Accumulated Amortization of Capital Lease Assets		(573,853	)		(546,332	)
Total Utility Plant — Net		2,261,325			2,120,619
Investments and Other Property
Investments in Lease Debt and Equity		132,168			126,672
Other		31,813			31,291
Total Investments and Other Property		163,981			157,963
Current Assets
Cash and Cash Equivalents		22,418			33,275
Accounts Receivable — Retail and Other		46,894			53,091
Accounts Receivable — Wholesale		17,904			44,610
Unbilled Accounts Receivable		32,368			33,554
Allowance for Doubtful Accounts		(3,806	)		(17,135	)
Accounts Receivable — Due from Affiliates		5,218			16,614
Materials and Fuel Inventory		104,861			81,067
Prepayments		5,678			5,535
Derivative Instruments		5,043			5,129
Regulatory Assets — Derivative Instruments		3,696			14,242
Regulatory Assets — Other		23,330			22,834
Deferred Income Taxes — Current		50,789			59,615
Interest Receivable on Capital Lease Debt Investment		5,081			4,491
Other		11,313			10,554
Total Current Assets		330,787			367,476
Regulatory and Other Assets
Regulatory Assets — Pension and Other Postretirement Benefits		80,169			106,596
Regulatory Assets — Derivatives		4,631			5,400
Regulatory Assets — Other		34,203			38,180
Income Taxes Recoverable Through Future Revenues		18,144			19,814
Derivative Instruments		1,075			4,982
Other Assets		19,984			20,741
Total Regulatory and Other Assets		158,206			195,713
Total Assets	$	2,914,299		$	2,841,771

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-94

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS

	December 31,
	2009		2008
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	643,144	$	583,606
Capital Lease Obligations		488,311		513,370
Long-Term Debt		903,615		903,615
Total Capitalization		2,035,070		2,000,591
Current Liabilities
Current Obligations Under Capital Leases		40,332		18,231
Borrowings Under Revolving Credit Facility		35,000		10,000
Accounts Payable		48,631		56,001
Accounts Payable — Purchased Power		22,697		28,510
Accounts Payable — Due from Affiliates		3,694		3,610
Income Taxes Payable		—		2,057
Interest Accrued		33,970		35,828
Accrued Taxes Other than Income Taxes		28,404		27,679
Accrued Employee Expenses		24,409		23,990
Customer Deposits		18,125		15,902
Derivative Instruments		9,434		18,737
Regulatory Liabilities — Over-Recovered Purchased Energy Costs		9,200		14,310
Regulatory Liability — Other		17,439		7,083
Other		1,363		1,204
Total Current Liabilities		292,698		263,142
Deferred Credits and Other Liabilities
Deferred Income Taxes — Noncurrent		217,316		180,098
Regulatory Liabilities — Net Cost of Removal for Interim Retirements		162,764		122,037
Regulatory Liabilities — Over-Recovered Purchased Energy Costs		16,714		44,469
Derivative Instruments		11,195		18,794
Pension and Other Postretirement Benefits		116,991		149,955
Other		61,551		62,685
Total Deferred Credits and Other Liabilities		586,531		578,038
Commitments and Contingencies (Note 4)
Total Capitalization and Other Liabilities	$	2,914,299	$	2,841,771

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-95

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31,
					2009			2008
					- Thousands of Dollars -
COMMON STOCK EQUITY
Common Stock—No Par Value					$	843,971		$	813,971
	2009		2008
Shares Authorized		75,000,000		75,000,000
Shares Outstanding		32,139,434		32,139,434
Capital Stock Expense						(6,357	)		(6,357	)
Accumulated Deficit						(188,668	)		(217,153	)
Accumulated Other Comprehensive Loss						(5,802	)		(6,855	)
Total Common Stock Equity						643,144			583,606
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding						—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1						320,843			306,553
Springerville Coal Handling Facilities						85,224			90,812
Springerville Common Facilities						109,499			108,516
Sundt Unit 4						13,077			25,400
Other Leases						—			320
Total Capital Lease Obligations						528,643			531,601
Less Current Maturities						(40,332	)		(18,231	)
Total Long-Term Capital Lease Obligations						488,311			513,370
LONG-TERM DEBT
Issue	Maturity		Interest Rate
Variable Rate IDBs		2011	Variable			458,600			458,600
Unsecured IDBs		2020 – 2033	4.95% to 7.125%			445,015			445,015
Total Long-Term Debt						903,615			903,615
Total Capitalization					$	2,035,070		$	2,000,591

See Notes to Consolidated Financial Statements.

K-96

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME

									Accumulated
			Capital						Other			Total
	Common		Stock			Accumulated			Comprehensive			Stockholder’s
	Stock		Expense			Deficit			Loss			Equity
	- Thousands of Dollars -
Balances at December 31, 2006	$	795,971	$	(6,357	)	$	(219,640	)	$	(15,260	)	$	554,714
Implementation of FIN 48							696						696
Comprehensive Income:
2007 Net Income							53,456						53,456
Decrease in Pension and Other Post-Retirement Benefit Liabilities (net of $3,820 income taxes)										5,826			5,826
Unrealized Loss on Cash Flow Hedges (net of $2,532 income taxes)										(3,862	)		(3,862	)
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income to Regulatory Asset (net of $996 income taxes)										1,519			1,519
Total Comprehensive Income													56,939
Capital Contribution from UniSource Energy		18,000											18,000
Dividends Paid							(53,000	)					(53,000	)
Balances at December 31, 2007		813,971		(6,357	)		(218,488	)		(11,777	)		577,349
Impact of Change in Pension Plan Measurement Date							(528	)					(528	)
Comprehensive Income (Loss):
2008 Net Income							4,363						4,363
Unrealized Loss on Interest Rate Swap (net of $2,181 income taxes)										(3,326	)		(3,326	)
Reclassification of Unrealized Gain on Cash Flow Hedges to Regulatory Asset (net of $1,337 income taxes)										(2,039	)		(2,039	)
Reclassification of Unrealized Loss on Cash Flow Hedges to Net Income (net of $1,569 income taxes)										2,393			2,393
Employee Benefit Obligations
Amortization of net actuarial loss and prior service credit included in net periodic benefit cost (net of $157 income taxes)										(240	)		(240	)
Increase in SERP Liability (net of $108 income taxes)										(165	)		(165	)
Reclassification of Pension and Other Postretirement Benefit to Regulatory Asset (net of $5,441 income taxes)										8,299			8,299
Total Comprehensive Income													9,285
Dividends Paid							(2,500	)					(2,500	)
Balances at December 31, 2008		813,971		(6,357	)		(217,153	)		(6,855	)		583,606
Comprehensive Income:
2009 Net Income							89,248						89,248
Unrealized Loss on Cash Flow Hedges (net of $33 income taxes)										51			51
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $690 income taxes)										1,053			1,053
Employee Benefit Obligations
Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $33 income taxes)										(51	)		(51	)
Total Comprehensive Income													90,301
Capital Contribution from UniSource Energy		30,000											30,000
Dividends							(60,763	)					(60,763	)
Balances at December 31, 2009	$	843,971	$	(6,357	)	$	(188,668	)	$	(5,802	)	$	643,144

We describe limitations on our ability to pay dividends in Note 8.

See Notes to Consolidated Financial Statements.

K-97

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — DRAFT

Audit Committee
2/19/10

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

NATURE OF OPERATIONS

UniSource Energy Corporation (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 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy Development Company (UED).

TEP, a regulated public utility, is UniSource Energy’s largest operating subsidiary and represented approximately 81% of UniSource Energy’s assets as of December 31, 2009. TEP generates, transmits and distributes electricity to approximately 402,000 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. In addition, TEP operates Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and beginning in December 2009 Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).

UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a gas distribution company with 146,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in Northern Arizona, as well as Santa Cruz County in South Central Arizona. UNS Electric is an electric transmission and distribution company with approximately 90,000 retail customers in Mohave and Santa Cruz counties.

Millennium invests in unregulated businesses. In June 2009, Millennium sold its 50% equity interest in Carboelectrica Sabinas, S. de R.L. de C.V. See Note 15.

Our business is comprised of three reporting segments – TEP, UNS Gas and UNS Electric.

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

BASIS OF PRESENTATION

We account for our investments in subsidiaries using the consolidation method when we hold a majority of a subsidiary’s voting stock and we can exercise control over the subsidiary. The accounts of the subsidiary and parent are combined, and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated.

We use the equity method to report corporate joint ventures, partnerships, and affiliated company investments when we can demonstrate the ability to exercise significant influence over the operating and financial policies of an investee company. Equity method investments are recorded at cost and 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. Quarterly, we review the equity investments and where there is an other-than-temporary impairment, we recognize the loss in earnings.

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USE OF ACCOUNTING ESTIMATES

We make estimates and assumptions to prepare financial statements under accounting principles generally accepted in the U.S. (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 about contingent assets and liabilities at the dates of the financial statements; and

• A portion of revenues and expenses reported during the periods presented.

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

ACCOUNTING FOR RATE REGULATION

TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies. However, sometimes regulatory accounting requires rate-regulated companies to apply special accounting treatment to show the effect of rate-regulation. For example, the ACC can determine that TEP, UNS Gas or UNS Electric are allowed to recover certain expenses, but at a designated time in the future. In this situation, TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until they are allowed to charge their customers. TEP, UNS Gas and UNS Electric then amortize these items as expenses as they recover these charges 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. We evaluate our regulatory assets each period and believe recovery is probable.

Beginning in December 2008, as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations. See Note 2.

The conditions a rate-regulated company must satisfy to apply regulatory accounting policies and practices include:

• An independent regulator sets rates;

• The regulator sets the rates to recover the specific enterprise’s costs of providing service; and

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

CASH AND CASH EQUIVALENTS

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

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UTILITY PLANT

TEP, UNS Gas and UNS Electric report utility plant at cost. Costs included in utility plant are materials and labor, contractor services, construction overhead (where applicable), and an Allowance for Funds Used During Construction (AFUDC).

Costs to replace major units of property are included in utility plant. The cost of planned major maintenance activities, including scheduled overhauls at TEP’s generation plants, is recorded as the costs are actually incurred. Replacement of capital equipment included in plant maintenance activities is capitalized to utility plant. TEP, UNS Gas and UNS Electric charge the cost of repairs and minor replacements to Other Operations and Maintenance expense.

When a unit of regulated property is retired, the original cost plus removal costs less any salvage value is credited or charged to accumulated depreciation. Prior to December 2008, before TEP reapplied regulatory accounting to its generation operations, interim retirements of unregulated generation plant, together with the cost of removal less salvage, were charged to accumulated depreciation.

AFUDC and Capitalized Interest

AFUDC, which reflects the cost of debt or equity funds used to finance construction, is capitalized as part of the cost of regulated utility plant. AFUDC applies to all regulated operations that follow regulatory accounting. AFUDC amounts capitalized are included in rate base for establishing utility rates. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction. The interest capitalized that relates to debt reduces Other Interest Expense on the income statement. The cost capitalized that relates to equity funds is recorded as Other Income. Beginning in December 2008, when TEP reapplied regulatory accounting to its generation operations, TEP began capitalizing costs that relate to equity funds. See Note 2.

	TEP
	2009			2008			2007
Average AFUDC rate on regulated construction expenditures		6.4	%		7.5	%		10.05	%
AFUDC — Debt (in millions)	$	2		$	2		$	2
AFUDC — Equity (in millions)	$	4		$	3		$	1
Average capitalized interest rate on generation-related construction expenditures (before December 2008)		N/A			5.02	%		5.73	%
Capitalized interest (in millions)		N/A		$	2		$	1

	UNS Gas
	2009			2008			2007
Average AFUDC rate on regulated construction expenditures		7.05	%		8.37	%		8.12	%
AFUDC — Debt (in millions)	$	0.1		$	0.1		$	0.3
AFUDC — Equity (in millions)	$	0.1		$	0.1		$	0.3

	UNS Electric
	2009			2008			2007
Average AFUDC rate on regulated construction expenditures		7.62	%		8.84	%		13.51	%
AFUDC — Debt (in millions)	$	0.4		$	0.2		$	0.7
AFUDC — Equity (in millions)	$	0.5		$	0.3		$	0.4

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Depreciation

TEP, UNS Gas, UNS Electric and UED compute depreciation for owned utility plant on a group method straight-line basis at rates based on the economic lives of the assets. See Note 5. The ACC approves depreciation rates for all utility plant, except that of UED and the transmission assets of TEP which are subject to FERC jurisdiction. Depreciation rates are based on average useful lives and reflect estimated removal costs, net of estimated salvage value for interim retirements. Prior to December 2008, before TEP reapplied regulatory accounting to its generation operations, the depreciable lives for TEP’s generation assets were based on remaining useful lives. We have summarized the average annual depreciation rates for all utility plants below.

Year	TEP			UNS Gas			UNS Electric			UED
2009		3.64	%		2.76	%		4.33	%		2.57	%
2008		3.33	%		2.77	%		4.47	%		2.57	%
2007		3.35	%		3.28	%		4.60	%		N/A

Computer Software Costs

TEP, UNS Gas and UNS Electric capitalize costs incurred to purchase and develop computer software for internal use and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense. TEP amortized capitalized computer software costs of $8 million in 2009, $7 million in 2008, and $9 million in 2007.

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. The lease terms are described in TEP Capital Lease Obligations in Note 6.

	Years Ended December 31,
	2009		2008		2007
	-Millions of Dollars-
Lease Expense:
Interest Expense – Included in:
Interest on Capital Leases	$	49	$	52	$	59
Operating Expenses – Fuel		5		5		5
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel		2		4		4
Operating Expenses – Depreciation and Amortization		26		21		21
Total Lease Expense	$	82	$	82	$	89

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP has investments in lease debt in two of TEP’s capital leases: Springerville Unit 1 and Springerville Coal Handling Facilities. TEP’s investments in lease debt are considered to be held-to-maturity investments because TEP has the ability and intent to hold until maturity. TEP records these investments at amortized cost and recognizes interest income. See Note 6. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to debt and equity holders.

TEP accounts for its 14% equity interest in the Springerville Unit 1 lease trust using the equity method.

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JOINTLY-OWNED FACILITIES

TEP has investments in several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation basis. See Note 5.

ASSET RETIREMENT OBLIGATIONS

TEP records a liability for the estimated present value of a conditional asset retirement obligation as follows:

• When it is 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; or

• If it can reasonably estimate the fair value.

When the liability is initially recorded at net present value, TEP capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, TEP adjusts the liability to its present value by recognizing accretion expense each period in other operations and maintenance expense, and the capitalized cost is depreciated in depreciation and amortization expense over the useful life of the related asset. Upon retirement of the asset, TEP either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount.

Beginning in December 2008, when TEP reapplied regulatory accounting to its generation operations, TEP began recording cost of removal for its generation assets that is recoverable through rates charged to customers. See Note 2. TEP, UNS Gas and UNS Electric record cost of removal for their transmission and distribution assets through depreciation rates and recover those amounts in rates charged to their customers. There are no legal obligations associated with these assets. TEP, UNS Gas and UNS Electric have recorded their obligation for estimated costs of removal as regulatory liabilities.

EVALUATION OF ASSETS FOR IMPAIRMENT

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

Millennium evaluates its investments for impairment at the end of each quarter. If the decline in fair value is judged to be other-than-temporary, an impairment loss would be recorded.

DEFERRED FINANCING COSTS

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

TEP, UNS Gas and UNS Electric defer and amortize the gains and losses on reacquired debt associated with their regulated operations to interest expense over the remaining life of the original debt. Prior to December 2008, when TEP reapplied regulatory accounting to its generation operations, TEP recognized gains and losses on reacquired debt, including unamortized debt issuance costs, associated with its generation operations, as incurred.

UTILITY OPERATING REVENUES

TEP, UNS Gas and UNS Electric 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.

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Amounts delivered are determined through systematic monthly readings of customer meters. At the end of the month, the usage since the last meter reading is estimated and the corresponding unbilled revenue is calculated. Unbilled revenue is estimated based on daily generation or purchased volumes, estimated customer usage by class, estimated line losses and estimated average customer rates. Accrued unbilled revenues are reversed the following month when actual billings occur. The accuracy of the unbilled revenue estimate is affected by factors that include fluctuations in energy demands, weather, line losses, and changes in the composition of customer classes.

Effective in January 2009, as a result of the 2008 TEP Rate Order, TEP has a rate-adjustment mechanism that provides for the recovery of fuel and purchased energy cost. UNS Gas and UNS Electric also have rate-adjustment mechanisms in place that allow for a revenue surcharge or surcredit (that adjusts the customer’s base rate for delivered purchased power or gas) to collect or return under- or over- recovery of costs. These rate-adjustment mechanisms are revised periodically and may increase or decrease the level of costs recovered through base rates for any difference between the total amount collected under the clauses and the recoverable costs incurred. See Note 2.

TEP’s wholesale revenue and purchased power costs from settled energy contracts that are not physically delivered are reported on a net basis in Electric Wholesale Sales. The corresponding cash receipts and payments are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales and Purchased Energy Costs Paid, respectively.

We record an Allowance for Doubtful Accounts to reduce accounts receivable for revenue amounts that are estimated to be uncollectible. TEP, UNS Gas and UNS Electric establish an allowance for doubtful accounts based on historical collection experience and any specific customer collection issues that are identified. TEP’s Allowance for Doubtful Accounts was $4 million at December 31, 2009, and $17 million at December 31, 2008. See Note 4. UNS Gas and UNS Electric’s combined Allowance for Doubtful Accounts was $2 million at December 31, 2009 and $3 million at December 31, 2008.

TEP recognizes revenue from operating Springerville Unit 3 and Unit 4 as contract services and materials are provided. Expenses are recorded in the respective line item of the income statement based on the nature of service or materials provided.

INVENTORY

TEP records fuel inventory, primarily coal, at weighted average cost. TEP uses full absorption costing, under which all handling and procurement costs are included in the cost of the inventory. Examples of these costs include direct material, direct labor, overhead costs and transportation costs. See Note 4 regarding fuel purchase contracts.

Materials and supplies inventories are recorded at cost. Materials and supplies consist of transmission and distribution line construction and repair materials and generating station and transmission and distribution substation repair materials.

FUEL AND PURCHASED ENERGY COSTS

TEP and UNS Electric Purchased Power and Fuel Adjustment Clause (PPFAC)

As a result of the 2008 TEP Rate Order, TEP began deferring differences between purchased energy costs and the recovery of such costs in rates effective January 1, 2009. UNS Electric also defers differences between purchased energy costs and the recovery of such costs in rates. Where applicable, fuel cost over-recoveries (the excess of fuel costs recovered in base rates over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel costs recovered in base rates) are deferred as current regulatory assets. The 2008 TEP Rate Order required TEP to credit, with interest, $58 million of Fixed CTC true-up revenues charged to customers from May 2008 to November 2008, through the PPFAC. See Note 2.

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UNS Gas Purchased Gas Adjustor (PGA)

UNS Gas defers differences between gas purchase costs and the recovery of such costs in base rates under a Purchased Gas Adjustor (PGA) mechanism. The PGA mechanism addresses the volatility of natural gas prices and allows UNS Gas to recover its commodity costs through a price adjustor. The PGA factor, computed monthly, is a calculation of the twelve-month rolling weighted average gas cost, and automatically adjusts monthly, 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 cost which is 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 surcredit with the goal of collecting or returning the amount deferred from or to customers, with interest, over a twelve-month period. See Note 2.

INCOME TAXES

Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. This difference is accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using current income tax rates, which are expected to be in effect when the deferred tax assets and liabilities are realized or settled.

Tax benefits are recognized in the financial statements when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority. In calculating the benefit to be recognized we assume the tax authorities have full knowledge of the position and all relevant facts. Interest Expense includes interest accrued by UniSource and TEP on tax positions taken on tax returns which have not been reflected in the financial statements.

Prior to 1990, we flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on the income tax return. Income Taxes Recoverable Through Future Rates on the balance sheet reflects the future revenues due us from ratepayers as these tax benefits reverse. See Notes 2 and 9.

Federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises.

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.

TAXES OTHER THAN INCOME TAXES

TEP, UNS Gas and UNS Electric act as conduits or collection agents for sales tax, utility taxes, franchise fees and regulatory assessments. We record liabilities payable to governmental agencies as customers are billed for these taxes and assessments. These amounts are not reflected in the income statement.

EMISSION ALLOWANCES

The Environmental Protection Agency (EPA) issues emission allowances to qualifying utilities 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 SO₂emission allowances annually; UNS Electric and UED do not receive SO₂emission allowances since neither has coal-fired generation. When issued from the EPA, these SO₂emission allowances have no book value for accounting purposes but may be sold if TEP does not need them for operations. TEP may also purchase additional SO₂emission allowances if needed. Purchased SO₂emission allowances are recorded at cost. Beginning in January 2009, as a result of the 2008 TEP Rate Order, TEP will credit 50% of the gains from the sales of SO₂emission allowances to the PPFAC. The remaining 50% of gains from sales of excess SO₂ emissionallowances will be reflected as a reduction of Other Operations and Maintenance expense on TEP’s income statement when title passes and in the operating activities section of the statement of cash flows. 100% of gains from sales of excess SO₂emission allowances were reflected as a reduction of Other Operations and Maintenance expense in 2007 and 2008. No allowances were sold in 2009.

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RENEWABLE ENERGY STANDARDS TARIFF (REST) AND RENEWABLE ENERGY CREDITS (RECs)

Arizona adopted a mandatory renewables portfolio standard that requires TEP and UNS Electric to engage in renewable energy activities, allowing cost recovery under REST. Arizona uses RECs as a form of measurement of compliance to the REST requirements encouraging construction and consumption of renewable energy. RECs are created each time one KWh of renewable energy is generated or when qualifying renewable equipment is manufactured. An escalating percentage of retail electric sales determine the annual REC requirement. RECs may be used to satisfy compliance requirements anytime after creation with no expiration date. We have the option of generating our own RECs, or purchasing RECs which are usually bundled with renewable power purchases. RECs may be sold if we do not need them for operations.

DERIVATIVE FINANCIAL INSTRUMENTS

Risks and Overview

TEP, UNS Gas and UNS Electric are exposed to energy price risk associated with their gas and purchased power requirements, volumetric risk associated with their seasonal load and operational risk associated with their power plants, transmission and transportation systems. The energy price risk is mitigated through the PPFAC and PGA mechanisms which provide an adjustment to TEP, UNS Gas and UNS Electric’s retail rates to recover the actual costs of purchased power, gas, transmission and transportation. TEP, UNS Gas and UNS Electric further reduce their energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability for TEP, UNS Gas and UNS Electric; to ensure TEP, UNS Gas and UNS Electric can meet their load and reserve requirements; and reducing TEP, UNS Gas and UNS Electric’s exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Note 2 for further information regarding regulatory matters.

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk, after considering collateral posted, on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.

Although TEP’s gains and losses on trading activities, if any, are recorded on a net basis in the income statement, we report the related cash receipts and cash payments separately in the statement of cash flows. We present cash collateral and derivative assets and liabilities, associated with the same counterparty, separately in our financial statements and we bifurcate all derivatives into their current and long-term portions on the balance sheet.

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Cash Flow Hedges

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to LIBOR on the Springerville Common Facilities Lease. TEP accounts for cash flow hedges as follows:

• The effective portion of the changes in the fair value of TEP’s interest rate swaps and TEP’s six-year power purchase swap agreement are recorded in AOCI and the ineffective portion, if any, is recognized in earnings.

• When TEP determines a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes the changes in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.

We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items. We discontinue hedge accounting when: (1) the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item; (2) the derivative expires or is sold, terminated, or exercised; (3) it is no longer probable that the forecasted transaction will occur; or (4) we determine that designating the derivative as a hedging instrument is no longer appropriate.

Mark-to-Market

•	TEP
	TEP’s non-trading hedges, such as forward power purchase contracts indexed to gas, short-term forward power sales contracts, or call and put options (gas collars), that did not qualify for cash flow hedge accounting treatment or did not qualify for the normal scope exception, are considered mark-to-market transactions. TEP hedges a portion of its monthly natural gas exposure for plant fuel, gas-indexed purchased power and spot market purchases with fixed price contracts for a maximum of three years. Beginning in December 2008, as a result of the 2008 TEP Rate Order, which permits recovery in the PPFAC of hedging transactions, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability only to the extent they qualify for recovery under the PPFAC mechanism.
	TEP enters into certain energy-related derivatives for trading purposes which are forward power purchase and sale contracts entered into purely to profit from market price changes. The net trading activities represent a very small portion (less than 1%) of TEP’s revenue from wholesale sales in 2007 and 2008. In 2009, TEP had no trading activity. As unrealized gains and losses resulting from changes in the market prices of trading derivatives are not recoverable in the PPFAC, unrealized gains and losses are recorded in the income statement in Electric Wholesale Sales.
•	UNS Electric
	UNS Electric hedges a portion of its purchased power exposure to fixed price and natural gas-indexed contracts with forward power purchases or financial gas swaps. In April 2009, UNS Electric also began using call and put options, creating price stability and reducing exposure to price volatility that may result in delayed recovery under the PPFAC.
•	UNS Gas
	UNS Gas enters into derivatives such as forward gas purchases and gas swaps, creating price stability and reducing exposure to natural gas price volatility that may result in delayed recovery under the PGA. Beginning in December 2008, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the UNS Gas PGA mechanism permits the recovery of the prudent cost of hedging contracts.

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Normal Purchase and Normal Sale

UNS Gas, UNS Electric and TEP enter into forward energy purchase and sales contracts, including call options, to support the current load forecast and contracts entered into with a counterparty with load serving requirements or generating capacity. These contracts are not required to be marked-to-market and are accounted for on an accrual basis. On an ongoing basis we evaluate our counterparties for non-performance risk to ensure it does not impact our ability to obtain the normal scope exception.

2007 and 2008 Accounting Summary

Prior to December 2008, we recorded unrealized gains and losses on derivative instruments as follows:

• TEP’s interest rate swaps, TEP’s forward contracts to sell excess capacity, and TEP and UNS Gas’ forward gas swaps were recorded in AOCI;

• TEP’s non-trading hedges such as forward power purchase contracts indexed to gas, and TEP’s forward purchase and sale trading contracts were recorded in the income statement; and

• All other commodity contracts were reflected on the balance sheet as either regulatory assets or regulatory liabilities.

SHARE-BASED COMPENSATION

UniSource Energy has a stock-based long-term incentive plan. UniSource Energy measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). Compensation costs are recognized over the period during which an employee is required to provide service in exchange for the award which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures of equity instruments prior to vesting. Our share-based compensation plans are described more fully in Note 11.

RECLASSIFICATIONS AND OTHER ADJUSTMENTS

Springerville Unit 1

In 2006, we recorded an investment in 14.14% of Springerville Unit 1 lease equity transaction as a lease restructuring. We subsequently determined that the transaction was best characterized as a purchase of an interest in a trust accounted for using equity method accounting. As a result, at June 30, 2009, UniSource Energy and TEP recorded a net increase to Net Income of less than $0.5 million, after tax. The net adjustment recorded in June 2009 included additional depreciation expense of $4 million; a reduction of interest expense on capital leases of $2 million; and $3 million of equity in earnings which is included in Other Income on the income statement. In addition, UniSource Energy and TEP recorded a $19 million increase to capital lease assets, a $4 million increase to accumulated amortization, a $3 million increase to capital lease obligations, and an $11 million decrease to investment in lease debt.

Renewable Energy and Demand Side Management (DSM) Revenues

UniSource Energy and TEP reclassified renewable revenue of $5 million and $3 million in 2008, and $7 million and $5 million in 2007, respectively, from Other Revenue to Electric Retail Sales in the Statements of Income. These reclassifications had no effect on Net Income.

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Dividend Equivalents

In September 2009, UniSource Energy and TEP recorded dividends of $0.9 million and $0.8 million, respectively, for dividend equivalents that should have been recorded between 2005 and 2008.

Other

In June 2009, TEP recorded approximately $1 million ($0.6 million after-tax) of additional depreciation for plant improvements that should have been recorded prior to 2009. TEP also recorded an after-tax gain of $1.5 million related to proceeds from a company owned life insurance policy that should have been recorded prior to 2009.

TEP 2008 Rate Order

In the TEP 2008 Rate Order, the Arizona Corporation Commission (ACC) granted TEP a Purchased Power and Fuel Adjustment Clause (PPFAC) which allows recovery of actual fuel and purchased power costs, including demand charges, transmission costs, and prudent settlement costs of contracts for hedging fuel and purchased power costs. UNS Electric has a similar PPFAC mechanism. UNS Gas has a Purchased Gas Adjuster (PGA) mechanism which allows UNS Gas to recover its actual commodity costs, including transportation. See Note 2.

To provide more information regarding the components of the PPFAC/PGA and to be comparable with the 2009 presentation, UniSource Energy and TEP made the following reclassifications to the statements of income for the years ended December 31, 2008 and December 31, 2007.

• UniSource Energy and TEP reclassified Transmission expenses of $19 million and $11 million in 2008, and $16 million and $9 million in 2007, respectively, from Other Operations and Maintenance to Transmission, a component of Total Fuel and Purchased Energy;

• UniSource Energy and TEP reclassified capital lease expenses of $5 million in 2007 and 2008 from Interest on Capital Leases to Fuel; and

• UniSource Energy reclassified $11 million in 2008 and $5 million in 2007 of over-recovered PPFAC and PGA expenses from Purchased Energy, Transmission, and Fuel to Increase (Decrease) to reflect PPFAC/PGA Recovery Treatment, a component of Total Fuel and Purchased Energy.

These reclassifications had no effect on Net Income.

NOTE 2. REGULATORY MATTERS

1999 Settlement Agreement

We believe that the 1999 Settlement Agreement contemplated that TEP’s retail rates for generation service would have been market-based beginning January 1, 2009. As part of the 2008 TEP Rate Order, TEP and all the parties to the 2008 Proposed Settlement Agreement relinquished all claims related to the 1999 Settlement Agreement and the ACC order adopting the 1999 Settlement Agreement.

1999 Transition Recovery Asset

TEP’s Transition Recovery Asset consisted of generation-related regulatory assets and a portion of TEP’s generation plant asset costs. Transition costs that were recovered through the Fixed CTC included: (1) the Transition Recovery Regulatory Asset; (2) a small portion of 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. In May 2008, TEP fully amortized the remaining Transition Recovery Asset balance, as costs were fully recovered through rates. TEP amortized $24 million and $78 million of the asset to the income statement in 2008 and 2007, respectively. TEP also amortized $2 million and $8 million of generation-related plant assets in 2008 and 2007, respectively.

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In May 2007, the ACC ordered that TEP’s current Fixed CTC revenue remain at its then-current level until the effective date of a final order in the TEP 2008 proposed settlement agreement proceeding. As of December 1, 2008, when new rates went into effect, TEP had collected $58 million of true-up revenues and recorded a $58 million reserve for Fixed CTC revenue to be refunded against its Electric Retail Sales in 2008. The 2008 TEP Rate Order requires TEP to return the Fixed CTC true-up revenues to customers by reducing the PPFAC balance.

TEP 2008 Rate Order

The 2008 TEP Rate Order, issued by the ACC and effective December 1, 2008, provides for a cost of service rate methodology for TEP’s generation assets; an average base rate increase of 6% over TEP’s previous retail rates; a fuel rate included in base rates of 2.9 cents per kilowatt-hour (kWh); a PPFAC effective January 1, 2009; a base rate increase moratorium through January 1, 2013; and a waiver of any claims under the 1999 Settlement Agreement.

As a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations. In addition, in December 2008, TEP began deferring its mark-to-market adjustments for derivative instruments that are expected to be recovered through the PPFAC as either regulatory assets or regulatory liabilities.

Purchased Power and Fuel Adjustment Clause (PPFAC)

The TEP PPFAC became effective January 1, 2009. The PPFAC allows recovery of fuel and purchased power costs, including demand charges and the prudent costs of contracts for hedging fuel and purchased power costs. The PPFAC consists of a forward component and a true-up component.

• The forward component of 0.18 cents per kWh became effective on April 1, 2009, and will be updated each year. The forward component is based on the forecasted fuel and purchased power costs for the twelve-month period from April 1 to March 31 the following year, less the average base cost of fuel and purchased power of approximately 2.9 cents per kWh, which is embedded in base rates.

• The true-up component will reconcile any over/under collected amounts from the preceding 12 month period and will be credited to or recovered from customers in the subsequent year.

TEP credited Fixed CTC revenue to be refunded ($58 million collected from May 2008 to November 30, 2008) to customers as an offset to the PPFAC rate. This credit will offset the forward and true-up components of the PPFAC, resulting in a PPFAC charge of zero until the Fixed CTC revenue to be refunded is fully credited, which is expected to occur over the next 36 to 48 months beginning April 1, 2009.

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The following table shows the balance of Regulatory Liabilities – (Over-) Under-Recovered Purchased Energy Costs:

	December 31,			December 31,
	2009			2008
	-Millions of Dollars-
Fixed CTC Revenue to be Refunded within the next 12 months; Included in Current Liabilities	$	(9	)	$	(14	)
Under-Recovered Purchased Energy Costs – Regulatory Basis as Billed to Customers	$	29		$	—
Estimated Purchased Energy Costs Recovered through Accrued Unbilled Revenues		(9	)		—
Fixed CTC Revenue to be Refunded		(37	)		(44	)
Total Included in Deferred Credits and Other Liabilities	$	(17	)	$	(44	)

The $12 million amortization of the Fixed CTC Revenue to be Refunded appears in the accompanying income statements as an addition to retail revenues in 2009. The $21 million 2009 change in Under-Recovered Purchased Energy Costs appears in the income statement as a credit to fuel and purchased power costs in the line item Increase (Decrease) to Reflect PPFAC Recovery Treatment.

For the purposes of reconciling fuel and purchased power to PPFAC revenues, including the credited forward component, TEP will credit the allocable retail portion of the following against the PPFAC eligible costs: 100% of short-term wholesale revenues; 10% of the annual profit on trading activity; and 50% of the revenues from the sales of SO₂ emission allowances. TEP had no trading activities or sales of SO₂ emission allowances in 2009.

Ratemaking Methodology for Generation Assets

Rates for generation service are based on a cost-of-service methodology. All generation assets acquired by TEP between the end of the rate case test year (December 31, 2006) and the end of the base rate increase moratorium period (December 31, 2012) shall be included in TEP’s rate base at their respective original depreciated cost, subject to subsequent review and approval by the ACC in future rate cases. Luna is included in TEP’s original cost rate base at its net book value of $48 million as of December 31, 2006.

Springerville Unit 1 non-fuel costs are being recovered through base rates at $25.67 per kilowatt (kW) per month, which approximates the levelized cost of Springerville Unit 1 through the remainder of the lease term.

Depreciation and Net Negative Salvage

On December 1, 2008, TEP implemented new depreciation rates that include a component for net negative salvage value for all generation assets except Luna and new depreciation rates for distribution and general plant assets that will extend the depreciable lives of these assets. The estimated net impact on the income statement is to increase depreciation expense $9 million per year.

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Impact of Reapplying Regulatory Accounting to TEP’s Generation Operations

In December 2008, as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations and TEP recorded the following adjustments:

	Income
	Statement			Balance Sheet
				Regulatory Asset
						Non
	(Gain)/Loss			Current		Current		AOCI
Recorded in Fuel:
San Juan Coal Contract Amendment	$	(9	)	$	1	$	8	$	—
Retiree Health Care and Final Mine Reclamation Costs		(15	)		—		15		—
Unrealized Gains (Losses) on Derivative Contracts (PPFAC)		(8	)		14		5		(11	)
Deregulation Costs Recorded in O&M		(1	)		1		—		—
Property Taxes		(7	)		7		—		—
Pension and Other Postretirement Benefits		—			—		14		(14	)
Pre-Tax Impact of Reapplying Regulatory Accounting	$	(40	)	$	23	$	42	$	(25	)

• San Juan Coal Contract Amendment costs of $9 million, incurred by TEP in 2000, will be amortized over 9 years beginning in December 2008.

• Final Mine Reclamation and Retiree Health Care Costs represent costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners and Navajo. TEP is required to recognize the present value of its liability associated with final reclamation and retiree health care obligations. As TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners, TEP recorded a regulatory asset.

• Unrealized gains (losses) on derivative instruments (PPFAC) are contracts for which the settled amounts will be recovered through the PPFAC. As TEP expects to recover the final settled amounts through the PPFAC, TEP reclassified amounts previously recorded in the income statement and in AOCI to a regulatory asset.

• Deregulation Costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders.

• Property taxes related to generation assets which will be recovered in rates as cash is paid rather than as costs are accrued.

• Pension and Other Postretirement Benefits represent the underfunded status of TEP’s defined benefit and other postretirement benefit plans prior to December 2008. As TEP expects to recover these costs in rates, TEP reclassified amounts previously recorded in AOCI to a regulatory asset.

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Income Statement Impact of Applying Regulatory Accounting

Regulatory accounting had the following impacts on TEP’s reported net income, in addition to the impact of reapplying regulatory accounting to its generation operations for 2008:

	Years Ended December 31,
	2009			2008		2007
	-Millions of Dollars-
Operating Revenues
Amortization of the Fixed CTC Revenue to be Refunded	$	(12	)	$	—	$	—
Operating Expenses
Depreciation (related to Net Cost of Removal for Interim Retirements)		41			10		7
Deferral of Under-Recovered Purchased Energy Costs		(21	)		—		—
Deferral of Unrealized losses on Derivative Instruments		10			—		—
Amortization of 1999 Transition Recovery Asset		—			24		78
Other		3			—		—
Interest Expense
Long-Term Debt (Amortization of Loss on Reacquired Debt Costs)		—			1		1
Income Taxes		—			4		5
Net Increase to Income Statement	$	21		$	39	$	91

If TEP had not applied regulatory accounting in these years, the above amounts would have been reflected in the income statements in prior or future periods.

Renewable Energy Standard Tariff (REST)

Through December 31, 2009, and December 31, 2008, TEP collected $29 million and $9 million in customer surcharges, of which $18 million and $3 million were expensed for REST projects, respectively. At December 31, 2009 and December 31, 2008, $17 million and $6 million were recorded as a current regulatory liability to be used in future periods, respectively.

The approved REST adjustor mechanism allows TEP to file an application with the ACC to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s REST surcharge.

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The following table summarizes TEP’s regulatory assets and liabilities:

	December 31,
	2009			2008
	-Millions of Dollars-
Current Regulatory Assets
Property Tax Deferrals(1)	$	16		$	16
Derivative Instruments(2)		4			14
Deregulation Costs(3)		4			4
Other Current Regulatory Assets(4)		3			3
Total Current Regulatory Assets		27			37
Pension and Other Postretirement Benefits(7)		80			107
Regulatory Assets – Other
Derivative Instruments(2)		5			5
Deregulation Costs(3)		7			10
San Juan Coal Contract Amendment(5)		7			8
Final Mine Reclamation Costs(8)		9			8
Retiree Health Care Costs(8)		6			6
Unamortized Loss on Reacquired Debt(9)		4			5
Other Regulatory Assets(4)		1			1
Total Regulatory Assets — Other		39			43
Income Taxes Recoverable through Future Revenues(6)		18			20
Current Regulatory Liabilities
Over-Recovered Purchased Energy Costs		(9	)		(14	)
Renewable Energy Standards Tariff (REST)(10)		(17	)		(6	)
Other Current Regulatory Liabilities(4)		—			(1	)
Total Current Regulatory Liabilities		(26	)		(21	)
Other Regulatory Liabilities
Net Cost of Removal for Interim Retirements(11)		(163	)		(123	)
Over-Recovered Purchased Energy Costs		(17	)		(44	)
Total Other Regulatory Liabilities		(180	)		(167	)
Total Net Regulatory Assets (Liabilities)	$	(42	)	$	19

Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:

1.	Property Tax is recorded based on historical ratemaking treatment allowing recovery as costs are paid out, rather than as costs are accrued. TEP records a regulatory property tax asset related to its generation assets. While these assets do not earn a return, the costs are fully recovered in rates over an approximate six month period.
2.	Derivative Instruments represent the unrealized gains or losses on contracts entered into to hedge the variability of purchased energy costs and short-term wholesale sales that are expected to be recovered through the PPFAC. As a result of the 2008 TEP Rate Order and the approval of the PPFAC, TEP deferred the gains and losses on certain contracts that meet the recovery criteria under the PPFAC requirements.
3.	Deregulation costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders, the recovery of which has been authorized by the ACC in the 2008 TEP Rate Order. These assets are included in rate base and consequently earn a return. TEP will recover these costs through rates over a four-year period, beginning in December 2008.

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4.	TEP does not earn a return on these assets.
5.	San Juan Coal Contract Amendment costs of $15 million were incurred by TEP in 2000. In the 2008 TEP Rate Order, the ACC approved the recovery of $9 million of these costs over a nine-year period beginning in December 2008. The current portion is recorded in Other Assets. These assets do not earn a return.
6.	Income Taxes Recoverable Through Future Revenues, while not included in rate base, are amortized over the life of the assets. TEP does not earn a return on these assets.
7.	Pension Assets. TEP records a regulatory pension and postretirement benefit asset related to its employees. Based on past regulatory actions, TEP expects to recover these costs in rates. TEP does not earn a return on these assets.
8.	Final Reclamation and Retiree Health Care Costs represent costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners and Navajo. TEP is required to recognize the present value of its liability associated with final reclamation and retiree health care obligations. As TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners, TEP recorded a regulatory asset. TEP expects to recover these costs over the life of the mines, which is estimated to be between 17 and 34 years. TEP does not earn a return on these assets.
9.	Unamortized Loss on Reacquired Debt Costs is amortized for rate recovery over the remaining life of the related debt instruments over a period of 21 years. TEP does not earn a return on these costs.

Regulatory liabilities represent items that TEP expects to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:

10.

Renewable Energy Standards Tariff (REST) represents the REST surcharge collected in excess of qualified renewable expenditures.

11.

Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, general and intangible plant which are not yet expended. TEP collects through revenue the net cost of removal of interim retirements for generation plant, which it has not yet expended.

Future Implications of Discontinuing Application of Regulatory Accounting

TEP continues to apply regulatory accounting to its regulated operations. TEP regularly assesses whether it can continue to apply regulatory accounting to these operations. If TEP stopped applying regulatory accounting to its regulated operations, regulatory pension assets would be reflected in AOCI, and it would write-off the remaining related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement. Based on the regulatory assets balances, net of regulatory liabilities, at December 31, 2009, if TEP had stopped applying regulatory accounting to its regulated operations, it would have recorded an extraordinary after-tax gain of $74 million and an after-tax loss in AOCI of $48 million. While future regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if TEP stopped applying regulatory accounting.

UNS GAS RATES AND REGULATION

2008 General Rate Case Filing

In November 2008, UNS Gas filed a general rate case (on a cost of service basis) with the ACC requesting a total rate increase of 6% to cover a revenue deficiency of $10 million. The case uses a June 30, 2008 test year. UNS Gas expects the ACC to rule on its rate case in the first half of 2010.

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Purchase Gas Adjustor (PGA) Mechanism

UNS Gas’ retail rates include a 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. All purchased gas commodity costs, including transportation, increase the PGA bank, a balancing account. UNS Gas recovers these costs or returns amounts over-collected from/to ratepayers through a PGA rate. The PGA rate includes the following two components:

(1)

ThePGA factor, computed monthly, is a calculation of the twelve-month rolling weighted average gas cost, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve-month period. Effective December 2007, the ACC increased the annual cap on the maximum increase in the PGA factor from $0.10 per therm to $0.15 per therm in a twelve-month period.

(2)

At any time UNS Gas’ PGA bank balance is under-recovered, UNS Gas may request aPGA surchargewith the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed basis, UNS Gas is required to request aPGA surcreditwith the goal of returning the over-collected balance to customers over a period deemed appropriate by the ACC.

The PGA surcharge was $0.05 cents per therm from January 2007 through April 2007. The PGA surcredit was $0.04 cents per therm from October 2007 through April 2008. From May 2008 through October 2009, there was no surcharge or surcredit in effect. In October 2009, the ACC approved a $0.08 cent per therm PGA surcredit, effective November 2009 through October 2010 or until the balance reaches zero.

Based on current projections of gas prices, UNS Gas believes that the current PGA rates will allow it to timely recover its gas costs. However, changes in the market price for gas, sales volumes and surcharges could significantly change the PGA bank balance in the future.

The following table shows the balance of over-recovered purchased gas costs:

	December 31,
	2009			2008
	-Millions of Dollars-
Under (Over) Recovered Purchased Gas Costs – Regulatory Basis as Billed to Customers	$	(2	)	$	5
Estimated Purchased Gas Costs Recovered through Accrued Unbilled Revenues		(8	)		(10	)
Over-Recovered Purchased Gas Costs (PGA) Included as a Current Regulatory Liability	$	(10	)	$	(5	)

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Other Regulatory Assets and Liabilities

In addition to the Over-Recovered Purchased Gas Costs, UNS Gas has the following Regulatory Assets and Liabilities:

	December 31,
	2009			2008
	-Millions of Dollars-
Current Assets
Derivative Instruments	$	5		$	7
Pension Obligations		2			3
Other Regulatory Assets
Derivative Instruments		3			6
Other Regulatory Assets		1			1
Other Regulatory Liabilities
Net Cost of Removal for Interim Retirements		(20	)		(19	)

Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:

• Derivative instruments represent the unrealized gains or losses on contracts entered into to hedge the variability of purchased energy costs that are expected to be recovered through the PGA. UNS Gas does not earn a return on these costs.

• Pension assets represent the unfunded status of UNS Gas’ share of the UES pension and other postretirement benefit plans that it expects, based on past regulatory actions, to recover through rates. UNS Gas does not earn a return on these costs.

• Other Regulatory Assets consist of its 2007 rate case costs which are recoverable over 3 years. In addition, UNS Gas deferred its 2008 rate case costs and its low income assistance program costs. UNS Gas requested recovery of these costs in its 2008 rate case filing. UNS Gas does not earn a return on these costs.

Regulatory liabilities represent items that UNS Gas expects to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:

• Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations. These are amounts collected through revenue for the net cost of removal of interim retirements for which removal costs have not yet been expended. In December 2007, to comply with ACC requirements, UNS Gas reclassified $12 million of Net Cost of Removal for Interim Retirements from Accumulated Depreciation to a regulatory liability.

Income Statement Impact of Applying Regulatory Accounting

If UNS Gas had not applied regulatory accounting, net income would have been $6 million higher in 2009, and $9 million higher in 2007 as UNS Gas would have been able to recognize over-recovered purchased energy costs and unrealized gains on its commodity derivative instruments as a reduction to its expenses in the income statement rather than record a regulatory liability. Net income would have been $4 million lower in 2008 as UNS Gas would have recognized under-recovered purchased energy costs and unrealized losses on its commodity derivative instruments as an expense to its income statement rather than a reduction to its regulatory liability.

Future Implications of Discontinuing Application of Regulatory Accounting

UNS Gas regularly assesses whether it can continue to apply regulatory accounting. If UNS Gas stopped applying regulatory accounting to its regulated operations, regulatory pension assets would be reflected in AOCI and UNS Gas would write-off the remaining related balance of its regulatory assets as an expense and 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 regulatory accounting to its regulated operations, it would have recorded an extraordinary after-tax gain of $13 million and an after-tax loss in AOCI of $1 million at December 31, 2009. Discontinuing application of regulatory accounting would not affect UNS Gas cash flows.

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UNS ELECTRIC RATES AND REGULATION

2008 UNS Electric Rate Order

In the May 2008 rate order, the ACC approved a rate increase of 2.5% ($4 million) effective June 2008. As a result of the May 2008 rate order limiting recovery of deferred rate case costs, UNS Electric expensed $0.3 million of the $0.6 million deferred costs in May 2008.

2009 General Rate Case Filing

In April 2009, UNS Electric filed a general rate case with the ACC (on a cost of service basis) requesting a total rate increase of 7.4% to cover a revenue deficiency of $13.5 million. The case uses a December 31, 2008 test year. Hearings before an ACC administrative law judge concluded in February 2010. UNS Electric expects the ACC to rule on its rate case in the second half of 2010.

Purchased Power and Fuel Adjustment Clause (PPFAC)

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 under-recovered or return over-recovered costs. Allowable PPFAC costs include fuel, purchased power (less proceeds from most wholesale sales) and transmission costs. The PPFAC approved in UNS Electric’s last rate case in May 2008, allows recovery of fuel and purchased power costs incurred to provide service to retail customers, including demand charges and the prudent costs of contracts for hedging fuel and purchased power costs.

The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on the difference between forecasted fuel and purchased power costs and the base cost of fuel and purchased power included in base rates. The true-up component reconciles the previous year’s actual fuel and purchased power costs with the amounts collected through base and PPFAC rates and credits or recovers that amount to or from customers in the subsequent PPFAC year. The PPFAC rate will be updated on June 1 of each year, beginning June 1, 2009.

On June 1, 2009, a PPFAC credit of approximately 1.06 cents per kWh took effect. The PPFAC rate from June 1, 2008 to May 31, 2009, was a charge of approximately 1.5 cents per kWh. Base rates of approximately 7.1 cents per kWh have been in effect since June 1, 2008. The retail rates prior to June 2008, included a charge for fuel and purchased power of approximately 7 cents per kWh (base rate recovery of 5.2 cents per kWh and a transmission surcharge of 1.8 cents per kWh).

The following table shows the balance of over-recovered purchased power costs:

	December 31,			December 31,
	2009			2008
	-Millions of Dollars-
(Over-)Recovered Purchased Power Costs – Regulatory Basis as Billed to Customers	$	(1	)	$	—
Estimated Purchased Power Costs Recovered through Accrued Unbilled Revenues		(4	)		(7	)
(Over-)Recovered Purchased Power Costs (PPFAC) Included as a Current Regulatory Liability	$	(5	)	$	(7	)

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Purchased Power Agreement

In June 2008, UED and UNS Electric entered into a 5-year Power Purchase Agreement (PPA) under which UED sells all the output of BMGS to UNS Electric. The PPA is a tolling arrangement in which UNS Electric takes operational control of BMGS and assumes all risk of operation and maintenance costs, including fuel. UNS Electric accounts for the PPA as an operating lease. The costs associated with the PPA are recoverable through UNS Electric’s PPFAC.

Regulatory Assets and Liabilities

UNS Electric’s regulatory assets and liabilities were as follows:

	December 31,
	2009			2008
	-Millions of Dollars-
Current Regulatory Assets
Derivatives	$	9		$	17
Other Regulatory Assets
Derivative Instruments		2			7
Pension Assets		2			3
Other		1			—
Current Regulatory Liabilities
REST		(1	)		(1	)
Over-Recovered Purchased Power Costs		(5	)		(6	)
Other Regulatory Liabilities
Net Cost of Removal for Interim Retirements		(12	)		(11	)

Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:

• Derivative instruments represent the unrealized gains or losses on contracts entered into to hedge the variability of purchased energy costs that are expected to be recovered through the PPFAC. UNS Electric does not earn a return on these costs.

• Pension assets represent the unfunded status of UNS Electric’s share of the UES pension and other postretirement benefit plans that it expects, based on past regulatory actions, to recover through rates. UNS Electric does not earn a return on these costs.

• Rate case costs included in Other Regulatory Assets are included in rate base and consequently earn a return. The recovery period is 3 years.

Regulatory liabilities represent items that UNS Electric expects to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:

• Renewable Energy Standards Tariff (REST) represents the REST surcharge collected in excess of qualified renewable expenditures. The ACC approved a REST surcharge for UNS Electric, effective June 1, 2008, to allow UNS Electric to recover the cost of qualified renewable expenditures, such as payments to customers who have renewable energy resources or the incremental cost of renewable power generated or purchased by UNS Electric. Any surcharge collected in excess of qualified renewable expenditures will be reflected in the financial statements as a current regulatory liability. Conversely, qualified renewable expenditures in excess of the REST surcharge will be reflected as a current regulatory asset. The REST plan includes an adjustor mechanism which allows UNS Electric to file an application with the ACC to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s REST surcharge.

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• 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 PPFAC approved by the ACC. The PPFAC allows for a revenue surcharge or surcredit (that adjusts the customer’s rate for delivered purchased power) to collect or return under- or over-recovery of costs.

• Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations. These are amounts collected through revenue for the net cost of removal of interim retirements for which removal costs have not yet been expended. In June 2008, to comply with ACC expectations, UNS Electric reclassified $7 million of Net Cost of Removal for Interim Retirements from Accumulated Depreciation to a regulatory liability.

Income Statement Impact of Applying Regulatory Accounting

If UNS Electric had not applied regulatory accounting, net income would have been $7 million higher in 2009 and $1 million higher in 2007, as UNS Electric would have been able to recognize over-recovered purchased power costs and unrealized gains on its commodity derivative instruments as a credit to the income statement rather than record an increase to regulatory liabilities. If UNS Electric had not applied regulatory accounting, net income would have been $15 million lower in 2008 as UNS Electric would have recognized under-recovered purchased energy and unrealized losses on its commodity derivative instruments as an expense to its income statement, rather than as regulatory assets or a reduction to its regulatory liabilities.

Future Implications of Discontinuing Application of Regulatory Accounting

UNS Electric regularly assesses whether it can continue to apply regulatory accounting to its operations. If UNS Electric stopped applying regulatory accounting to its regulated operations, regulatory pension assets would be reflected in AOCI and it would write-off the remaining related balances 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 Electric had stopped applying regulatory accounting to its regulated operations, it would have recorded an extraordinary after-tax gain of $3 million and an after-tax loss in AOCI of $1 million at December 31, 2009. Discontinuing application of regulatory accounting would not affect UNS Electric’s cash flows.

NOTE 3. SEGMENT AND RELATED INFORMATION

We have three reportable segments that are determined based on the way we organize our operations and evaluate performance:

(1)	TEP, a vertically integrated electric utility business, is our largest subsidiary.
(2)	UNS Gas is a regulated gas distribution utility business.
(3)	UNS Electric is a regulated electric distribution utility business.

The UniSource Energy and UES holding companies, Millennium, and UED are included in All Other.

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Reconciling adjustments consist of the elimination of intersegment revenue which were due to the following transactions and they are eliminated in consolidation:

	Reportable Segments
			UNS		UNS
	TEP		Gas		Electric		Other
	-Millions of Dollars-
Intersegment Revenue
2009:
Wholesale Sales – TEP to UNSE	$	23	$	—	$	—	$	—
Wholesale Sales – UNSE to TEP		—		—		4		—
Wholesale Sales – UED to UNSE		—		—		—		12
Gas Revenue – UNSG to UNSE & UED		—		5		—		—
Other Revenue – TEP to Affiliates(1)		8		—		—		—
Other Revenue – Millennium to TEP & UNSE(2)		—		—		—		16
Other Revenue – TEP to UNSE(3)		3		—		—		—
Total Intersegment Revenue	$	34	$	5	$	4	$	28
2008:
Wholesale Sales – TEP to UNSE	$	24	$	—	$	—	$	—
Wholesale Sales – UNSE to TEP		—		—		9		—
Wholesale Sales – UED to UNSE		—		—		—		7
Gas Revenue – UNSG to UNSE & UED		—		8		—		—
Other Revenue – TEP to Affiliates(1)		8		—		—		—
Other Revenue – Millennium to TEP & UNSE(2)		—		—		—		16
Other Revenue – TEP to UNSE(3)		2		—		—		—
Total Intersegment Revenue	$	34	$	8	$	9	$	23
2007:
Other Revenue – TEP to Affiliates(1)	$	7	$	—	$	—	$	—
Other Revenue – Millennium to TEP &UNSE(2)		—		—		—		15
Total Intersegment Revenue	$	7	$	—	$	—	$	15

(1)	TEP provides corporate services (finance, accounting, tax, information technology services, etc.) to UniSource Energy and its subsidiaries. See Note 14.
(2)	A Millennium subsidiary provides a supplemental workforce and meter reading services to TEP and UNS Electric.
(3)	TEP provides control area services to UNS Electric. See Note 14.

Other significant reconciling adjustments include intercompany interest between UniSource Energy and UED, the elimination of investments in subsidiaries held by UniSource Energy and reclassifications of deferred tax assets and liabilities.

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

	Reportable Segments
				UNS			UNS			All			Reconciling			UniSource
2009	TEP			Gas			Electric			Other			Adjustments			Energy
	-Millions of Dollars-
Income Statement
Operating Revenues – External	$	1,063		$	148		$	183		$	—		$	—		$	1,394
Operating Revenues – Intersegment		34			5			4			28			(71	)		—
Depreciation and Amortization		153			7			14			2			—			176
Interest Income		11			—			—			1			—			12
Interest Expense		85			6			7			11			—			109
Income Tax Expense (Benefit)		55			5			4			1			(1	)		64
Net Income (Loss)		89			7			6			2			—			104
Cash Flow Statement
Capital Expenditures		(235	)		(14	)		(28	)		(10	)		—			(287	)
Balance Sheet
Total Assets		2,914			307			273			1,107			(1,000	)		3,601
Investments in Equity Method Entities		—			—			—			10			—			10

	Reportable Segments
				UNS			UNS			All			Reconciling			UniSource
2008	TEP			Gas			Electric			Other			Adjustments			Energy
	-Millions of Dollars-
Income Statement
Operating Revenues – External	$	1,045		$	166		$	186		$	—		$	—		$	1,397
Operating Revenues – Intersegment		34			8			9			23			(74	)		—
Depreciation and Amortization		126			7			14			1			—			148
Amortization of Transition Recovery Asset		24			—			—			—			—			24
Interest Income		10			—			—			1			—			11
Net Loss from Equity Method Entities		—			—			—			(2	)		—			(2	)
Interest Expense		96			7			7			11			(2	)		119
Income Tax Expense (Benefit)		11			6			2			(2	)		—			17
Net Income (Loss)		4			9			4			16			(19	)		14
Cash Flow Statement
Capital Expenditures		(295	)		(16	)		(30	)		(16	)		—			(357	)
Balance Sheet
Total Assets		2,842			294			285			1,061			(972	)		3,510
Investments in Equity Method Entities		—			—			—			25			—			25

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	Reportable Segments
				UNS			UNS			All			Reconciling			UniSource
2007	TEP			Gas			Electric			Other			Adjustments			Energy
	-Millions of Dollars-
Income Statement
Operating Revenues – External	$	1,064		$	151		$	169		$	(3	)	$	—		$	1,381
Operating Revenues – Intersegment		7			—			—			15			(22	)		—
Depreciation and Amortization		120			8			13			—			—			141
Amortization of Transition Recovery Asset		78			—			—			—			—			78
Interest Income		16			1			—			2			—			19
Interest Expense		111			7			6			8			—			132
Income Tax Expense (Benefit)		36			3			3			(3	)		—			39
Net Income (Loss)		53			4			5			(4	)		—			58
Cash Flow Statement
Capital Expenditures		(162	)		(23	)		(38	)		(22	)		—			(245	)
Balance Sheet
Total Assets		2,573			276			231			1,077			(971	)		3,186
Investments in Equity Method Entities		3			—			—			28			—			31

NOTE 4. COMMITMENTS AND CONTINGENCIES

TEP COMMITMENTS

Firm Purchase Commitments

At December 31, 2009, TEP had various firm non-cancelable purchase commitments and operating leases as described in the table below.

	Purchase Commitments
	2010		2011		2012		2013		2014		Thereafter		Total
	-Millions of Dollars-
Fuel (including Transportation)	$	89	$	51	$	42	$	39	$	37	$	142	$	400
Purchased Power		44		12		4		2		2		2		66
Transmission		2		2		2		2		2		2		12
Total Firm Purchase Commitments		135		65		48		43		41		146		478
Operating Lease Payments		1		—		—		—		—		—		1
Total Unrecognized Firm Commitments	$	136	$	65	$	48	$	43	$	41	$	146	$	479

Fuel and Purchased Power Contracts

TEP has long-term contracts for the purchase and delivery of coal and natural gas with various expiration dates from 2010 through 2020. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. The table above also includes approximately $1 million under take-or-pay arrangements if certain minimum quantities are not transported in 2010. TEP expects to spend more to meet its fuel requirements than the minimum purchase obligations outlined above.

TEP has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in various years between 2010 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2009.

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Starting January 1, 2009, fuel, purchased power and transmission costs are recoverable from customers through a PPFAC.

TEP has, subject to ACC approval, entered into three long-term purchase power agreements with developing renewable energy generation facilities that extend for periods of 15 to 20 years. The facilities are expected to begin commercial operation between 2010 and 2012. TEP is required to purchase the full output of each facility. Expected capacities range from 2 MW to 25 MW. TEP is only obligated to pay for actual energy delivered. There are no minimum payment obligations under these contracts.

Operating Leases

TEP’s aggregate operating lease expense, which is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates, totaled $1 million in 2009, $1 million in 2008 and $2 million in 2007.

Environmental Regulation

Clean Air Act Requirements

TEP generating facilities are subject to EPA limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $24 million in 2009, $73 million in 2008 and $7 million in 2007 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan described below. TEP expects to capitalize environmental compliance costs of $8 million in 2010 and $5 million in 2011. In addition, TEP recorded operating expenses of $13 million in 2009, $14 million in 2008 and $10 million in 2007 related to environmental compliance. TEP expects environmental expenses to be $11 million in 2010.

As a result of a 2005 settlement agreement between PNM, environmental activist groups, and the New Mexico Environment Department (PNM Consent Decree), the co-owners of San Juan installed new pollution control equipment at the generating station to reduce mercury, particulate matter, NOx, and SO₂emissions. TEP owns 50% of San Juan Units 1 and 2. The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan. In 2008 and 2007, TEP’s share of stipulated penalties at San Juan was $1 million and $2 million, respectively. TEP can not deduct these penalties for income tax purposes. TEP did not incur any stipulated penalties at San Juan in 2009. The installation of new pollution control equipment designed to remedy all emission violations was completed in 2008 for San Juan Unit 1 and in 2009 at San Juan Unit 2.

In April 2009, APS received a request from the EPA under section 114 of the Clean Air Act seeking information about Four Corners. Four Corners, which is operated by APS, is comprised of five coal-fired generating units. TEP has a 7% ownership interest in two units, totaling 100 MW. APS has responded to the EPA’s request. TEP cannot predict the timing or outcome of this matter.

In 1993, the EPA allocated TEP’s generating units SO₂ Emission Allowances based on past operational history. Beginning in 2000, TEP’s generating units were required to hold SO₂ Emission Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years. To date, TEP has had sufficient SO₂ Emission Allowances to comply with the SO₂ regulations. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may reduce operating efficiency.

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UNS GAS and UNS ELECTRIC COMMITMENTS

At December 31, 2009, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in the table below.

	Purchase Commitments
	2010		2011		2012		2013		2014		Thereafter		Total
	-Millions of Dollars-
Total Unrecognized Firm Commitments – Fuel	$	19	$	14	$	5	$	3	$	3	$	23	$	67

UNS Gas purchases gas from various suppliers at market prices. However, UNS Gas’ risk of loss due to increased costs (as a result of changes in the market price of fuel) is mitigated through the use of the PGA, which provides for pass-through of most fuel costs to customers. UNS Gas’ forward gas purchase agreements expire through 2012. Certain of these contracts are at a fixed price per mmbtu and others are indexed to natural gas prices. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2011 and 2024.

At December 31, 2009, UNS Electric had various firm non-cancelable purchase commitments as described in the table below.

	Purchase Commitments
	2010		2011		2012		2013		2014		Thereafter		Total
	-Millions of Dollars-
Purchased Power	$	67	$	23	$	14	$	47	$	—	$	—	$	151
Transmission		2		2		1		—		—		—		5
Total Unrecognized Firm Commitments	$	69	$	25	$	15	$	47	$	—	$	—	$	156

UNS Electric enters into agreements with various energy suppliers for purchased power at market prices to meet its energy requirements. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in various years through 2013. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on market prices as of December 31, 2009.

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 2011 and 2017. However, the effects of both purchased power and transmission cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

UNS Electric has subject to ACC approval, entered into one long-term purchase power agreement with a renewable energy generation facility that extends for 20 years. The facility is expected to begin commercial operation in 2011. UNS Electric is required to purchase the full output of the facility with an expected minimum capacity of 7 MW. UNS Electric is only obligated to pay for actual energy delivered. There is no minimum payment obligation under this contract.

In addition, UNS Gas and UNS Electric’s combined operating lease expense, which is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates was $1 million in each of the years 2009, 2008 and 2007. UNS Gas and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are approximately $1 million per year from 2010 to 2011 and $2 million thereafter.

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MILLENNIUM COMMITMENTS

Millennium has a remaining obligation to fund investments for capital and operations of less than $1 million over the next 3 years.

UNISOURCE ENERGY COMMITMENTS

UniSource Energy purchased land and plans to construct a new headquarters building on the site. The construction contract has not yet been executed; however, firm commitments related to the design phase have been made requiring expenditures of $3 million over the next 18 months.

TEP CONTINGENCIES

El Paso Electric Transmission

In 2006, El Paso filed a complaint to the FERC claiming that TEP must request service under El Paso’s Open Access Transmission Tariff (OATT) in order to transmit power from Luna to TEP’s system. TEP filed a counter complaint stating that TEP has existing rights under a 1982 Tucson-El Paso Transmission Agreement and, therefore, is not required to pay for transmission service under El Paso’s OATT. On November 13, 2008, the FERC issued an order supporting TEP’s position. In December 2008, El Paso refunded to TEP $10 million paid for transmission service from Luna during the pendency of this dispute and interest of $1 million. On January 14, 2009, FERC granted El Paso’s request for a rehearing of this matter. TEP is no longer accruing for transmission service under El Paso’s OATT, however, due to the rehearing, TEP deferred recognition of a reduction in transmission expense.

In December 2008, TEP filed a complaint in the United States Federal District Court against El Paso seeking a $2 million reimbursement from El Paso for transmission charges paid by TEP to PNM for transmission service in an attempt to mitigate TEP’s damages before FERC issued its decision in November 2008. On September 10, 2009, the District Court denied El Paso’s motion to dismiss TEP’s complaint and stayed the proceeding pending a final resolution of the FERC proceedings and any appeal. TEP cannot predict the timing or outcome of these lawsuits.

Claims Related to Navajo Generating Station

In June 1999, the Navajo Nation filed suit against Salt River Project, several Peabody Coal Company entities (including Peabody Western Coal Company, the coal supplier to Navajo Generating Station), Southern California Edison Company, and other defendants in the U.S. District Court for the District of Columbia (D.C. Lawsuit). The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate of the lease agreements under which Peabody mines coal by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River Project. In March 2008, the U.S. District Court lifted a stay that had been in place since October 2004 and referred pending discovery related motions to a Magistrate judge. In June 2009, the District Court ordered the parties to complete fact discovery by February 2010. In February 2010, the District Court issued an Amended Scheduling Order which extends the February 2010 discovery deadline and sets other procedural deadlines at various dates between March 2010 and February 2011.

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In 2004, Peabody Western Coal Company (Peabody) filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP (7.5% owner), for reimbursement of royalties and other costs arising out of the D.C. Lawsuit. In July��2008, the parties entered into a joint stipulation of dismissal of these claims which was approved by the Circuit Court. TEP cannot predict whether the lawsuit will be refiled based upon the final outcome of the D.C. Lawsuit.

Claims Related to San Juan Coal Company

San Juan Coal Company, the coal supplier to San Juan, through leases with the federal government and the State of New Mexico, owns coal interests with respect to an underground mine. Certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties in the area of the underground mine. These gas producers allege that San Juan Coal Company’s underground coal mining operations have or will interfere with their gas production and will reduce the amount of natural gas that they would otherwise be entitled to recover. San Juan Coal Company has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity was close enough to warrant shutting down the well. These settlements, however, do not resolve all potential claims by gas producers in the underground mine area. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at 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 corresponding coal supply agreement. At December 31, 2009 and 2008, TEP recorded liabilities of $10 million and $9 million, respectively, based on our $17 million obligation at the expiration dates of the coal supply agreements in 2011 through 2017.

TEP’s PPFAC, as approved in the 2008 TEP Rate Order, allows TEP to pass-through most fuel costs, including final reclamation costs, to customers. Therefore, in 2008, when TEP reapplied regulatory accounting to its generation operations, TEP reclassified these costs from fuel expense to a regulatory asset. TEP will increase the regulatory asset and the liability over the remaining life of the coal supply agreements on an accrual basis, and will recover the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Amounts recorded for final reclamation are subject to various assumptions, such as estimating the costs of reclamation, when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreement term. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition occurs over the remaining terms of its coal supply agreements.

TEP Wholesale Accounts Receivable and Allowances

TEP’s Accounts Receivable from Electric Wholesale Sales included $16 million of receivables at December 31, 2008 related to sales to the California Power Exchange (CPX) and the California Independent System Operator (CISO) in 2001 and 2000. TEP had recognized a related reserve of $14 million. There are currently pending several proceedings 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, where the parties are seeking refunds of $4 million. TEP’s cost to litigate these matters is expected to increase substantially as the proceedings enter the trial phase in 2010. In light of this, TEP re-engaged in settlement discussions with the plaintiffs in the fourth quarter of 2009. In December 2009, based on those settlement discussions, TEP wrote off the remaining receivable balance of $2 million and accrued an additional liability of $2 million. TEP believes it is adequately reserved but we cannot predict the final outcome of the settlement discussions or lawsuits at this time.

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Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile transmission line from Tucson to Nogales, Arizona. UNS Electric’s participation in 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 a route identified as the Western Corridor route subject to a number of conditions, including obtaining all required permits from state and federal agencies. The U.S. Forest Service subsequently identified a preference for a route identified as the Central Corridor route in the final Environmental Impact Statement for the project. TEP is considering options for the project including potential new routes. If a decision is made to pursue an alternative route, approvals will be needed from the ACC, the Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and Water Commission. As of December 31, 2009, TEP had capitalized $11 million related to the project, including $2 million of land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes cost recovery is probable for prudent and reasonably incurred costs related to the project as a consequence of the ACC’s requirement for a second transmission line serving the Nogales, Arizona area.

Sierra Club San Juan Allegations

In December 2009, the Sierra Club sent TEP, the other owners of the San Juan Generating Station (SJGS), and San Juan Coal Company (SJCC), a Notice of Intent to Sue (RCRA Notice) under the Resource Conservation and Recovery Act (RCRA). The RCRA Notice alleges that certain activities at SJGS and the San Juan mine associated with the treatment, storage and disposal of coal and coal combustion by-products (CCBs) are causing imminent and substantial harm to the environment and that placement of CCBs at the mine constitute “open dumping” in violation of RCRA. Additionally, TEP has been informed that the Sierra Club sent SJCC a separate Notice of Intent to Sue (SMCRA Notice) under the Surface Mine Control and Reclamation Act (SMCRA) in December 2009. The SMCRA Notice similarly alleges damage to the environment due to activities at the San Juan mine, including the placement of CCBs from SJGS in the surface pits at the mine. Both Notices state Sierra Club’s intent to file citizens’ suits to pursue these claims upon expiration of the RCRA and SMRCA statutory notice periods. If suits are filed, potential remedies include the imposition of civil penalties and injunctive relief. TEP and Public Service Company of New Mexico, the SJGS operator, plan an aggressive defense of the RCRA claims. TEP cannot predict the outcome of these matters at this time.

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 senior unsecured notes issued by UNS Gas ($100 million) and by UNS Electric ($100 million),

• UES’ guarantee of the $60 million UNS Gas/UNS Electric Revolver, and

• UniSource Energy’s guarantee of approximately $2 million in building lease payments for UNS Gas, and

• UniSource Energy’s guarantee of the $26 million of outstanding loans under the UED Credit Agreement. In February 2010, UED increased its borrowings under this agreement to $35 million. As a result, UniSource Energy increased its guarantee to $35 million.

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To the extent liabilities exist under these contracts, the liabilities are included in our consolidated balance sheets.

In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4. We have indemnified the seller of Sundt Unit 4 from any sales, use, transfer or similar taxes or fees due relating to the purchase. The terms of the indemnification do not include a limit on potential future payments; however, we believe that the parties to the agreement have abided by all tax laws and we do not have any additional tax obligations. We have not made any payments under the terms of this indemnification to date.

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NOTE 5. UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

The following table shows Utility Plant in Service by company and major class.

	December 31, 2009
	- Millions of Dollars -
					UNS				UniSource
	TEP		UNS Gas		Electric		UED		Energy
Plant in Service:
Electric Generation Plant	$	1,527	$	—	$	17	$	61	$	1,605
Electric Transmission Plant		682		—		30		4		716
Electric Distribution Plant		1,110		—		185		—		1,295
Gas Distribution Plant		—		216		—		—		216
Gas Transmission Plant		—		18		—		—		18
General Plant		178		15		11		—		204
Computer Software		82		1		4		—		87
Electric Plant Held for Future Use		5		—		1		—		6
Total Plant in Service	$	3,584	$	250	$	248	$	65	$	4,147
Utility Plant under Capital Leases	$	720	$	—	$	1	$	—	$	721

	December 31, 2008
	- Millions of Dollars -
					UNS				UniSource
	TEP		UNS Gas		Electric		UED		Energy
Plant in Service:
Electric Generation Plant	$	1,398	$	—	$	17	$	58	$	1,473
Electric Transmission Plant		660		—		29		4		693
Electric Distribution Plant		1,044		—		163		—		1,207
Gas Distribution Plant		—		201		—		—		201
Gas Transmission Plant		—		18		—		—		18
General Plant		173		14		9		—		196
Computer Software		71		1		4		—		76
Electric Plant Held for Future Use		5		—		1		—		6
Total Plant in Service	$	3,351	$	234	$	223	$	62	$	3,870
Utility Plant under Capital Leases	$	701	$	—	$	1	$	—	$	702

TEP’S UTILITY OPERATING STATISTICS

	For Years Ended December 31,
	2009		2008		2007		2006		2005
Generation and Purchased Power — kWh (000)
Remote Generation (Coal)		9,576,873		10,438,864		11,001,318		10,854,710		10,059,315
Local Tucson Generation (Oil, Gas & Coal)		711,420		1,039,362		1,088,778		966,476		1,165,001
Purchased Power		3,085,805		2,947,749		2,046,864		1,680,495		1,638,737
Total Generation and Purchased Power		13,374,098		14,425,975		14,136,960		13,501,681		12,863,053
Less Losses and Company Use		948,463		954,643		944,024		885,120		806,168
Total Energy Sold		12,425,635		13,471,332		13,192,936		12,616,561		12,056,885

TEP’s unamortized computer software costs were $31 million as of December 31, 2009 and $29 million as of December 31, 2008. UNS Gas and UNS Electric had unamortized computer software costs of $1 million as of December 31, 2009 and as of December 31, 2008.

All TEP Utility Plant under Capital Leases is used in TEP’s generation operations and amortized over the primary lease term as described in Notes 1 and 6. The amortization expense on capital lease assets was $26 million in 2009, and $25 million in each of 2008 and 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

The following table reconciles the gross investment in utility plant to net investment in utility plant, segregated between regulated and non-regulated utility plant.

	December 31, 2009
	Regulated										Non- Regulated
							UNS		UNS
							Gas		Electric				UniSource
			TEP		Total		Total		Total		UED		Energy
	T&D		Gen		Plant		Plant		Plant		Plant		Total Plant
	-Millions of Dollars-
Gross Plant in Service	$	2,057	$	1,527	$	3,584	$	250	$	248	$	65	$	4,147
Less Accumulated
Depreciation and Amortization		913		669		1,582		15		52		3		1,652
Net Plant in Service	$	1,144	$	858	$	2,002	$	235	$	196	$	62	$	2,495

	December 31, 2008
	Regulated										Non- Regulated
							UNS		UNS
							Gas		Electric				UniSource
			TEP		Total		Total		Total		UED		Energy
	T&D		Gen		Plant		Plant		Plant		Plant		Total Plant
	-Millions of Dollars-
Gross Plant in Service	$	1,953	$	1,398	$	3,351	$	234	$	223	$	62	$	3,870
Less Accumulated
Depreciation and Amortization		865		667		1,532		9		39		1		1,581
Net Plant in Service	$	1,088	$	731	$	1,819	$	225	$	184	$	61	$	2,289

The category T&D includes all transmission and distribution Plant in Service. The category Gen includes the generation assets. Rates for utility operations appearing in this table are set by the ACC on a cost-of-service basis, and are accounted for under the provisions of regulatory accounting for all periods except those assets owned by UED.

The depreciable lives as of December 31, 2009 were as follows:

			UNS Gas,
			UNS Electric
Major Class of Utility Plant in Service	TEP		& UED
Electric Generation Plant	7-59 years		38-49 years
Electric Transmission Plant	10-50 years		20-50 years
Electric Distribution Plant	28-60 years		23-50 years
Gas Distribution Plant		n/a	30-65 years
Gas Transmission Plant		n/a	30-55 years
General Plant	5-31 years		5-40 years
Intangible Plant	3-15 years		5-32 years

SeeTEP Utility Plantin Note 1 andTEP Capital Lease Obligationsin Note 6.

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Audit Committee
2/19/10

JOINTLY-OWNED FACILITIES

At December 31, 2009, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:

				Plant		Construction
	Ownership			in		Work in		Accumulated
	Percentage			Service		Progress		Depreciation
	-Millions of Dollars-
San Juan Units 1 and 2		50.0	%	$	416	$	5	$	209
Navajo Station Units 1, 2 and 3		7.5			138		3		86
Four Corners Units 4 and 5		7.0			89		5		67
Transmission Facilities		7.5 to 95.0			243		—		177
Luna Energy Facility		33.3			50		—		—
Total				$	936	$	13	$	539

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 4 for commitments related to TEP’s jointly-owned facilities.

NOTE 6. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

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

UNISOURCE ENERGY DEBT

Convertible Senior Notes

UniSource Energy has $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 27.427 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $36.46 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 if 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

TEP DEBT

2009 Sale and Redemption of Bonds

In October 2009, the Pima Authority issued approximately $80 million of its 2009 Series A tax-exempt pollution control bonds (2009 Pima A San Juan Bonds) for TEP’s benefit. At the same time, the Coconino County, Arizona Pollution Control Corporation (Coconino PCC) issued approximately $15 million of its 2009 Series A tax-exempt pollution control bonds (2009 Coconino A Bonds) for TEP’s benefit. The 2009 Pima A San Juan Bonds are unsecured, bear interest at a rate of 4.95%, mature on October 1, 2020, and are not callable prior to maturity. The 2009 Coconino A Bonds are unsecured, bear interest at 5.125%, mature on October 1, 2032, and are callable in whole or in part for cash at par beginning October 1, 2019. Semi-annual interest payments on both series of bonds are payable beginning April 1, 2010. TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs for each through the respective maturity dates.

The proceeds from the issuance of the 2009 Pima A San Juan Bonds and the 2009 Coconino A Bonds were deposited with a trustee and were used on November 2, 2009, to redeem approximately $80 million of 6.95% 1997 Series A City of Farmington, New Mexico Pollution Control Bonds and approximately $15 million of 7.0% 1997 Series B Coconino County, Arizona Pollution Control Bonds.

Collateral Trust Bonds

In 1998, TEP issued a total of $140 million, 7.5% Collateral Trust Bonds, due August, 2008. TEP retired these bonds in 2008. See 2008 Pima A and 2008 Pima B Bonds below.

2008 Pima A Bonds

In March 2008, The Industrial Development Authority of Pima County (Pima Authority) issued, for the benefit of TEP, approximately $91 million of its 2008 Series A tax-exempt, unsecured, 6.375% bonds (2008 Pima A Bonds) due September 1, 2029. The proceeds were used to redeem a corresponding principal amount of bonds previously issued by the Pima Authority for TEP’s benefit, which TEP repurchased in 2005. In 2005, TEP did not cancel the repurchased bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. As holder of the repurchased bonds, TEP received the payment of the redemption price.

TEP used the redemption proceeds to repay $75 million in revolving loans outstanding under its revolving credit facility. The remaining proceeds were used in May 2008 to redeem $10 million of the $138 million 7.5% Collateral Trust Bonds due August 2008. TEP capitalized $1 million of costs related to the issuance of the 2008 Pima A Bonds and will amortize these costs through August 2029, the term of the bonds.

Interest on the 2008 Pima A Bonds is payable semi-annually, commencing on September 1, 2008.

Beginning in March 2013, TEP will have the option to redeem the 2008 Pima A Bonds, in whole or in part, for cash, at a price equal to 100% of the principal amount, plus accrued interest.

2008 Pima B Bonds

In June 2008, the Pima Authority issued for TEP’s benefit, $130 million of its 2008 Series B tax-exempt variable rate IDBs (2008 Pima B Bonds) due September 1, 2029. The 2008 Pima B Bonds were supported by a letter of credit (LOC) issued under the TEP 2008 Letter of Credit Facility. The LOC was secured by $132 million of 1992 Mortgage Bonds. The proceeds were used to redeem a corresponding principal amount of bonds previously issued by the Pima Authority for TEP’s benefit which TEP repurchased in 2005. TEP did not cancel the repurchased bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. As holder of the repurchased bonds being redeemed, TEP received the payment of the redemption price.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

TEP deposited the redemption proceeds with the trustee for its 7.5% Collateral Trust Bonds. In August 2008, the deposit was applied to the payment of $128 million of principal plus $5 million of accrued interest on such bonds at maturity. TEP was required to deposit these funds with the trustee pursuant to amendments dated May 30, 2008 to the TEP Credit Agreement and the 2008 TEP Letter of Credit Facility. These amendments allowed TEP to exclude the $128 million of Collateral Trust Bonds to be retired in August 2008 from Total Indebtedness for the calculation of its leverage ratio covenant at June 30, 2008.

While in the variable rate mode, the 2008 Pima B Bonds accrued interest at a rate which reset weekly. The average weekly interest rate on the 2008 Pima B Bonds ranged from 0.50% to 8.25%, with an average rate of 2.03% for 2008, and from 0.15% to 0.75%, with an average rate of 0.34% for 2009. The peak weekly rate of 8.25% occurred in mid-September 2008, when the short-term debt markets began to experience significant disruptions related to the creditworthiness of several large financial institutions. The rate on this debt was 0.30% and 0.75%, respectively, as of December 31, 2009 and 2008. TEP paid a remarketing fee of 10 basis points (bps) to the remarketing agent of the bonds, an LOC fee of 65 bps to the lenders, and an LOC issuing fee of 12.5 bps to the issuing bank.

In January 2010, TEP converted the interest on the 2008 Pima B to a fixed rate. The Pima B Bonds were reoffered in January 2010, with a term rate of 5.75% through maturity of September 2029. Interest is payable semi-annually beginning June 1, 2010. The bonds are callable at par beginning January 2015. Accordingly, the associated LOC was terminated on January 12, 2010 and the mortgage bonds were canceled.

TEP capitalized $1 million of costs related to the issuance of the 2008 Pima B Bonds and will amortize these costs through August 2029. TEP capitalized approximately $2 million of costs related to the reoffering in January 2010 and will amortize these costs through August 2029.

Variable Rate Industrial Development Bonds (IDBs)

Weighted average interest rates on this variable rate tax-exempt IDBs debt ranged from 0.25% to 0.79% during 2009, and from 0.55% to 8.09% during 2008, and the average interest rate on such debt was 0.41% in 2009, and 2.11% in 2008. In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate industrial development bonds to a fixed rate of 2.4% from September 2009 through September 2014.

1992 Mortgage

TEP’s 1992 Mortgage 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 $2 billion at December 31, 2009.

TEP CAPITAL LEASE OBLIGATIONS

In January 2010, TEP entered into an agreement to purchase 100% of the equity interest in Sundt Unit 4 from the owner participant for $52 million. The purchase price is subject to increase by 0.75% of the purchase price per month in the event that the purchase occurs after March 31, 2010. TEP expects to finalize the purchase prior to March 31, 2010. Following the completion of the transaction, TEP expects to repay the remaining Sundt Unit 4 lease obligation of $5 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

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

• 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.

Effective with commercial operation of Springerville Unit 3 in July 2006 and Springerville Unit 4 in December 2009, Tri-State and SRP are reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including 14% each of the Springerville Common Lease payments and 17% each of the Springerville Coal Handling Facilities Lease payments. TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement. Lease expenses reimbursed by Tri-State were $7 million in each of 2009, 2008 and 2007.

TEP has agreed with the owners of Springerville Units 3 and 4 that, upon expiration of the Springerville Coal Handling Facilities and Common Leases, TEP will acquire the leased interest in the facilities at fixed prices of $120 million in 2015, $38 million in 2017, and $68 million in 2021. Upon such acquisitions by TEP, each of the owners of Unit 3 and Unit 4 have the obligation to purchase or continue renting from TEP a 17% and 14% interest, respectively, in such facilities. On or before the Springerville Unit 1 Lease expiration date, TEP will determine if it will either: a) purchase the assets at the fair market value; b) extend the lease term; or c) not continue with an interest in Springerville Unit 1.

In January 2010, through scheduled lease payments, TEP reduced its capital lease obligation by $40 million.

Investments in Springerville Lease Debt and Equity

In March 2009, TEP purchased $31 million of Springerville Unit 1 lease debt which included a premium that will be amortized over the remaining term of the lease debt. TEP’s investment in Springerville Unit 1 lease debt totaled $88 million at December 31, 2009 and $59 million at December 31, 2008. TEP also held an undivided equity ownership interest in the Springerville Unit 1 lease totaling $37 million at December 31, 2009 and $48 million at December 31, 2008. TEP held an investment in Springerville Coal Handling Facilities lease debt totaling $7 million at December 31, 2009 and $20 million at December 31, 2008.

Interest Rate Swaps — Springerville Common Facilities Lease Debt

In June 2006 and in May 2009, TEP entered into interest rate swaps to hedge the floating interest rate risk associated with the Springerville Common Facilities Lease debt. Interest on the lease debt is payable at six-month LIBOR plus a spread. The applicable spread was 1.625% as of December 31, 2009 and 1.5% as of December 31, 2008. The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

				LIBOR
Outstanding at December 31, 2009	Fixed Ratio			Spread
$35 million		5.77	%		1.625	%
$23 million		3.18	%		1.625	%
$7 million		3.32	%		1.625	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

These interest rate swaps have been recorded by TEP as a cash flow hedge for financial reporting purposes. See Note 18.

UNS ELECTRIC LONG-TERM DEBT

UNS Electric has $100 million of senior unsecured debt; $50 million at 6.5%, due 2015 and $50 million at 7.1%, due 2023 (UNS Electric 2008 Long-Term Debt). The UNS Electric Long-Term Debt is guaranteed by UES. The 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.

The UNS Electric Long-Term Debt contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments and incurrence of indebtedness. As of December 31, 2009, UNS Electric was in compliance with the covenants.

UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.

UNS GAS LONG-TERM DEBT

UNS Gas has $100 million of senior unsecured notes outstanding, consisting of $50 million at 6.23%, due August 2011, and $50 million at 6.23%, due August 2015. The 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. UES guarantees the notes.

UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. UNS Gas may refinance existing debt and incur up to $7 million in short-term debt.

The UNS Gas Long-Term Debt contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments and incurrence of indebtedness. As of December 31, 2009, UNS Gas was in compliance with the terms of its note purchase agreement.

UNISOURCE ENERGY CREDIT AGREEMENT

The UniSource Energy Credit Agreement consists of a $30 million amortizing term loan facility and a $70 million revolving credit facility and matures in August 2011. UniSource Energy’s obligations under the UniSource Credit Agreement are secured by a pledge of the capital stock of Millennium, UES and UED.

At December 31, 2009 the following balances were outstanding:

	Current		Long-					Current		Long-
	Liabilities		TermDebt		Total			Liabilities		Term Debt		Total
	- Millions of Dollars-
	December 31, 2009							December 31, 2008
Revolver	$	—	$	31	$	31		$	—	$	43	$	43
Term Loan	$	6	$	3	$	9		$	6	$	9	$	15
Weighted Average Interest Rate on the Revolver and Term Loan		—		—		1.48	%		—		—		2.48	%

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Audit Committee
2/19/10

We have included the revolver borrowings in Long-Term Debt as UniSource Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 25, 2010, outstanding borrowings under the UniSource Energy Credit Agreement were $15 million.

Principal payments of $1.5 million on the outstanding term loan are due quarterly, with the balance due at maturity. We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at adjusted LIBOR plus 1.25% or the sum of the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate and 0.25%.

The UniSource Energy 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 interest coverage ratio for UniSource Energy on a standalone basis and (2) a maximum leverage ratio on a consolidated basis. In September 2008, as a result of higher than expected fuel and purchased power costs, UniSource Energy amended the UniSource Energy Credit Agreement to provide more flexibility to meet the leverage ratio test for the next four calendar quarters, ending June 30, 2009. In February 2009, the leverage ratio in the UniSource Credit Agreement was further amended through August 2011. The leverage ratio is calculated as the ratio of consolidated total indebtedness to consolidated earnings before interest, taxes, depreciation and amortization (EBITDA). As of December 31, 2009, UniSource Energy was in compliance with the terms of its credit agreement.

UniSource Energy may pay dividends if, after giving effect to the dividend payment, it has more than $15 million of unrestricted cash and unused revolving credit.

TEP CREDIT AGREEMENT

The TEP Credit Agreement consists of a $150 million revolving credit facility, and a $341 million LOC facility which supports $329 million of tax-exempt Variable Rate IDBs. The TEP Credit Agreement matures in August 2011 and is secured by $491 million of mortgage bonds issued under the 1992 Mortgage, which creates a lien on and security interest in most of TEP’s utility plant assets. The $150 million revolving credit facility may be used for revolver borrowings as well as to issue letters of credit. TEP issues letters of credit to provide credit enhancements to counterparties for power and gas procurement and hedging activities.

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 0.45% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.45% per annum. TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.45% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.

The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leaseback 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.

In September 2008, as a result of higher than expected fuel and purchased power costs, TEP amended the TEP Credit Agreement, to provide more flexibility to meet the leverage ratio test for the next four calendar quarters, ending June 30, 2009. The leverage ratio is calculated as the ratio of consolidated total indebtedness to EBITDA. As of December 31, 2009, TEP was in compliance with all the terms of its credit agreement.

As of December 31, 2009, TEP had $35 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility. As of December 31, 2008, TEP had $10 million in loans outstanding under its revolving credit facility and $1 million outstanding in letters of credit. The revolving loan balances are included in Current Liabilities in the UniSource Energy and TEP balance sheets. The outstanding letters of credit are off-balance sheet obligations of TEP. As of February 25, 2009, TEP had $50 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

TEP Letter of Credit Facility

In April 2008, TEP entered into a three-year $132 million letter of credit and reimbursement agreement (2008 TEP Letter of Credit Facility). The 2008 TEP Letter of Credit Facility supported $130 million aggregate principal amount of variable rate tax-exempt IDBs that were issued on behalf of TEP in June 2008. (See 2008 Pima B Bonds above).

Interest rates and fees under the 2008 TEP Letter of Credit Facility were based on a pricing grid tied to TEP’s credit ratings. Based on TEP’s current credit ratings, the letter of credit fees were 0.65% per annum during the first two years and 0.775% in the third year.

The TEP Letter of Credit Facility contained substantially the same restrictive covenants as the TEP Credit Agreement described above. As of December 31, 2009, TEP was in compliance with all the terms of the TEP Letter of Credit Facility. The TEP Letter of Credit Facility was terminated in January 2010 at the time of the fixed rate conversion of the 2008 Pima B Bonds (See 2008 Pima B Bonds above).

UNS GAS/UNS ELECTRIC CREDIT AGREEMENT

The UNS Gas/UNS Electric Revolver is a $60 million revolving credit facility which matures in August 2011. Either UNS Gas or UNS Electric may borrow up to a maximum of $45 million, so long as the combined amount borrowed does not exceed $60 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 Gas/UNS Electric Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric. The UNS Gas/UNS Electric Revolver may be used to issue letters of credit, as well as for revolver borrowings. UNS Gas and UNS Electric issue letters of credit, which are off-balance sheet obligations, to support power and gas purchases and hedges.

UNS Gas and UNS Electric each have the option of paying interest at LIBOR plus 1.0% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.

The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, dividends, 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, 2009, UNS Gas and UNS Electric were each in compliance with the terms of the UNS Gas/UNS Electric Revolver.

The borrowings under the UNS Gas/UNS Electric Revolver were as follows:

	UNS		UNS		UNS		UNS
	Gas		Electric		Gas		Electric
	-Millions of Dollars-
	December 31, 2009				December 31, 2008
Balance on the Revolver	$	—	$	—	$	—	$	8
Weighted Average Interest Rate		—		—		—		1.5	%
Outstanding Letters of Credit	$	—	$	11	$	10	$	7

At December 31, 2008, UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver were excluded from Current Liabilities and presented as Long-Term Debt, as UNS Electric has the ability and the intent to keep the borrowings outstanding under the UNS Gas/UNS Electric Revolver for the next twelve months.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

UED BORROWINGS

In March 2009, UED entered into a 364-day, $30 million senior secured term loan facility. The loan is guaranteed by UniSource Energy and is secured by a lien of substantially all the assets of UED, including the BMGS and an assignment of UED’s PPA with UNS Electric. UED has the option of paying interest on the loan facility at LIBOR plus 3% or an alternative base rate plus 2%. The alternative base rate is the greater of federal funds plus 0.5%, the agent bank’s reference rate or one-month LIBOR plus 1%. The terms of the facility require UED to make quarterly excess cash flow payments. UED paid $1 million in debt issuance costs which are being amortized to interest expense over one year, the term of the loan. UED used the proceeds of the loan to pay a dividend of $30 million to UniSource Energy. As of December 31, 2009, UED owed $26 million under the senior secured term loan facility. In February 2010, UED amended its term loan facility to extend the termination date by two years to March 2012 and had net additional borrowings of $9 million bringing the outstanding balance to $35 million. UED capitalized less than $1 million in costs related to the transaction.

DEBT MATURITIES

Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:

	TEP
	Variable
	Rate IDBs		TEP		TEP										UniSource
	Supported		Scheduled		Capital										Energy
	by Letters		Debt		Lease			TEP			UNS		UNS		(includes
	of Credit		Retirements		Obligations			Total			Gas		Electric		UED)		Total
	- Millions of Dollars -
2010	$	—	$	—	$	93		$	93		$	—	$	—	$	32	$	125
2011		459		—		107			566			50		—		34		650
2012		—		—		118			118			—		—		—		118
2013		—		—		122			122			—		—		—		122
2014		—		—		195			195			—		—		—		195
Total 2010 — 2014		459		—		635			1,094			50		—		66		1,210
Thereafter		—		445		103			548			50		100		150		848
Less: Imputed Interest		—		—		(209	)		(209	)		—		—		—		(209	)
Total	$	459	$	445	$	529		$	1,433		$	100	$	100	$	216	$	1,849

TEP’s Variable Rate IDBs are backed by a $341 million LOC issued pursuant to TEP’s Credit Agreement which expires in August 2011 and TEP’s $132 million Letter of Credit Facility which was terminated in January 2010. Although the Variable Rate IDBs mature between 2018 and 2029, the above table reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.

NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price that would be received to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:

• The carrying amounts of our current assets and liabilities, including Current Maturities of Long-Term Debt, UED’s term loan, and amounts outstanding under our credit agreements, approximate their fair value due to the short-term nature of these instruments. Accordingly, these items have been excluded from the table below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

• Investments in Lease Debt and Equity: TEP calculated the present value of remaining cash flows at the balance sheet date using current market rates with similar characteristics with respect to credit rating and time-to-maturity. We also incorporated the impact of counterparty credit risk using market credit default swap data.

• Fixed Rate Long-Term Debt: UniSource Energy and TEP used quoted market prices, where available, or calculated the present value of remaining cash flows at the balance sheet date using current market rates for bonds with similar characteristics with respect to credit rating and time-to-maturity. We also incorporate the impact of our own credit risk using a credit default swap rate when determining the fair value of fixed rate long-term debt.

• Variable Rate Long-Term Debt: TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of their fair value. The fair value of variable rate long-term debt has also been adjusted for credit risk using a credit default swap rate.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The amount recorded in the balance sheet (carrying value) and the estimated fair values of our financial instruments included the following:

	December 31,
	2009				2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	-Millions of Dollars-
Assets:
TEP Investment in Lease Debt and Equity	$	132	$	140	$	127	$	144
Millennium Note Receivable		15		15		—		—
Liabilities:
Fixed Rate Long-Term Debt
TEP		445		336		445		322
UniSource Energy		795		693		795		661
Variable Rate Long-Term Debt
TEP		459		452		459		441
UniSource Energy		459		452		459		441

See Note 6 for a description of TEP’s investment in Springerville Lease Debt and Equity. TEP intends to hold the $95 million investment in Springerville Lease Debt Securities to maturity (Springerville Coal Handling Facilities lease debt totaling $7 million matures through July 1, 2011, and Springerville Unit 1 lease debt totaling $88 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.

NOTE 8. STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UniSource Energy

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, 2009, we complied with the terms of all such debt covenant requirements. Because UNS and all of its subsidiaries are in compliance with their debt covenants at December 31, 2009, there are no amounts of net income which are restricted.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

In February 2010, UniSource Energy declared a first quarter dividend to shareholders of $0.39 per share of UniSource Energy Common Stock. The dividend, totaling approximately $14 million, will be paid on March 8, 2010 to common shareholders of record as of February 23, 2010. In 2009, UniSource Energy paid quarterly dividends to the shareholders of $0.29 per share, for a total of $1.16 per share, or $41 million for the year. In 2008, UniSource Energy paid quarterly dividends to the shareholders of $0.24 per share, for a total of $0.96 per share, or $34 million, for the year. During 2007, UniSource Energy paid quarterly dividends to the shareholders of $0.225 per share, for a total of $0.90 per share, or $32 million, for the year.

In 2008, UniSource Energy’s dividend to the shareholders of $34 million exceeded its retained earnings. As a result, we recorded dividends of $14 million against retained earnings and dividends of $20 million against common stock. UniSource Energy has no additional paid-in capital. Such dividends do not represent a return of capital dividend for income tax purposes.

TEP

TEP paid dividends to UniSource Energy of $60 million in 2009, $3 million in 2008, and $53 million in 2007. In 2009, TEP recorded $0.8 million of dividend equivalents related to restricted stock units as dividends. UniSource Energy is the holder of TEP’s common stock. TEP met the requirements discussed below before paying these dividends.

UniSource Energy contributed capital to TEP of $30 million in 2009 and $18 million in 2007.

Bank Credit Agreement

TEP’s Credit Agreement as of August 2006 allows TEP to pay dividends as long as TEP complies with the agreement and certain financial covenants including quarterly limits on the ratio of total indebtedness to total earnings before interest expense/income, income taxes and non-cash items. TEP is in compliance with these covenants.

Federal Power Act

This Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP’s 2009, 2008 and 2007 dividends were paid from current year earnings.

UNS Gas and UNS Electric

The terms of the senior unsecured note agreements entered into by both UNS Gas and UNS Electric contain dividend restrictions. See Note 6. UES did not pay any dividends to UniSource Energy in 2009, 2008 or 2007.

UES made capital contributions to UNS Electric of less than $0.5 million in 2008.

UniSource Energy made no capital contributions to UNS Electric in 2009 and 2008. UniSource Energy made capital contributions to UNS Electric of $10 million in 2007.

Millennium and UED

Millennium paid dividends of $4 million to UniSource Energy in January 2010, $3 million in 2009, $25 million in 2008 and $15 million in 2007, all of which represented return of capital distributions.

UED paid dividends to UniSource Energy of $9 million in February 2010, $4 million of which represented return of capital distributions; $30 million in 2009 which represented return of capital distributions; and $0.5 million in 2008. Millennium and UED have no dividend restrictions.

K-140

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

In December 2008, UniSource Energy contributed $59 million in capital to UED by canceling an intercompany promissory note in the amount of $59 million. Borrowings under the promissory note were used to finance the development of BMGS.

NOTE 9. INCOME TAXES

A reconciliation of the federal statutory income tax rate to each company’s effective income tax rate is as follows:

	UniSource Energy									TEP
	Years Ended December 31,
	2009			2008			2007			2009			2008			2007
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	59		$	11		$	34		$	51		$	5		$	31
State Income Tax Expense, Net of Federal Benefit		7			1			5			6			1			4
Depreciation Differences (Flow Through Basis)		1			2			3			1			2			3
San Juan Generating Station Environmental Penalties		—			3			—			—			3			—
Federal/State Tax Credits		(1	)		(3	)		(2	)		(1	)		(3	)		(2	)
Other		(2	)		3			(1	)		(2	)		3			—
Total Federal and State Income Tax Expense	$	64		$	17		$	39		$	55		$	11		$	36
Effective Tax Rate		38	%		55	%		40	%		38	%		71	%		40	%

In 2008, it was determined that the environmental penalties at San Juan Generating Station would not be deductible for income tax purposes. As a result, an additional $3 million of tax expense was recognized in 2008 for penalties incurred in the current and prior years. Other items included in GAAP expense which will not be deductible for tax were offset by the recognition of income tax credits.

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

	UniSource Energy							TEP
	Years Ended December 31,
	2009		2008			2007		2009		2008			2007
	-Millions of Dollars-
Current Tax Expense (Benefit)
Federal	$	5	$	(17	)	$	14	$	7	$	(12	)	$	22
State		—		(2	)		3		1		(1	)		6
Total		5		(19	)		17		8		(13	)		28
Deferred Tax Expense (Benefit)
Federal		48		34			20		38		23			9
State		11		2			2		9		1			(1	)
Total		59		36			22		47		24			8
Total Federal and State Income Tax Expense	$	64	$	17		$	39	$	55	$	11		$	36

We record deferred income tax assets and liabilities for amounts that will result in tax deductions or taxable income on future tax returns. We consider it more likely than not that all the deferred tax assets will result in lower income taxes in the future. Consequently, we have not recorded a valuation allowance to reduce our deferred tax assets.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

The significant components of deferred income tax assets and liabilities consist of the following:

	UniSource Energy						TEP
	December 31,						December 31,
	2009			2008			2009			2008
	-Millions of Dollars-
Gross Deferred Income Tax Assets
Capital Lease Obligations	$	208		$	209		$	208		$	209
Customer Advances and Contributions in Aid of Construction		43			40			26			26
Alternative Minimum Tax Credit		43			49			28			35
Accrued Postretirement Benefits		24			24			24			24
Emission Allowance Inventory		13			13			12			12
Other		35			39			25			27
Gross Deferred Income Tax Assets		366			374			323			333
Gross Deferred Income Tax Liabilities
Plant — Net		(442	)		(390	)		(397	)		(357	)
Capital Lease Assets — Net		(58	)		(61	)		(58	)		(61	)
Regulatory Asset — Income Taxes Recoverable Through Future Revenues		(7	)		(8	)		(7	)		(8	)
Pensions		(10	)		(7	)		(11	)		(8	)
Deferred Lease Payment		(5	)		(6	)		(5	)		(6	)
Other		(19	)		(19	)		(11	)		(13	)
Gross Deferred Income Tax Liabilities		(541	)		(491	)		(489	)		(453	)
Net Deferred Income Tax Liabilities	$	(175	)	$	(117	)	$	(166	)	$	(120	)

The balance sheets display the net deferred income tax liability as follows:

	UniSource Energy						TEP
	December 31,						December 31,
	2009			2008			2009			2008
	-Millions of Dollars-
Deferred Income Taxes — Current Assets	$	52		$	61		$	51		$	60
Deferred Income Taxes — Noncurrent Liabilities		(227	)		(178	)		(217	)		(180	)
Net Deferred Income Tax Liability	$	(175	)	$	(117	)	$	(166	)	$	(120	)

Deferred Income Taxes — Current Assets at December 31, 2009 and 2008 for UniSource Energy includes $3 million of deferred tax assets related to losses of a foreign investment held by a Millennium subsidiary. Management plans to dispose of its investment in the foreign joint venture and recognize the deferred losses on UniSource Energy’s federal and state income tax returns. This recognition on filed tax returns will allow for realization of the deferred tax asset. If management is unable to complete its plans to dispose of the joint venture, UniSource Energy may be required to write off the deferred tax asset of $3 million.

At December 31, 2008, UniSource Energy had $43 million and TEP had $28 million of state net operating loss carryforwards which are expected to be used on the 2009 income tax returns. Deferred tax assets also include $2 million of federal and state capital loss carryforward at UniSource Energy which is also expected to be fully used on the 2009 income tax returns.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

Management believes that based on its historical pattern of taxable income, UniSource Energy will produce sufficient income in the future to realize its deferred income tax assets. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred tax asset will not be realized. No valuation allowance has been recorded to reduce the balance in deferred tax assets since management believes it is more likely than not that UniSource Energy will be able to recognize the tax deductions on future returns.

The $13 million income tax receivable at December 31, 2008 is attributable to a 2008 net operating loss which was carried back to prior years.

Uncertain Tax Positions

UniSource Energy and TEP adopted uncertain tax position accounting as of January 1, 2007. Accounting guidance requires us to determine whether it is “more likely than not” that we will sustain a tax position under examination. Each tax position is measured to determine the amount of benefit to recognize in the financial statements. The amount of unrecognized tax benefit reported by UniSource Energy, all of which is recorded at TEP, was $19 million at December 31, 2009 and $20 million at December 31, 2008. The following table shows the changes in unrecognized tax benefits of UniSource Energy and TEP:

	December 31,
	2009			2008
Unrecognized Tax Benefits, beginning of year	$	20		$	12
Additions based on tax positions taken in the current year		1			6
Reductions based on settlements with tax authorities		(1	)		—
Additions based on tax positions taken in the prior year		—			3
Reductions based on tax positions taken in the prior year		(1	)		(1	)
Unrecognized Tax Benefits, end of year	$	19		$	20

Unrecognized tax benefits which, if recognized, would reduce the effective tax rate, were $1 million at December 31, 2009 and 2008 for both UniSource Energy and TEP.

The $1 million decrease in the balance of unrecognized tax benefits from 2008 to 2009 relates to $1 million of tax benefit attributable to tax positions taken in 2009 which may not be sustainable, offset by the recognition of $1 million of tax benefits from prior years and recognition of $1 million of tax benefits based on settlements with authorities. The balance in unrecognized tax benefits could increase in the next twelve months as a result of the ongoing IRS audits, but the amount of the increase cannot be determined.

TEP recognizes interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements. In 2009 $1 million of interest expense was recorded and in 2008 no interest expense was recognized. The balance of interest payable at December 31, 2009 is $2 million and at December 31, 2008 it was $1 million. Penalties accrued are immaterial in amount.

UniSource Energy and TEP have been audited by the IRS through tax year 2004 and are currently under audit by the IRS for 2005, 2006, and 2008. Tax Year 2007 has not yet been selected for audit. The fieldwork for the 2005 and 2006 audits is complete and the audits are effectively settled. The 2005 and 2006 audits closed in January 2010. UniSource Energy and TEP have a current liability of $2 million for taxes and interest to settle 2005 and 2006 audits. We are unable to determine when the 2008 audit will be completed. UniSource Energy and TEP are not currently under audit by any state tax agencies.

K-143

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

NOTE 10. EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

TEP, UNS Gas and UNS Electric maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees. Employees receive benefits based on their years of service and average compensation. TEP, UNS Gas and UNS Electric fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations.

We recognize the underfunded status of our defined benefit pension plans as a liability on our consolidated balance sheets. The underfunded status is measured as the difference between the fair value of the plans assets and the projected benefit obligation for pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in rates. In December 2008, as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations. Accordingly, TEP reclassified pension amounts related to its generation operations, previously recognized in AOCI, to a regulatory asset.

TEP also provides supplemental retirement benefits to certain employees whose benefits are limited by IRS benefit or compensation limitations. Changes in benefit obligations are recognized as a component of AOCI.

Pension Contributions

The Pension Protection Act of 2006 (The Pension Act) establishes minimum funding targets for pension plans beginning in 2008. A plan’s funding target is the present value of all benefits accrued or earned as of the beginning of the plan year. While the annual targets are not legally required, if a plan does not meet the annual funding targets, the plan’s benefit payment options are limited and a funding deficiency notice must be sent to all plan participants. All TEP, UNS Gas and UNS Electric plans are in compliance with The Pension Act.

UniSource Energy made pension plan contributions in 2009 of $25 million, of which $23 million was made by TEP.

In 2010, UniSource Energy expects to contribute $22 million to the pension plans of which $20 million will be made by TEP.

TEP Salaried Employees Retirement Plan Amendment

In August 2009, TEP amended one of its defined benefit pension plans to limit early retirement benefits for TEP non-union employees hired after June 1, 2009 and to modify disability retirement and survivor benefits for all TEP non-union employees. As a result of the pension plan amendment, the plan assets and liabilities were remeasured as of August 31, 2009. In performing the remeasurement, management reviewed the key assumptions used to measure the plan’s benefit obligation at December 31, 2008 and to calculate pension expense for 2009. TEP determined that the discount rate should be increased to 6.40% from the 6.30% rate assumed at December 31, 2008. The revised discount rate was determined using the same methodology as was employed at year-end 2008. All other key assumptions, including the expected rate of return on assets, remained unchanged from December 31, 2008.

The amendment reduced the annual expense for 2009 for the salaried plan by less than $1 million to $8 million. The reduction in pension expense was recognized ratably from September to December of 2009. The remeasurement reduced the benefit obligation and corresponding regulatory asset by $8 million.

In December 2009, TEP amended its defined benefit pension plan for union employees to limit early retirement benefits for TEP union employees hired on or after January 1, 2011, modify disability retirement and survivor benefits for TEP union employees, and modify maximum credited service beginning in 2009. Because the amendment was in December, there was no additional remeasurement.

K-144

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

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. UNS Gas and UNS Electric provide postretirement medical benefits for current retirees and a small group of active employees.

In the 2008 TEP Rate Order, the ACC authorized accrual basis recovery of other postretirement benefit plan costs based on a commitment to fund the plan. TEP established a Voluntary Employee Beneficiary Association (VEBA) trust in 2009 to fund its other postretirement benefit plan and began funding the plan. TEP, UNS Gas and UNS Electric now record changes in their other postretirement obligation, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in rates. Amounts previously recorded in AOCI were reclassified to a regulatory asset in 2008.

The pension and other postretirement benefit related amounts (excluding tax balances) included in the UniSource Energy balance sheet are:

							Other Postretirement
	Pension Benefits						Benefits
	Years Ended December 31,
	2009			2008			2009			2008
	-Millions of Dollars-
Regulatory Pension Asset included in Other Regulatory Assets	$	75		$	105		$	9		$	7
Accrued Benefit Liability included in Accrued Employee Expenses		—			—			(4	)		(4	)
Accrued Benefit Liability included in Pension and Other Postretirement Benefits		(58	)		(95	)		(65	)		(63	)
Accumulated Other Comprehensive Loss		3			3			—			—
Net Amount Recognized	$	20		$	13		$	(60	)	$	(60	)

The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $5 million and $7 million, at December 31, 2009 and 2008 respectively, and a postretirement benefit liability of $1 million for UNS Gas and UNS Electric, for each period presented.

The balance remaining in AOCI of $3 million relates to the TEP supplemental executive retirement plan.

K-145

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

OBLIGATIONS AND FUNDED STATUS

We measured the actuarial present values of all pension benefit obligations and other postretirement benefit plans at December 31, 2009 and 2008. The tables below include TEP, UNS Gas and UNS Electric plans. The change in projected benefit obligation and plan assets and reconciliation of the funded status are as follows:

							Other Postretirement
	Pension Benefits						Benefits
	Years Ended December 31,
	2009			2008			2009			2008
	-Millions of Dollars-
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	230		$	209		$	67		$	65
Actuarial (Gain) Loss		—			13			1			—
Interest Cost		14			14			4			4
Service Cost		7			7			2			2
Measurement Date Change		—			1			—			—
Amendments		(1	)		(2	)		—			—
Benefits Paid		(8	)		(12	)		(3	)		(4	)
Projected Benefit Obligation at End of Year		242			230			71			67
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		135			193			—			—
Actual (Loss) Return on Plan Assets		32			(57	)		—			—
Benefits Paid		(8	)		(12	)		(3	)		(4	)
Employer Contributions		25			10			5			4
Measurement Date Change		—			1			—			—
Fair Value of Plan Assets at End of Year		184			135			2			—
Funded Status at End of Year	$	(58	)	$	(95	)	$	(69	)	$	(67	)

The table above includes pension benefit obligations for UNS Gas and UNS Electric of approximately $5 million and $7 million, at December 31, 2009 and 2008, respectively, plan assets of $6 million and $4 million at December 31, 2009 and 2008, respectively, and a postretirement benefit liability of less than $1 million, for UNS Gas and UNS Electric, for each period presented.

The following table provides the components of UniSource Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of December 31, 2009:

					Other Postretirement
	Pension Benefits				Benefits
	Years Ended December 31,
	2009		2008		2009			2008
	-Millions of Dollars-
Net Loss	$	77	$	105	$	13		$	13
Prior Service Cost (Benefit)		1		3		(4	)		(6	)

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

Information for pension plans with Accumulated Benefit Obligations in excess of plan assets follows:

	December 31,
	2009		2008
Projected Benefit Obligation at End of Year	$	242	$	230
Accumulated Benefit Obligation at End of Year		210		198
Fair Value of Plan Assets at End of Year		184		135

At December 31, 2008, and December 31, 2009, all UniSource Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets.

The components of net periodic benefit costs are as follows:

										Other Postretirement
	Pension Benefits									Benefits
	Years Ended December 31,
	2009			2008			2007			2009			2008			2007
	-Millions of Dollars-
Service Cost	$	7		$	7		$	8		$	2		$	2		$	2
Interest Cost		14			14			13			4			4			4
Expected Return on Plan Assets		(11	)		(16	)		(14	)		—			—			—
Prior Service Cost Amortization		1			2			1			(2	)		(2	)		(2	)
Recognized Actuarial Loss		7			—			2			1			1			1
Net Periodic Benefit Cost	$	18		$	7		$	10		$	5		$	5		$	5

Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in Other Operating and Maintenance costs.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:

	Pension Benefits
	2009					2008						2007
	Regulatory					Regulatory						Regulatory
	Asset			AOCI		Asset			AOCI			Asset			AOCI
	-Millions of Dollars-
Current Year Actuarial (Gain) Loss	$	(21	)	$	—	$	85		$	1		$	(16	)	$	(6	)
Amortization of Actuarial Gain (Loss)		(7	)		—		—			—			(1	)		(1	)
Prior Service (Cost) Amortization		—			—		(2	)		—			(1	)		(1	)
Plan Amendments		(1	)		—		(2	)		—			—			—
Reclassification from AOCI to Regulatory Asset		—			—		8			(8	)		—			—
Change in Additional Minimum Liability		—			—		—			—			—			—
Total Recognized	$	(29	)	$	—	$	89		$	(7	)	$	(18	)	$	(8	)

	Other Postretirement Benefits
	2009			2008
	Regulatory			Regulatory						2007
	Asset			Asset			AOCI			AOCI
	-Millions of Dollars-
Current Year Actuarial (Gain) Loss	$	1		$	—		$	—		$	(1	)
Amortization of Actuarial Gain (Loss)		(1	)		(1	)		—			(1	)
Prior Service (Cost) Amortization		2			2			—			2
Change in Additional Minimum Liability		—			—			—			(2	)
Reclassification from AOCI to Regulatory Asset		—			6			(6	)		—
Total Recognized	$	2		$	7		$	(6	)	$	(2	)

For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $5 million estimated net loss and less than $1 million prior service cost from other regulatory assets or AOCI into net periodic benefit cost in 2010. The estimated net loss and prior service benefit for the defined benefit postretirement plans that will be amortized from other regulatory assets into net periodic benefit cost in 2010 are $1 million and $2 million, respectively.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

							Other Postretirement
	Pension Benefits						Benefits
	2009			2008			2009			2008
Weighted-Average Assumptions Used to Determine Benefit Obligations as of the Measurement Date
Discount Rate		6.3	%		6.3	%		6.0	%		6.5	%
Rate of Compensation Increase		3.0 – 5.0	%		3.0 – 5.0	%		N/A			N/A

										Other Postretirement
	Pension Benefits									Benefits
	2009			2008			2007			2009			2008
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate		6.3	%		6.6 – 6.8	%		5.9	%		6.5	%		6.5	%
Rate of Compensation Increase		3.0 – 5.0	%		3.0 – 5.0	%		3.0 – 5.0	%		N/A			N/A
Expected Return on Plan Assets		8.0	%		7.75 – 8.3	%		8.3	%		N/A			N/A

Net periodic benefit cost for the other postretirement benefit plan was remeasured as of January 1, 2007 to reflect the plan amendment communicated to plan participants on January 2, 2007. A discount rate of 5.6% was used for the January 2007 portion of the expense, while a discount rate of 5.8% was used for the remaining eleven months.

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.

TEP, UNS Gas and UNS Electric use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25^th percentile to the 75^th percentile. The model used as a guideline for selecting the overall rate-of-return-on-assets assumption is based on forward looking return expectations only. The above method is used for all asset classes.

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,
	2009			2008
Assumed Health Care Cost Trend Rates
Health Care Cost Trend Rate Assumed for Next Year		7.9	%		7.5	%
Ultimate Health Care Cost Trend Rate Assumed		4.5	%		5	%
Year that the Rate Reaches the Ultimate Trend Rate		2027			2017

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Assumed health care cost trend rates significantly affect 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, 2009 amounts:

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

PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS

TEP, UNS Gas and UNS Electric calculate the fair value of plan assets on December 31, the measurement date. The 2007 measurement date was December 1. Pension plan asset allocations, by asset category, were as follows:

							UNS Gas and UNS Electric
	TEP Plan Assets						Plan Assets
	December 31,			December 31,			December 31,			December 31,
	2009			2008			2009			2008
Asset Category
Equity Securities		57	%		51	%		56	%		67	%
Fixed Income Securities		34	%		33	%		33	%		31	%
Real Estate		7	%		13	%		11	%		—
Other		2	%		3	%		—			2	%
Total		100	%		100	%		100	%		100	%

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	Fair Value Measurements of Pension Assets
	December 31, 2009
	($ in millions)
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable
	Markets		Inputs		Inputs
Asset Category	(Level 1)		(Level 2)		(Level 3)		Total
Cash	$	1	$	—	$	—	$	1
Equity Securities:
U.S. Large Cap		—		53		—		53
U.S. Small Cap		—		10		—		10
Non-U.S.		—		42		—		42
Fixed Income		—		63		—		63
Real Estate		—		5		8		13
Hedge Fund		—		—		1		1
Private Equity		—		—		1		1
Total	$	1	$	173	$	10	$	184

Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.

Level 2 investments comprise amounts held in co-mingled equity funds, US bond and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.

Level 3 real estate investments were valued by appraisal at September 30, 2009, and subsequently revalued at December 31, 2009. Revaluation comprised of using a preliminary real estate index value to estimate the percentage change in asset value from September 30, 2009, to December 31, 2009. The preliminary real estate index value was developed based on appraisals comprising 82% of real estate assets tracked by the index.

Level 3 hedge and private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.

As of December 31, 2009, the fair value of VEBA trust assets were $1.5 million of which $1 million were fixed income investments and $0.5 million were equities. There are no level three assets in the VEBA trust.

A Reconciliation of Level 3 Assets follows:

	Private Equity		Real Estate			Hedge Fund			Total
Beginning Balances at December 31, 2008	$	1	$	12		$	3		$	16
Actual Return on Plan Assets:
Relating to Assets still held at Reporting Date		—		(4	)		—			(4	)
Relating to Assets sold during the Period		—		—			(1	)		(1	)
Purchases, Sales, and Settlements		—		—			(1	)		(1	)
Transfers in and/or out of Level 3		—		—			—			—
Ending Balance at December 31, 2009	$	1	$	8		$	1		$	10

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2/19/10

Pension Plan Investments

Investment Goals

Strategic asset allocation is the principal method for achieving each plan’s investment objective, while maintaining an appropriate level of risk. We will consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for Plan Sponsor funding will be reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the Plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. The plan seeks to provide returns in excess of a portfolio benchmark.

Risk Management

We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a Plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: 1) Plan status; 2) Plan Sponsor financial status and profitability; 3) Plan features; and 4) workforce characteristics. We have determined that the Plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks the plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment managers and on the portfolio as a whole. Investment managers for the plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges have also been used for defensive purposes.

Relationship between Plan Assets and Benefit Obligations

The overall health of the Plan will be monitored by comparing the value of Plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the market value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of Plan data, but will be no less frequent than annually via annual actuarial valuation.

The current target allocation percentages for the major categories or plan assets follow. For each Plan, there is a range of +/- 2% of the target allocation before the fund will be automatically rebalanced. The hedge fund is being closed, and is currently in the redemption/liquidation process.

	TEP Plan %			UES Plan %			VEBA Trust %
Fixed Income		31.7	%		33.4	%		62.5	%
U.S. Large Cap		26.4	%		27.8	%		27.6	%
Non-US Developed		15.9	%		16.7	%		3.3	%
Real Estate		10.6	%		11.1	%		—
U.S. Small Cap		5.2	%		5.5	%		1.6	%
Non-US Emerging		5.2	%		5.5	%		—
Private Equity		5.0	%		—			—
Cash / Treasury Bills		—			—			5.0	%
Total		100.0	%		100.0	%		100.0	%

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Pension Fund Descriptions

The funds are manager of manager funds, with the exception of the hedge fund and the private equity fund, which are funds of funds.

ESTIMATED FUTURE BENEFIT PAYMENTS

TEP expects the following benefit payments to be made by the defined benefit pension plans, which reflect future service, as appropriate.

			Other
	Pension		Postretirement
	Benefits		Benefits
	-Millions of Dollars-
2010	$	10	$	5
2011		11		5
2012		12		5
2013		13		6
2014		14		6
Years 2015-2019		88		30

UNS Gas and UNS Electric expect pension and postretirement benefit payouts of approximately $4 million in 2010 through 2014 and $7 million in 2015 through 2019 to be made by the defined benefit pension and postretirement plans.

DEFINED CONTRIBUTION PLANS

TEP, UNS Gas and UNS Electric offer defined contribution savings plans to all eligible employees. The Internal Revenue Code identifies the plans as qualified 401(k) plans. Participants direct the investment of contributions to certain funds in their account which may include a UNS stock fund. TEP, UNS Gas, and UNS Electric match part of a participant’s contributions to the plans. TEP made matching contributions to these plans of approximately $4 million in each of 2009, 2008, and 2007. UNS Gas and UNS Electric made matching contributions of less than $0.5 million in each of 2009, 2008, and 2007.

NOTE 11. SHARE-BASED COMPENSATION PLANS

Under the 2006 Omnibus Stock and Incentive Plan, the Compensation Committee of the UniSource Energy Board of Directors may issue various types of share-based compensation, including stock options, restricted shares/units, and performance shares. The total number of shares which may be awarded under the Plan cannot exceed 2.25 million shares. At December 31, 2009, the total number of shares awarded under the 2006 Omnibus Stock and Incentive Plan was 1 million shares.

STOCK OPTIONS

In February 2009, the Compensation Committee of the UniSource Energy Board of Directors granted 248,760 stock options to officers with an exercise price of $26.11. In 2008, the Compensation Committee of the UniSource Energy Board of Directors granted 303,550 stock options to officers with an exercise price of $26.18. In 2007, the board granted 184,260 stock options to officers with an exercise price of $37.88.

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Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, 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. Compensation expense is recorded on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement eligible officers, compensation expense is recorded immediately. One stock option award accrues 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. Dividend equivalents are recorded as dividends when declared. See discussion of dividend equivalents in Note 1.

The fair value of each option award was estimated on the date of grant using the Black-Scholes-Merton option pricing model with the assumptions noted in the following table. The expected terms of the stock options granted in 2009 and 2008 were estimated using historical exercise data. The expected term of 2007 options granted was estimated using a “simplified” method which considered the 3 year vesting period and the contractual term. The risk-free rate was based on the rate available on a U.S. Treasury Strip with a maturity equal to the expected term of the option at the time of the grant. The expected volatility for each award was based on historical volatility for UniSource Energy’s stock for a period equal to the expected term of the award. The expected dividend yield on a share of stock was calculated using the historical dividend yield with the implicit assumption that current dividend yields will continue in the future.

	2009			2008			2007
Expected Term (years)		7			6			6
Risk-free Rate		3.4	%		3.1	%		4.4	%
Expected Volatility		25.0	%		18.8	%		20.2	%
Expected Dividend Yield		3.2	%		2.8	%		2.4	%
Weighted-Average Grant-Date Fair Value of Options Granted During the Period	$	5.53		$	4.23		$	8.13

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A summary of the stock option activity follows:

	2009					2008					2007
				Weighted					Weighted					Weighted
				Average					Average					Average
(Shares in Thousands)				Exercise					Exercise					Exercise
Stock Options	Shares			Price		Shares			Price		Shares			Price
Outstanding, Beginning of Year		1,635		$	22.50		1,451		$	21.21		1,388		$	18.59
Granted		249		$	26.11		304		$	26.18		184		$	37.88
Exercised or Vested		(282	)	$	14.46		(120	)	$	16.34		(120	)	$	16.56
Forfeited/Expired		(4	)	$	12.28		—			—		(1	)	$	12.28
Outstanding, End of Year		1,598		$	24.50		1,635		$	22.50		1,451		$	21.21
Exercisable, End of Year		1,085		$	23.06		1,153		$	19.50		1,139		$	17.43
Aggregate Intrinsic Value of Options Exercised ($000s)	$	4,177				$	1,680				$	2,226

	At December 31, 2009($000s)
Aggregate Intrinsic Value for Options Outstanding	$	13,408
Aggregate Intrinsic Value for Options Exercisable	$	10,679
Weighted Average Remaining Contractual Life of Outstanding Options	4.4 years
Weighted Average Remaining Contractual Life of Exercisable Options	3.0 years

A summary of stock options follows:

	Options Outstanding					Options Exercisable
			Weighted-
			Average	Weighted-				Weighted-
	Number of		Remaining	Average		Number		Average
Range of	Shares		Contractual	Exercise		of Shares		Exercise
Exercise Prices	(000s)		Life	Price		(000s)		Price
$15.28 – $18.84		664	1.6 years	$	17.39		664	$	17.39
$26.11 – $37.88		934	6.4 years	$	29.55		421	$	31.99

We summarize the status of non-vested stock options as of December 31, 2009, and changes during 2009 below:

	Number of Shares			Weighted-Average
Non-vested Shares	(000s)			Grant-Date Fair Value
Non-vested at January 1, 2009		482		$	5.59
Granted		249			5.53
Vested		(218	)		6.13
Forfeited		—			—
Non-vested at December 31, 2009		513		$	5.33

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2/19/10

RESTRICTED STOCK UNITS/AWARDS AND PERFORMANCE SHARES

Restricted Stock Units

Restricted stock and stock units are generally granted under the Plan to non-employee directors. Restricted stock is an award of Common Stock that is subject to forfeiture if the restrictions specified in the award are not satisfied. Stock units are a non-voting unit of measure that is equivalent to one share of Common Stock. The directors may elect to receive stock units in lieu of restricted stock. Restricted stock generally vests over periods ranging from one to three years and are payable in Common Stock. Stock units vest either immediately or over periods ranging from one to three years. The restricted stock units vest immediately upon death, disability, or retirement. In the January following the year the person is no longer a director, Common Stock shares will be issued for the vested stock units. Compensation expense equal to the fair market value on the grant date is recognized over the vesting period. 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.

The Compensation Committee of the UniSource Energy Board of Directors granted the following stock units to non-employee directors:

• May 2009 — 21,886 stock units at a weighted average fair value of $26.73 per share,

• February 2008 — 3,130 stock units at a weighted average fair value of $28.75 per share,

• May 2008 — 18,448 stock units at a weighted average fair value of $31.71 per share,

• August 2008 — 1,400 stock units at a weighted average fair value of $32.15 per share, and

• 2007 — 17,857 stock units at a weighted average fair value of $37.30 per share.

Performance Share Awards

In February 2009, the Compensation Committee of the UniSource Energy Board of Directors granted 62,190 performance share awards (targeted shares) to Officers at a grant date fair value, based on a Monte Carlo simulation, of $21.62 per share. The performance share awards will be paid out in shares of UniSource Energy common stock based on targeted, cumulative UniSource Energy Total Shareholder Return during the performance period of January 1, 2009 through December 31, 2011 compared with Total Shareholder Return over the same period of an industry peer group.

In February 2008, the Compensation Committee of the UniSource Energy Board of Directors granted 49,120 performance share awards (targeted shares) to Officers at a grant date fair value, based on a Monte Carlo simulation, of $17.10 per share. The performance share awards will be paid out in shares of UniSource Energy Common Stock based on UniSource Energy’s performance over the performance period of January 1, 2008 through December 31, 2010. The performance criteria specified in the awards is determined based on targeted UniSource Energy Total Shareholder Return during the performance period compared to the Total Shareholder Return over the same period of an industry or peer group. The performance shares vest based on goal attainment, upon completion of the performance period; any unearned awards are forfeited. Compensation expense equal to the fair value on the grant date is recognized over the vesting period if the requisite service period is fulfilled whether or not the threshold is achieved.

In March 2007, the Compensation Committee of the UniSource Energy Board of Directors granted 37,270 performance share awards (targeted shares) to certain officers at a grant date fair value of $35.56 per share (market price of $37.88 less the present value of expected dividends of $2.32). At December 31, 2009, upon completion of the 3-year performance period, 22,116 shares vested based on achievement of targeted cumulative Cash Flows from Operations and cumulative Diluted Earnings per Share over the performance period; 15,154 shares were unearned and forfeited. Compensation expense equal to the fair market value on the grant date less the present value of expected dividends was recognized over the performance period and adjusted for goals that were not achieved. In February 2010, the Board of Directors approved distribution of the 22,116 vested shares of UniSource Energy Common Stock.

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Audit Committee
2/19/10

	Performance Shares					Restricted Stock Units
				Weighted-					Weighted-
				Average					Average
	Shares			Grant-Date		Shares			Grant-Date
	(000s)			Fair Value		(000s)			Fair Value
Non-vested at January 1, 2009		67		$	25.23		23		$	31.33
Granted		62			21.62		22			26.73
Vested		(22	)		35.56		(23	)		31.33
Forfeited		(7	)		35.56		—			—
Non-vested at December 31, 2009		100		$	19.92		22		$	26.73

SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units)

Annually during 2007 through 2009, UniSource Energy and TEP recorded share-based compensation expense of $3 million and $2 million, respectively. The actual tax deduction realized from the exercise of share-based payment arrangements totaled $3 million for 2009, $1 million for 2008, and $0.5 million in 2007. We capitalize approximately 30% of share-based compensation costs as a cost of construction.

At December 31, 2009, the total unrecognized compensation cost related to non-vested share-based compensation was $2 million, which will be recorded as compensation expense over the remaining vesting periods through February 2011. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at December 31, 2009 was 2 million.

2010 SHARE-BASED COMPENSATION AWARDS

In February 2010, the Compensation Committee of the UniSource Energy Board of Directors granted 93,720 performance share awards (targeted shares). 50% of the performance share awards will be paid out in shares of UniSource Energy Common Stock based on targeted, cumulative UniSource Energy Total Shareholder Return during the performance period of January 1, 2010 through December 31, 2012, compared to the Total Shareholder Return over the same period of an industry or peer group. The remaining 50% will be paid out in shares of UniSource Energy Common Stock based on cumulative net income for the 3-year period ended December 31, 2012. The performance shares vest based on goal attainment, upon completion of the performance period; any unearned awards are forfeited. Performance shares are eligible for dividend equivalents during the performance period.

NOTE 12. FAIR VALUE MEASUREMENTS

The following tables set forth, by level within the fair value hierarchy, UniSource Energy and TEP’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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	UniSource Energy
	Quoted Prices in		Significant Other			Significant
	Active Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2009
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	51	$	—		$	—		$	51
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		14			—			14
Equity Investments(3)		—		—			6			6
Collateral Posted(4)		—		2			—			2
Energy Contracts(5)		—		1			6			7
Total Assets		51		17			12			80
Liabilities
Energy Contracts(5)		—		(16	)		(19	)		(35	)
Interest Rate Swaps(6)		—		(6	)		—			(6	)
Total Liabilities		—		(22	)		(19	)		(41	)
Net Total Assets and (Liabilities)	$	51	$	(5	)	$	(7	)	$	39

	UniSource Energy
	Quoted Prices in		Significant Other			Significant
	Active Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2008
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	14	$	—		$	—		$	14
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		9			—			9
Equity Investments(3)		—		—			11			11
Collateral Posted(4)		—		14			—			14
Energy Contracts(5)		—		1			6			7
Total Assets		14		24			17			55
Liabilities
Energy Contracts(5)		—		(40	)		(23	)		(63	)
Interest Rate Swaps(6)		—		(8	)		—			(8	)
Total Liabilities		—		(48	)		(23	)		(71	)
Net Total Assets and (Liabilities)	$	14	$	(24	)	$	(6	)	$	(16	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

	TEP
	Quoted Prices
	in Active		Significant Other			Significant
	Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2009
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	8	$	—		$	—		$	8
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		14			—			14
Energy Contracts(5)		—		1			5			6
Total Assets		8		15			5			28
Liabilities
Energy Contracts(5)		—		(5	)		(9	)		(14	)
Interest Rate Swaps(6)		—		(6	)		—			(6	)
Total Liabilities		—		(11	)		(9	)		(20	)
Net Total Assets and (Liabilities)	$	8	$	4		$	(4	)	$	8

	TEP
	Quoted Prices
	in Active		Significant Other			Significant
	Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2008
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	8	$	—		$	—		$	8
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		9			—			9
Energy Contracts(5)		—		—			10			10
Total Assets		8		9			10			27
Liabilities
Energy Contracts(5)		—		(18	)		(11	)		(29	)
Interest Rate Swaps(6)		—		(8	)		—			(8	)
Total Liabilities		—		(26	)		(11	)		(37	)
Net Total Assets and (Liabilities)	$	8	$	(17	)	$	(1	)	$	(10	)

(1)	Cash Equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
(2)	Level 2 Investments comprise amounts held in mutual and money market funds related to deferred compensation and Supplemental Executive Retirement Plan (SERP) benefits. The valuation is based on quoted prices, traded in active markets. These investments are included in Investments and Other Property — Other in the UniSource Energy and TEP balance sheets.
(3)	Equity Investments are, in the absence of readily ascertainable market values, based on the lower of the investment partners’ valuations or management’s valuation and comprise Millennium’s equity investment in unregulated businesses. These investments are included in Investments and Other Property — Other in the UniSource Energy balance sheet.
(4)	Collateral provided for energy contracts with counterparties to reduce credit risk exposure.
(5)	Energy Contracts include gas swap agreements (Level 2), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to take advantage of favorable market conditions and reduce exposure to energy price risk. The valuation techniques are described below.
(6)	Interest Rate Swaps are valued based on either the six-month LIBOR index or the Securities Industry and Financial Markets Association (“SIFMA”) Municipal Swap index (Level 2).

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2/19/10

Energy Contracts

TEP, UNS Gas, and UNS Electric primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Where observable inputs are available for substantially the full terms of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange (NYMEX) pricing, adjusted for basin differences, the instrument is categorized in Level 2.

Derivatives valued using an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers are categorized in Level 3. For both power and gas prices, TEP and UNS Electric obtain quotes from brokers, major market participants, exchanges or industry publications as well as its own price experience from active transactions in the market. TEP and UNS Electric primarily use one set of quotations each for power and for gas, and then use the other sources as validation of those prices. The broker providing quotes for power prices states that the market information provided is indicative only, but believes it to be reflective of market conditions as of the time and date indicated. In addition, energy derivatives include contracts where published prices are not readily available. These include contracts for delivery periods during non-standard time blocks, contracts for delivery during only a few months of a given year when prices are quoted only for the annual average, or contracts for delivery at illiquid delivery points. In these cases, TEP and UNS Electric apply certain management assumptions to value such contracts. These assumptions include applying percentage multipliers to value non-standard time blocks, applying historical price curve relationships to calendar year quotes, and including adjustments for transmission and line losses to value contracts at illiquid delivery points. We also consider the impact of counterparty credit risk using current and historical default and recovery rates as well as our own credit risk using credit default swap data. TEP and UNS Electric review these assumptions on a quarterly basis.

The fair value of TEP’s and UNS Electric’s purchase power call options is estimated using an internal pricing model which includes assumptions about market risks such as liquidity, volatility, and contract valuation. This model also considers credit and non-performance risk. UniSource Energy and TEP’s assessment of the significance of a particular input to the fair value measurements requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

K-160

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

The following tables set forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	Year Ended
	December 31, 2009
	- Millions of Dollars -
	UniSource Energy									TEP
	Mark-to-									Mark-to-
	Market									Market
	Contracts			Investments			Total			Contracts
Balance, as of January 1, 2009	$	(17	)	$	11		$	(6	)	$	(1	)
Gains and (Losses) (Realized/Unrealized)
Recorded to:
Net Regulatory Assets — Derivative Instruments		5			—			5			(2	)
OCI		(1	)		—			(1	)		(1	)
Other Expense		—			(2	)		(2	)		—
Cash — Proceeds from Sale of Investment		—			(3	)		(3	)		—
Balance, as of December 31, 2009	$	(13	)	$	6		$	(7	)	$	(4	)

Gains and losses on mark-to-market contracts include the reclassification of realized gains and losses on the settlement of derivative contracts. All of the Level 3 unrealized gains and losses are attributable to the change in fair value of Level 3 assets and liabilities held at the reporting date.

There were no transfers in or out of Level 3 derivatives.

NOTE 13. UNISOURCE ENERGY EARNINGS PER SHARE (EPS)

We compute basic EPS 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.

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

	Years Ended December 31,
	2009		2008		2007
	-In Thousands-
Numerator:
Net Income	$	104,258	$	14,021	$	58,373
Income from Assumed Conversion of Convertible Senior Notes		4,390		—		4,390
Adjusted Numerator	$	108,648	$	14,021	$	62,763
Denominator:
Weighted-average Shares of Common Stock Outstanding
Common Shares Issued		35,653		35,415		35,264
Fully Vested Deferred Stock Units		105		217		222
Participating Securities		100		—		—
Total Weighted-average Shares of Common Stock Outstanding and Participating Securities — Basic		35,858		35,632		35,486
Effect of Diluted Securities
Convertible Senior Notes		4,093		—		4,000
Options and Stock Issuable under Employee Benefit Plans and the Directors’ Plan		499		537		583
Total Shares		40,450		36,169		40,069

K-161

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

For the year ended December 31, 2008, 4 million potentially dilutive shares from the conversion of convertible senior notes, and after-tax interest expense of $4 million was not included in the computation of diluted EPS because to do so would be anti-dilutive.

Stock options to purchase an average of 395,000, 312,000 and 169,000 shares of Common Stock were outstanding during 2009, 2008 and 2007, respectively, but were not included in the computation of EPS because the stock option’s exercise price was greater than the average market price of the Common Stock at year end.

NOTE 14. RELATED PARTY TRANSACTIONS

UniSource Energy incurs corporate costs that are allocated to its subsidiaries, including TEP. Corporate costs are allocated based on a weighted-average of three factors: assets, payroll and revenues. 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 $7 million in each of 2009, 2008 and 2007. Charges allocated to UNS Gas and UNS Electric were $1 million in each of 2009, 2008 and 2007.

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 cost-causative basis. Management believes this method of allocation is reasonable. The charges by TEP to the other companies were $15 million in 2009 and 2008, and $14 million in 2007.

TEP and UNS Electric began selling power to each other in 2008 at prices based on the Dow Jones Four Corners Daily Index. TEP had wholesale power sales to UNS Electric of $23 million in 2009 and $25 million in 2008. UNS Electric had wholesale power sales to TEP of $4 million in 2009 and $9 million in 2008.

TEP charged UNS Electric $3 million for control area services in 2009 and $2 million in 2008. No such services were provided in 2007.

In May 2008, UED began providing energy from its Black Mountain Generating Station (BMGS) to UNS Electric, through a power sale agreement. UED charged UNS Electric $12 million in 2009 and $7 million in 2008 for this energy. UNS Gas charged UNS Electric $5 million for gas used by the BMGS facility in 2009 and $7 million in 2008. In 2008, UNS Gas charged UED $1 million for gas used by BMGS facility.

Southwest Energy Solutions, Inc. (SES), a subsidiary of Millennium, provides a supplemental workforce for TEP and UNS Electric. Types of services provided for TEP include dusk to dawn lighting, facilities maintenance, meter reading, transmission and distribution, line locating, fleet support, and general supplemental support. SES bills TEP for 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. SES charged TEP $15 million in 2009, $15 million in 2008 and $14 million in 2007 for these services. SES provides meter reading services for UNS Electric. SES charged UNS Electric $1 million for these services in 2009, 2008 and 2007.

K-162

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT

Audit Committee
2/19/10

NOTE 15. SALE OF MILLENNIUM’S INVESTMENT IN SABINAS

In June 2009, Millennium finalized a sale of its 50% equity interest in Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas), a Mexican limited liability company. Millennium received an upfront payment of $5 million in January 2009 and a $15 million, three-year, 6%, secured note receivable from Minerales de Monclova, S.A. de C.V. (Mimosa). Principal on the note is due at maturity; interest on the note is due annually on December 31. The $15 million note is included in Investments and Other Property — Other on UniSource Energy’s balance sheet. Millennium recorded a $6 million pre-tax gain on the sale included in Other Income on UniSource Energy’s income statement.

NOTE 16. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The following recently issued accounting standards are not yet reflected in the UniSource Energy and TEP’s financial statements:

• The FASB issued authoritative guidance for transfers of financial assets that clarify and change the criteria for a transfer to be accounted for as a sale, change the amount of a recognized gain/loss on a sale when beneficial interests are received by the transferor, and requires extensive disclosures. This standard is effective for interim and annual periods beginning January 1, 2010. To date, we have not participated in any transfers to which this guidance is applicable.

• The FASB issued authoritative guidance for variable interest entities requiring an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. This standard did not have a material impact on our financial statements on adoption on January 1, 2010.

• The FASB issued authoritative guidance for multiple deliverable revenue arrangements that provides another alternative for determining the selling price of deliverables and eliminates the residual method of allocating consideration. In addition, this pronouncement requires expanded qualitative and quantitative disclosures and is effective for revenue arrangements entered into after January 1, 2011. We are evaluating the impact of this pronouncement.

• The FASB issued amendments that require some new disclosures and clarify some existing disclosure requirements about fair value measurements. The amendments are effective for interim and annual reporting periods beginning January 1, 2010, except for disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in level 3 fair value measurements, which are effective for interim and annual reporting periods beginning January 1, 2011. We are evaluating the impact of these new and revised disclosures on our financial statements.

K-163

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT Audit Committee

2/19/10

NOTE 17. SUPPLEMENTAL CASH FLOW INFORMATION

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

	UniSource Energy
	Years Ended December 31,
	2009			2008			2007
	-Thousands of Dollars-
Net Income	$	104,258		$	14,021		$	58,373
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation and Amortization Expense		176,018			147,690			140,638
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		4,929			6,467			6,897
Amortization of Deferred Debt-Related Costs included in Interest Expense		4,171			3,891			3,831
Provision for Bad Debts		3,583			5,007			3,592
Deferred Income Taxes		58,692			35,739			22,021
California Power Exchange Provision for Wholesale Revenue Refunds		4,172			—			—
Pension and Postretirement Expense		23,594			11,991			14,442
Pension and Postretirement Funding		(30,078	)		(13,928	)		(13,809	)
Gain on Sale of Millennium’s Investment in Sabinas		(5,979	)		—			—
Stock Based Compensation Expense		2,779			2,901			2,693
Excess Tax Benefit from Stock Options Exercised		(3,256	)		(633	)		(541	)
Mark-to-Market Transactions		43			9,281			2,459
Impact of Reapplication of Regulatory Accounting		—			(40,144	)		—
Provision for Navajo Retiree Health Care and Mine Reclamation		—			10,198			—
Amortization of Transition Recovery Asset		—			23,945			77,681
CTC Revenue Refunded		(12,141	)		58,092			—
Over/Under Recovered Purchased Energy Cost		(17,091	)		(10,337	)		2,377
Decrease in Value of Millennium Investments		1,249			2,469			—
Net Unrealized Loss (Gain) on MEH Trading Activities		—			—			2,562
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		17,696			432			4,981
Collateral Posted		12,370			(14,120	)		—
Materials and Fuel Inventory		(24,621	)		(10,176	)		(8,805	)
Accounts Payable		(8,196	)		8,164			(5,057	)
Income Taxes		14,924			(12,720	)		(2,895	)
Interest Accrued		15,956			16,772			10,031
Other Regulatory Liabilities		10,009			7,501			2,903
Taxes Other Than Income Taxes		(48	)		(29	)		1,344
Other		(5,723	)		14,537			(2,952	)
Net Cash Flows — Operating Activities	$	347,310		$	277,011		$	322,766

K-164

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT Audit Committee

2/19/10

	TEP
	Years Ended December 31,
	2009			2008			2007
	-Thousands of Dollars-
Net Income	$	89,248		$	4,363		$	53,456
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation and Amortization Expense		152,901			126,040			119,811
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		3,439			5,039			5,339
Amortization of Deferred Debt-Related Costs included in Interest Expense		2,364			2,826			2,677
Provision for Bad Debts		2,342			2,957			2,161
California Power Exchange Provision for Wholesale Revenue Refunds		4,172			—			—
Deferred Income Taxes		46,721			24,410			8,310
Pension and Postretirement Expense		21,294			10,402			12,683
Pension and Postretirement Funding		(28,330	)		(12,439	)		(12,479	)
Stock Based Compensation Expense		2,121			2,239			2,097
CTC Revenue Refunded		(12,141	)		58,092			—
Over/Under Recovered Purchased Energy Cost		(20,724	)		—			—
Mark-to-Market Transactions		44			9,283			2,459
Impact of Reapplication of regulatory accounting		—			(40,144	)		—
Provision for Navajo Retiree Health Care and Mine Reclamation		—			10,198			—
Amortization of Transition Recovery Asset		—			23,945			77,681
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		9,488			131			4,013
Materials and Fuel Inventory		(23,794	)		(8,774	)		(9,103	)
Accounts Payable		(10,410	)		14,812			(6,230	)
Income Taxes		(2,057	)		10,127			(3,378	)
Interest Accrued		16,142			15,857			10,113
Taxes Other Than Income Taxes		725			(1,011	)		1,463
Other Regulatory Liabilities		10,555			6,449			—
Other		3,964			3,904			(6,961	)
Net Cash Flows — Operating Activities	$	268,064		$	268,706		$	264,112

UED prepaid $2 million for its LIBOR borrowing with Union Bank on July 28 and again on October 30, 2009 in accordance with the terms of the UED Credit Agreement. In August and November 2009, the deposits were applied to the $30 million principal giving rise to a $4 million non-cash financing activity that affected recognized assets and liabilities but did not result in cash receipts or payments.

The proceeds from the issuance of the 2009 Pima A San Juan Bonds and the 2009 Coconino A Bonds were deposited with a trustee and were used in November 2009, to redeem approximately $80 million of 6.95% 1997 Series A City of Farmington, New Mexico Pollution Control Bonds and approximately $15 million of 7.0% 1997 Series B Coconino County, Arizona Pollution Control Bonds. TEP had no cash receipts or payments as a result of this transaction.

In the third quarter of 2008, TEP deposited the Pima B redemption proceeds for its 7.5% collateral trust bonds with a trustee. On August 1, 2008, the deposit was applied to the payment of $128 million of principal plus $5 million of accrued interest upon maturity of the bonds giving rise to a $128 million non-cash financing activity that affected recognized assets and liabilities but did not result in cash receipts or payments.

K-165

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT Audit Committee

2/19/10

Other 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,
	2009		2008			2007
	-Thousands of Dollars-
(Decrease)/Increase to Utility Plant Accruals	$	1,082	$	(25,450	)	$	24,915
Net Cost of Removal of Interim Retirements		43,381		45,100			21,301
Capital Lease Obligations		17,984		16,612			13,259

The non-cash additions to Utility Plant represent accruals for capital expenditures.

The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.

The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.

NOTE 18. ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES

See Note 1 for description of our related accounting policies.

Financial Impact of Derivatives

The net unrealized gains and losses on these contracts reported in AOCI were as follows:

	UniSource Energy and TEP
	2009			2008			2007
	-Millions of Dollars-
Cash Flow Hedges — Unrealized Gains (Losses)
Forward Power Contracts	$	(1	)	$	(7	)	$	—
Gas Price Swaps		—			3			(5	)
Interest Rate Swaps		1			(5	)		(1	)
Total Pre-Tax Unrealized Gains (Losses)	$	—		$	(9	)	$	(6	)
After-Tax Unrealized Gains (Losses) Recorded in AOCI	$	—		$	(5	)	$	(4	)
After-Tax Unrealized (Gains) Losses Reclassified to Net Income	$	1		$	2		$	2

Regulatory Treatment of Commodity Derivatives

Prior to December 2008, unrealized gains and losses resulting from changes in the market prices of non-trading hedges or short-term forward power sales contracts were recorded on the same line in the income statement as the hedged transaction. Beginning in December 2008, as a result of the 2008 TEP Rate Order, which permits the recovery of prudent costs associated with hedging contracts through the PPFAC, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability.

K-166

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT Audit Committee

2/19/10

UniSource Energy and TEP report unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheet as a regulatory asset or a regulatory liability rather than as a component of AOCI or in the income statement. UniSource Energy recorded decreases to regulatory balances of $29 million and increases of $65 million in 2009 and 2008, respectively. In 2007, UniSource Energy recorded an increase to regulatory balances of $6 million. TEP recorded decreases to regulatory balances of $11 million and increases of $19 million in 2009 and 2008, respectively. Realized gains and losses on settled gas swaps are fully recovered through the PPFAC or PGA. In 2009, 2008, and 2007, UniSource Energy realized losses of $51 million, $9 million and $9 million, respectively. TEP realized losses of $29 million, $4 million and $9 million in 2009, 2008, and 2007, respectively.

At December 31, 2009, TEP had contracts that will settle through the third quarter of 2015; UNS Electric had contracts that will settle through the fourth quarter of 2013; and UNS Gas had contracts that will settle through the fourth quarter of 2012.

Other Commodity Derivatives

UniSource Energy and TEP record unrealized gains and losses on energy trading contracts in Wholesale Sales. In 2009, 2008, and 2007, net unrealized gains and losses were less than $0.5 million.

Derivative Volumes

At December 31, 2009, UniSource Energy and TEP had gas swaps totaling 13,321GBtu and 5,658 GBtu, respectively, and power contracts totaling 3,859 GWh and 1,247 GWh, respectively, which were accounted for as derivatives.

The settlement of forward purchased power and sales contracts that do not result in physical delivery were reflected in the financial statements of UniSource Energy and TEP as follows:

	2009			2008			2007
	-Millions of Dollars-
Recorded in Wholesale Sales:
Forward Power Sales	$	23		$	30		$	28
Forward Purchased Power		(21	)		(30	)		(28	)
Net Impact in Wholesale Sales	$	2		$	—		$	—

Credit Risk Adjustment

When the fair value of our derivative contracts are reflected as an asset, the counterparty owes us and this creates credit risk. We minimize our credit risk by (1) entering into transactions with high-quality counterparties; (2) limiting our exposure to each counterparty; (3) monitoring the financial condition of the counterparties; and (4) requiring collateral in accordance with the counterparty master agreements. Using a combination of market credit default swap data and historical recovery rates for subordinated bonds, we consider the impact of counterparty credit worthiness in determining the fair value of our derivatives as well as its possible effect on continued qualification for cash flow hedge accounting. At December 31, 2009, and December 31, 2008, the impact of counterparty credit risk on the fair value of derivative asset contracts was less than $0.5 million.

We also consider the impact of our own credit risk on instruments that are in a net liability position, after deducting collateral posted, using market credit default swap data and allocating the credit risk adjustment to all individual contracts in a net liability position. At December 31, 2009, and December 31, 2008, the impact of our own credit risk was less than $0.5 million.

K-167

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT Audit Committee

2/19/10

CONCENTRATION OF CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations. TEP, UNS Gas and UNS Electric enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and mark-to-market valuations.

TEP, UNS Gas and UNS Electric have contractual agreements for their energy procurement and hedging activities that contain certain provisions that require each company to post collateral under certain circumstances. These circumstances include credit rating downgrades, or a failure to meet certain financial ratios. In the event that such credit events were to occur, TEP, UNS Gas and UNS Electric would have to provide certain credit enhancements in the form of cash or letters of credit to fully collateralize their exposure to these counterparties.

The following table shows the sum of the fair value of all derivative instruments along with net payable position under contracts with credit-risk-related contingent features that are in a net liability position at December 31, 2009. It also shows cash collateral and letters of credit posted, and additional collateral to be posted if credit-risk related contingent features were triggered.

							UniSource
	TEP		UNS Gas		UNS Electric		Energy
	December 31, 2009
	-Millions of Dollars-
Net Liability Position	$	26	$	25	$	20	$	71
Cash Collateral Posted		—		2		—		2
Letters of Credit		1		—		11		12
Additional Collateral to Post if Contingent Features Triggered		26		23		14		63

As of December 31, 2009, TEP had $20 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities, of which four counterparties individually composed greater than 10% of the total credit exposure. At December 31, 2009, UNS Gas and UNS Electric had immaterial exposure to other counterparties.

K-168

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) — DRAFT Audit Committee

2/19/10

NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED)

Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the summer months and peak sales periods for UNS Gas generally occur 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)
2009
Operating Revenue	$	311,857		$	337,784	$	414,239		$	330,544
Operating Income		33,300			59,090		116,858			43,085
Net Income		4,919			31,275		57,646			10,418
Basic EPS		0.14			0.88		1.60			0.29
Diluted EPS		0.14			0.80		1.45			0.28
2008
Operating Revenue	$	330,134		$	360,322	$	387,852		$	319,203
Operating Income		22,017			34,627		13,900			69,899
Net Income (Loss)		(2,614	)		4,747		(11,039	)		22,927
Basic EPS		(0.07	)		0.13		(0.31	)		0.64
Diluted EPS		(0.07	)		0.13		(0.31	)		0.60

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.

	TEP
	First			Second		Third			Fourth
	-Thousands of Dollars-
2009
Operating Revenue	$	213,274		$	271,544	$	357,189		$	254,704
Operating Income		18,572			51,594		108,055			31,902
Net Income (Loss)		(553	)		26,507		55,277			8,017
2008
Operating Revenue	$	228,602		$	294,141	$	323,312		$	233,198
Operating Income		7,460			29,752		6,329			58,969
Net Income (Loss)		(8,862	)		5,765		(12,237	)		19,697

K-169

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (concluded) — DRAFT Audit Committee

2/19/10

The principal unusual items for TEP and UniSource Energy include:

UniSource Energy and TEP

• Fourth Quarter 2009.In December 2009, based on settlement discussions related to its sales to the CPX and CISO, TEP wrote off the remaining receivable balance of $2 million and accrued an additional liability of $2 million resulting in a $4 million ($2.4 million after-tax) reduction in net income.

• Fourth Quarter 2008.In the fourth quarter of 2008, as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations, and consequently, recorded a reduction to fuel expense, O&M and Taxes Other Than Income Taxes of $32 million, $1 million and $7 million, respectively. The total after-tax impact on net income was an increase of $24 million.

• Third Quarter 2008.In the third quarter of 2008, as a result of a settlement between Peabody and the Navajo Generating Station participants, TEP recorded, as fuel expense, the present value of its share of the Navajo Generating Station mine reclamation and postretirement benefit costs, totaling $9 million ($5 million after-tax).

UniSource Energy

• Second Quarter 2009.Millennium recorded a $6 million ($3.6 million after-tax) gain on the sale of its Sabinas investment.

K-170

Schedule II — Valuation and Qualifying Accounts — UniSource Energy

			Additions-
	Beginning		Charged to				Ending
Description	Balance		Income		Deductions		Balance
	-Millions of Dollars-
Year Ended December 31,
Allowance for Doubtful Accounts(1)
2009	$	20	$	4	$	18	$	6
2008(2)		18		5		3		20
2007(2)		17		4		3		18

(1)	TEP, UNS Gas and UNS Electric 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.
(2)	Balances are related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001. The accounts were written off in 2009 as a result of negotiations in the fourth quarter of 2009. See Note 4.

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Schedule II — Valuation and Qualifying Accounts — TEP

			Additions-
	Beginning		Charged to				Ending
Description	Balance		Income		Deductions		Balance
	-Millions of Dollars-
Year Ended December 31,
Allowance for Doubtful Accounts(1)
2009	$	17	$	2	$	15	$	4
2008(2)		17		3		3		17
2007(2)		16		2		1		17

(1)	TEP 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.
(2)	Balances are related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001. The accounts were written off in 2009 as a result of negotiations in the fourth quarter of 2009. See Note 4.

TEP had no deferred tax assets valuation allowance in the periods presented.

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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 such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of December 31, 2009. 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 Exchange Act, 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 are also designed to ensure that information required to be disclosed by UniSource Energy and TEP in the reports that they file or submit under the Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. 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 2009, that has materially affected, or is reasonably likely to materially affect, UniSource Energy or TEP’s internal control over financial reporting.

UniSource Energy’s and TEP’s Management’s Reports on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appear as the first two reports under Item 8 in UniSource Energy’s and TEP’s 2009 Annual Report on Form 10-K, the Report of Independent Registered Public Accounting Firm for UniSource Energy appears as the third report under Item 8, and the Report of Independent Registered Public Accounting Firm for TEP appears as the fourth report under Item 8.

ITEM 9B. — OTHER INFORMATION

None.

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PART III

ITEM 10. — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS

Directors — UniSource Energy

			Board	Director
Name	Age		Committee*	Since
Paul J. Bonavia		58	None		2009
Lawrence J. Aldrich		57	3, 5		2000
Barbara M. Baumann		54	1, 2, 4		2005
Larry W. Bickle		64	3, 4, 5		1998
Elizabeth T. Bilby		70	4, 5		1995
Harold W. Burlingame		69	2, 3, 5		1998
John L. Carter		75	1, 2, 3, 4, 5		1996
Robert A. Elliott		54	1, 3, 5		2003
Daniel W.L. Fessler		68	1, 5		2005
Louise L. Francesconi		57	1, 2, 3		2008
Warren Y. Jobe		69	1, 2, 4		2001
Ramiro G. Peru		54	1, 2		2008
Gregory A. Pivirotto		57	1, 3, 4		2008
Joaquin Ruiz		57	2, 3, 5		2005

*	Board Committees
(1)	Audit
(2)	Compensation
(3)	Corporate Governance and Nominating
(4)	Finance
(5)	Environmental, Safety and Security

Paul J. Bonavia	Mr. Bonavia became Chairman, President and Chief Executive Officer of UniSource Energy and TEP in January 2009. Prior to joining UniSource Energy and TEP, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
Lawrence J. Aldrich	President and Chief Executive Officer of University Physicians Healthcare since January 2009. President of Aldrich Capital Company since January 2007; Chief Operating Officer of The Critical Path Institute from January 2006 to December 2006; General Partner of Valley Ventures, LP from September 2002 to December 2005; Managing Director and Founder of Tucson Ventures, LLC, from February 2000 to September 2002.
Barbara M. Baumann	President and Owner of Cross Creek Energy Corporation since 2003; Executive Vice President of Associated Energy Managers, LLC from 2000 to 2003; former Vice President of Amoco Production Company; Director of St. Mary Land & Exploration since 2002.
Larry W. Bickle	Director of St. Mary Land & Exploration since 1995; Retired private equity investor; Managing Director of Haddington Energy Partners from 1997 to 2005.
Elizabeth T. Bilby	Retired President of Gourmet Products, Inc., an agricultural product marketing company; retired Director of Marketing of Green Valley Pecans.
Harold W. Burlingame	Former Executive Vice President of AT&T; Chairman of ORC Worldwide since December 2004.

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John L. Carter	Retired as Executive Vice President and Chief Financial Officer of Burr Brown Corporation in 1996.
Robert A. Elliott	President and owner of The Elliott Accounting Group since 1983; Director and Corporate Secretary of Southern Arizona Community Bank since 1998; Television Analyst/Pre-game Show Co-host for Fox Sports Arizona since 1999; Chairman of the Board of Tucson Metropolitan Chamber of Commerce from 2002 to 2003; Treasurer of Tucson Urban League from 2002 to 2003; Chairman of the Board of Tucson Urban League from 2003 to 2004; Chairman of the Board of the Tucson Airport Authority from January 2006 to January 2007.
Daniel W.L. Fessler	Professor Emeritus of the University of California; Partner in the law firm of LeBoeuf, Lamb, Greene & MacRae LLP from 1997 to 2003; previously served on the UniSource Energy and TEP boards of directors from 1998 to 2003; Managing Principal of Clear Energy Solutions, LLC since December 2004.
Louise L. Francesconi	Retired Vice President and General Manager of Raytheon Missile Systems.
Warren Y. Jobe	Certified Public Accountant (licensed, but not practicing); Senior Vice President of Southern Company from 1998 to 2001; Executive Vice President and Chief Financial Officer of Georgia Power Company from 1987-1998; Director of WellPoint Health Networks, Inc. from 2001 to December 2004; Director of WellPoint, Inc. since December 2004; Trustee of RidgeWorth Funds since 2004.
Ramiro G. Peru	Executive Vice President and Chief Financial Officer of Phelps Dodge Corporation from 2004 to 2007; Director of WellPoint Health Networks, Inc. since 2003; Director of Southern Peru Copper Corporation from 2002 to 2004; Director of University of Arizona Foundation since 2005.
Gregory A. Pivirotto	Retired President and Chief Executive Officer and Director of University Medical Center Corporation since 1994; Certified Public Accountant since 1978; Director of Arizona Hospital & Healthcare Association from 1997 to 2005.
Joaquin Ruiz	Professor of Geosciences, University of Arizona since 1983; Dean, College of Science, University of Arizona since 2000.

Directors — TEP

			Director
Name	Age		Since
Paul J. Bonavia		58		2009
Michael J. DeConcini		45		2009
Raymond S. Heyman		54		2009
Kevin P. Larson		53		2009

Paul J. Bonavia	Mr. Bonavia became Chairman, President and Chief Executive Officer of UniSource Energy and TEP in January 2009. Prior to joining UniSource Energy and TEP, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
Michael J. DeConcini	Mr. DeConcini joined TEP in 1988 and was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003. In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution. In May 2009, he was named Senior Vice President and Chief Operating Officer.

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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 UniSource Energy and TEP, Mr. Heyman was a member of the Phoenix, Arizona law firm Roshka, Heyman & DeWulf, PLC.

Kevin P. Larson

Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and at TEP’s investment subsidiaries. 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 serves as Treasurer of both organizations. He was named Senior Vice President in September 2005.

Executive Officers of UniSource Energy and TEP

SeeItem 1. Business, Executive Officers of the Registrants.

Information required by Items 401, 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UniSource Energy’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, which information is incorporated herein by reference.

ITEM 11. — EXECUTIVE COMPENSATION

Information concerning Executive Compensation will be contained in UniSource Energy’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, which information is incorporated herein by reference.

ITEM 12. — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

General

At February 23, 2010, UniSource Energy had outstanding 35.9 million shares of Common Stock. As of February 23, 2010, the number of shares of Common Stock beneficially owned by all directors and officers of UniSource Energy as a group amounted to approximately 2% of the outstanding Common Stock.

At February 23, 2010, UniSource Energy owned 100% 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 in UniSource Energy’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, 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 in UniSource Energy’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, which information is incorporated herein by reference.

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Securities Authorized for Issuance Under Equity Compensation Plans

Information concerning securities authorized for issuance under equity compensation plans will be contained in UniSource Energy’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, which information is incorporated herein by reference.

ITEM 13. — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information concerning certain relationships and related transactions, and director independence of UniSource Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks and Insider Participation in UniSource Energy’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, 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 2010 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2009, 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, 2009 and 2008 and for Each of the Three Years in the Period Ended December 31, 2009
UniSource Energy Corporation
Report of Independent Registered Public Accounting Firm		84
Consolidated Statements of Income		86
Consolidated Statements of Cash Flows		87
Consolidated Balance Sheets		88
Consolidated Statements of Capitalization		90
Consolidated Statements of Changes in Stockholders’ Equity		91
Notes to Consolidated Financial Statements		98
Tucson Electric Power Company
Report of Independent Registered Public Accounting Firm		85
Consolidated Statements of Income		92
Consolidated Statements of Cash Flows		93
Consolidated Balance Sheets		94
Consolidated Statements of Capitalization		96
Consolidated Statements of Changes in Stockholder’s Equity		97
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
Schedule II Valuation and Qualifying Accounts		171
3. Exhibits

Reference is made to the Exhibit Index commencing on page 154.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	UNISOURCE ENERGY CORPORATION
Date: February 25, 2010	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: February 25, 2010	/s/ Paul J. Bonavia*
	Paul J. Bonavia
	Chairman of the Board, President and Principal Executive Officer
Date: February 25, 2010	/s/ Kevin P. Larson
	Kevin P. Larson
	Principal Financial Officer
Date: February 25, 2010	/s/ Karen G. Kissinger*
	Karen G. Kissinger
	Principal Accounting Officer
Date: February 25, 2010	/s/ Lawrence J. Aldrich*
	Lawrence J. Aldrich
	Director
Date: February 25, 2010	/s/ Barbara Baumann*
	Barbara Baumann
	Director
Date: February 25, 2010	/s/ Larry W. Bickle*
	Larry W. Bickle
	Director
Date: February 25, 2010	/s/ Elizabeth T. Bilby*
	Elizabeth T. Bilby
	Director
Date: February 25, 2010	/s/ Harold W. Burlingame*
	Harold W. Burlingame
	Director

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Date: February 25, 2010	/s/ John L. Carter*
	John L. Carter
	Director
Date: February 25, 2010	/s/ Robert A. Elliott*
	Robert A. Elliott
	Director
Date: February 25, 2010	/s/ Daniel W.L. Fessler*
	Daniel W.L. Fessler
Date: February 25, 2010	/s/ Louise L. Francesconi*
	Louise L. Francesconi
	Director
Date: February 25, 2010	/s/ Warren Y. Jobe*
	Warren Y. Jobe
	Director
Date: February 25, 2010	/s/ Ramiro Peru*
	Ramiro Peru
	Director
Date: February 25, 2010	/s/ Gregory A. Pivirotto*
	Gregory Pivirotto
	Director
Date: February 25, 2010	/s/ Joaquin Ruiz*
	Joaquin Ruiz
	Director
Date: February 25, 2010	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

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SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TUCSON ELECTRIC POWER COMPANY
Date: February 25, 2010	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: February 25, 2010	/s/ Paul J. Bonavia*
	Paul J. Bonavia
	Chairman of the Board, President and Principal Executive Officer
Date: February 25, 2010	/s/ Kevin P. Larson
	Kevin P. Larson
	Principal Financial Officer and Director
Date: February 25, 2010	/s/ Karen G. Kissinger*
	Karen G. Kissinger
	Principal Accounting Officer
Date: February 25, 2010	/s/ Michael J. DeConcini*
	Director
Date: February 25, 2010	/s/ Raymond S. Heyman*
	Director
Date: February 25, 2010	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

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EXHIBIT INDEX

*2(a)	—	Agreement and Plan of Exchange, dated as of March 20, 1995, between TEP, UniSource Energy and NCR Holding, Inc.
*3(a)	—	Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for year ended December 31, 1996, File No. 1-5924 — Exhibit 3(a).)
*3(b)	—	Bylaws of TEP, as amended as of August 31, 2009 (Form 10-Q for the quarter ended September 30, 2009, File No. 13739 — Exhibit 3.1).
*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 February 27, 2008 (Form 10-K for the year ended December 31, 2007, File No. 13739 — Exhibit 3(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).)
*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).)

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*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).)
*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).)

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*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, 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).)

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*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(i)(8)	—	Supplemental Indenture No. 7 creating a series of bonds designated First Mortgage Bonds, Collateral Series F, dated as of December 1, 2006. (Form 8-K dated December 22, 2006, File Nos. 1-5924 and 1-13739 — Exhibit 4.1.)
*4(i)(9)	—	Supplemental Indenture No. 8 creating a series of bonds designated First Mortgage Bonds, Collateral Series G, dated as of June 1, 2008. (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(b).).
4(i)(10)	—	Supplemental Indenture No. 9 dated as of July 3, 2008.
*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(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).)

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*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(q)(1)	—	Amended and Restated TEP Credit Agreement dated as of August 11, 2006, among TEP, the Lenders Party Thereto, the Issuing Banks Party Thereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 — Exhibit 4.3.)
*4(r)(2)	—	Amendment No. 1 to Amended and Restated TEP Credit Agreement, dated September 1, 2006. (Form 10-Q for the quarter ended September 30, 2006, File No. 1-5924 — Exhibit 4.)
*4(r)(3)	—	Amendment No. 2 to Amended and Restated TEP Credit Agreement, dated May 30, 2008.(Form 10-K dated December 31, 2008, File No. 1-13739)
*4(r)(4)	—	Amendment No. 3 to Amended and Restated TEP Credit Agreement, dated September 16, 2008. (Form 10-K dated December 31, 2008, File No. 1-13739)
*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.)
*4(t)(1)	—	Note Purchase and Guaranty Agreement date August 5, 2008 among UNS Electric, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 10-Q for the quarter ended June 30, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4.).
*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(w)(1)	—	Amended and Restated Credit Agreement dated as of August 11, 2006, among UniSource Energy, the Lenders Party Hereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 — Exhibit 4.1.)

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*4(w)(2)	—	Amendment No. 1 to the Amended and Restated UniSource Energy Credit Agreement, dated September 16, 2008. (Form 10-K dated December 31, 2008, File No. 1-13739)
*4(w)(3)	—	Amendment No. 2 to the Amended and Restated UniSource Energy Credit Agreement, dated February 26, 2009. (Form 10-K dated December 31, 2008, File No. 1-13739)
*4(x)(1)	—	Amended and Restated Credit Agreement dated as of August 11, 2006, 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, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 — Exhibit 4.4.)
*4(x)(2)	—	Amendment No. 1 to the Amended and Restated UNS Gas/UNS Electric Credit Agreement, dated as of April 30, 2007. (Form 10-K dated December 31, 2008, File No. 1-13739)
*4(x)(3)	—	Amendment No. 2 to the Amended and Restated UNS Gas/UNS Electric Credit Agreement, dated as of July 31, 2008. (Form 10-K dated December 31, 2008, File No. 1-13739)
*4(z)(1)	—	Indenture of Trust, dated as of March 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Trust National Association authorizing Industrial Development Revenue Bonds, 2008 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 19, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(a).)
*4(z)(2)	—	Loan Agreement, dated as of March 1, 2008, between the Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 2008 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 19, 2008, File Nos. 1-5924 and1-13739 — Exhibit 4(b).)
*4(aa)(1)	—	Indenture of Trust, dated as of June 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Trust National Association authorizing Industrial Development Revenue Bonds, 2008 Series B (Tucson Electric Power Company Project). (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(a).)
*4(aa)(2)	—	Loan Agreement, dated as of June 1, 2008, between The Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 2008 Series B (Tucson Electric Power Company Project). (Form 8-K dated June 25, 2008, File Nos. 1-5924 and1-13739 — Exhibit 4(b).)
*4(aa)(3)	—	Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project) (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(A)).
*4(aa)(4)	—	Loan Agreement, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company San Juan Project) (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(B)).
*4(aa)(5)	—	Indenture of Trust, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project) (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(C)).
*4(aa)(6)	—	Loan Agreement, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project) (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(D)).

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*4(aa)(7)	—	UniSource Energy Development Credit Agreement, dated as of March 26, 2009, between UED and Union Bank, N.A. and the banks named therein and from time to time parties thereto. (Form 8-K dated April 1, 2009, File No. 1-13739- Exhibit 4(a)).
*4(aa)(8)	—	Guaranty Agreement, dated as of March 26, 2009, made by UniSource Energy in favor of Union Bank, N.A. as Agent for each of the secured parties as defined in the UED Credit Agreement. (Form 8-K dated April 1, 2009, File No. 1-13739- Exhibit 4(b)).
4(aa)(9)	—	Amendment No. 1 to UED Credit Agreement, dated as of February 3, 2010, among UED, Union Bank, N.A. as Agent, and the banks named therein and from time to time party thereto.
*10(a)(1)	—	Lease Agreements, dated as of December 1, 1984, between Valencia and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(1).)
*10(a)(2)	—	Guaranty and Agreements, dated as of December 1, 1984, between TEP and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(2).)
*10(a)(3)	—	General Indemnity Agreements, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors; General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc. as Owner Participants; United States Trust Company of New York, as Owner Trustee; Teachers Insurance and Annuity Association of America as Loan Participant; and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(3).)
*10(a)(4)	—	Tax Indemnity Agreements, dated as of December 1, 1984, between General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc., each as Beneficiary under a separate Trust Agreement dated December 1, 1984, with United States Trust of New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia, Lessee, and TEP, Indemnitors. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(4).)
*10(a)(5)	—	Amendment No. 1, dated December 31, 1984, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(5).)
*10(a)(6)	—	Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(6).)
*10(a)(7)	—	Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(7).)
*10(a)(8)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(8).)
*10(a)(9)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(9).)

K-188

*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 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).)

K-189

*10(a)(20)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 —Exhibit 10(f)(20).)
*10(a)(21)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(21).)
*10(a)(22)	—	Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(22).)
*10(a)(23)	—	Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(15).)
*10(a)(24)	—	Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(16).)
*10(a)(25)	—	Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(25).)
*10(a)(26)	—	Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(26).)
*10(a)(27)	—	Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732 — Exhibit 10(f)(27).)
*10(b)(1)	—	Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(1).)

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*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 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).)

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*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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 — Exhibit 10(a).)
*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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 — Exhibit 10(b).)
*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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 — Exhibit 10(c).)
*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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 — Exhibit 10(d).)
*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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 — Exhibit 10(e).)
*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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 — Exhibit 10(f).)

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*10(b)(20)	—	Amendment No. 4, dated as of June 1, 2006, 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 Cotrustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 8-K dated June 12, 2006, File No.1-5924 — Exhibit 10.1.)
*10(b)(21)	—	Amendment No. 4, dated as of June 1, 2006, 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 Cotrustee, respectively, under a Trust Agreement with Selco Service Corporation as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 — Exhibit 10.2.)
*10(b)(22)	—	Amendment No. 4, dated as of June 1, 2006, 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 Cotrustee, respectively, under a Trust Agreement with Emerson Finance LLC as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 — Exhibit 10.3.)
*10(b)(23)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, 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 Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 — Exhibit 10.4.)
*10(b)(24)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Selco Service 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 Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 — Exhibit 10.5.)
*10(b)(25)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Emerson Finance 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 Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 — Exhibit 10.6.)
*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).)

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*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 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).)

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*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(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(m)	—	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.) (Form 10-K for the year ended December 31, 2004, File No. 1-5924 — Exhibit 10(q))
+*10(n)	—	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(o)(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)	—	UniSource Energy 2006 Omnibus Stock and Incentive Plan (Form S-8 dated January 31, 2007. File No. 333-140353.)
+*10(q)	—	Stock Option Agreement between UniSource Energy and Raymond S. Heyman dated as of September 15, 2005 (Form 10-K for the year ended December 31, 2007, File No. 1-13739, Exhibit 10(r).)
+*10(r)	—	Management and Directors Deferred Compensation Plan II of UniSource Energy. (Form S-8 dated December 30, 2008, File No. 333-156491.)
+*10(s)	—	Letter of Employment dated as of December 9, 2008, between UniSource Energy and Paul J. Bonavia. (Form 8-K dated December 15, 2008, File No. 1-13739.)
+*10(t)	—	Amended and Restated Officer Change in Control Agreement, dated as of October 9, 2009, between TEP and Michael J. DeConcini (including a schedule of other officers who are covered by substantially identical agreements) (Form 8-K dated October 13, 2009, File No. 1-13739 — Exhibit 10(A)).
+*10(u)	—	Officer Change in Control Agreement, dated as of October 9, 2009, between UniSource Energy Corporation and Raymond S. Heyman (Form 8-K dated October 13, 2009, File No. 1-13739 — Exhibit 10(B)).
+*10(v)	—	Employment Agreement, dated May 4, 2009, between UniSource Energy and Paul J. Bonavia (Form 10-Q for the quarter ended March 31, 2009, File No. 13739 — Exhibit 4).
12(a)	—	Computation of Ratio of Earnings to Fixed Charges — TEP.
12(b)	—	Computation of Ratio of Earnings to Fixed Charges — UniSource Energy.

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21	—	Subsidiaries of the Registrants.
23	—	Consent of Independent Registered Public Accounting Firm.
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 Paul J. Bonavia.
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 Paul J. Bonavia.
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).

(*)	Previously filed as indicated and incorporated herein by reference.
(+)	Management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by item 601(b)(10)(iii) of Regulation S-K.
**	Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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