Uns Energy (UNS) 10-K 2010 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, 2010

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 to Section 12(b) of the Exchange Act:

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

Securities registered pursuant to Section 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	Yesþ	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 $1,082,660,902 based on the last reported sale price thereof on the consolidated tape on June 30, 2010.

At February 15, 2011, 36,605,748 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At February 15, 2011, 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) on Form 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 2011 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	5
Fuel Supply	8
Water Supply	9
Transmission Access	9
Rates and Regulation	10
TEP’s Utility Operating Statistics	12
Environmental Matters	13
UNS Gas	16
Service Territory and Customers	16
Gas Supply and Transmission	16
Rates and Regulation	17
Environmental Matters	17
UNS Electric	18
Service Territory and Customers	18
Power Supply and Transmission	18
Rates and Regulation	19
Environmental Matters	20
Millennium	20
Other	20
Employees	21
Executive Officers of the Registrants	21
SEC Reports Available on UniSource Energy’s Website	22
Item 1A. — Risk Factors	23
Item 1B. — Unresolved Staff Comments	28
Item 2. — Properties	28
TEP Properties	28
UES Properties	29
UED Properties	30
Item 3. — Legal Proceedings	30
Item 4. — Removed and Reserved	30
— PART II —
Item 5. — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity	31
Item 6. — Selected Consolidated Financial Data	32
UniSource Energy	32
TEP	33
Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
UniSource Energy Consolidated	34
Outlook and Strategies	34
Results of Operations	35
Liquidity and Capital Resources	37
Tucson Electric Power Company	42
Results of Operations	42

ii

Factors Affecting Results of Operations	50
Liquidity and Capital Resources	53
UNS Gas	61
Results of Operations	61
Factors Affecting Results of Operations	62
Liquidity and Capital Resources	63
UNS Electric	65
Results of Operations	65
Factors Affecting Results of Operations	67
Liquidity and Capital Resources	68
Millennium	70
Results of Operations	70
Factors Affecting Results of Operations	70
Other Non-Reportable Business Segments	71
Results of Operations	71
Critical Accounting Policies	71
Recently Issued Accounting Pronouncements	75
Safe Harbor for Forward-Looking Statements	76
Item 7A. — Quantitative and Qualitative Disclosures about Market Risk	76
Item 8. — Consolidated Financial Statements and Supplementary Data	82
Management’s Report on Internal Controls Over Financial Reporting	82
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 and Comprehensive Income	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 and Comprehensive Income	97
Notes to Consolidated Financial Statements	98
Note 1. Nature of Operations and Summary of Significant Accounting Policies	98
Note 2. Regulatory Matters	107
Note 3. Segment and Related Information	118
Note 4. Commitments and Contingencies	121
Note 5. Utility Plant and Jointly-Owned Facilities	128
Note 6. Debt, Credit Facilities and Capital Lease Obligations	130
Note 7. Stockholders’ Equity	137
Note 8. Income Taxes	139
Note 9. Employee Benefit Plans	142
Note 10. Share-Based Compensation Plan	151
Note 11. Fair Value Measurements	155
Note 12. UniSource Energy Earnings Per Share (EPS)	160
Note 13. Millennium Investments	161
Note 14. Recently Issued Accounting Pronouncements	162
Note 15. Supplemental Cash Flow Information	163
Note 16. Accounting for Derivative Instruments, Trading Activities and Hedging Activities	165
Note 17. Quarterly Financial Data (Unaudited)	168
Item 9. — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	171
Item 9A. — Controls and Procedures	171
Item 9B. — Other Information	171

iii

— PART III —
Item 10. — Directors, Executive Officers and Corporate Governance of the Registrants	172
Item 11. — Executive Compensation	174
Item 12. — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	174
Item 13. — Certain Relationships and Related Transactions and Director Independence	175
Item 14. — Principal Accountant Fees and Services	175
— PART IV —
Item 15. — Exhibits and Financial Statement Schedules	175
Signatures	176
Exhibit Index	179
Exhibit 3(a)
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
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

iv

DEFINITIONS

The abbreviations and acronyms used in the 2010 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
AMT	Alternative Minimum Tax
AOCI	Accumulated Other Comprehensive Income
APS	Arizona Public Service Company
ARO	Asset Retirement Obligation
BART	Best Available Retrofit Technology
BMGS	Black Mountain Generating Station
Btu	British thermal unit(s)
CCRs	Coal combustion residuals
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
CO2	Carbon dioxide
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
EE Standards	Electric Energy Efficiency Standards
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; 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 is being credited to customers through the PPFAC
Four Corners	Four Corners Generating Station
GAAP	Generally Accepted Accounting Principles
Gas EE Standards	Gas Utility Energy Efficiency Standards
GHG	Greenhouse gases
GWh	Gigawatt-hour(s)
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)

v

kV	Kilovolt(s)
LIBOR	London Interbank Offered Rate
Luna	Luna Energy Facility
Mark-to-Market Adjustments	Forward energy sales and purchase contracts that are considered to be Derivatives and 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
NMED	New Mexico Environmental Improvement Board
NOx	Nitrogen oxide
O&M	Operations and Maintenance Expense
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
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
PV	Photovoltaic
RES	Renewable Energy Standard and Tariff
Reimbursement Agreement	Reimbursement Agreement dated as of December 14, 2010 among TEP as borrower and a group of financial institutions.
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
SERP	Supplemental Executive Retirement Plan
SCR	Selective catalytic reduction
SES	Southwest Energy Solutions
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	Second Amended and Restated Credit Agreement between TEP and a syndicate of Banks, dated as of November 9, 2010

vi

TEP Letter of Credit Facility	Letter of credit facility under the TEP Credit Agreement
TEP Revolving Credit Facility	Revolving credit facility under the TEP Credit Agreement
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.
Transwestern	Transwestern Pipeline Company
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 Credit Agreement	Second Amended and Restated Credit Agreement between UniSource Energy and a syndicate of banks, dated as of November 9, 2010
UniSource Energy	UniSource Energy Corporation
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES
UNS Gas	UNS Gas, Inc., a wholly-owned subsidiary of UES
UNS Gas/UNS Electric Revolver	Revolving credit facility under the Second 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 November 9, 2010
Valencia	Valencia power plant owned by UNS Electric
VEBA	Voluntary Employee Beneficiary Association
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 elsewhere 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 Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), UniSource Energy Development Company (UED) and Millennium Energy Holdings, Inc. (Millennium). We conduct our business in four primary business segments — TEP, UNS Gas, Inc. (UNS Gas), UNS Electric, Inc. (UNS Electric), 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 and 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) in northwestern Arizona. The facility, which includes two natural gas-fired combustion turbines, provides energy to UNS Electric through a power sales agreement.

Millennium has existing investments in unregulated businesses that represent less than 1% of UniSource Energy’s total assets as of December 31, 2010; no new investments are planned in Millennium. Southwest Energy Solutions (SES), a subsidiary of Millennium, provides supplemental labor and meter reading services to TEP, UNS Gas and UNS Electric.

UniSource Energy was incorporated in the state of Arizona in 1995 and obtained regulatory approval to form a holding company in 1997. TEP and UniSource Energy exchanged shares of stock in 1998, making TEP a subsidiary of UniSource Energy.

K-1

BUSINESS SEGMENT CONTRIBUTIONS

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

	2010			2009		2008
	-Millions of Dollars-
TEP	$	107		$	89	$	4
UNS Gas		9			7		9
UNS Electric		10			6		4
Millennium		(13	)		2		—
Other(1)		(2	)		—		(3	)
Consolidated Net Income	$	111		$	104	$	14

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

See Note 3 for additional financial information regarding our business segments.

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

Rates and Regulation of TEP, UNS Gas and UNS Electric

The Arizona Corporation Commission (ACC) regulates portions of TEP, UNS Gas and UNS Electric’s utility accounting practices and energy rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. Our regulated utility 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 (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 while depreciation and retirement of utility plant reduce the rate base.

The retail rates charged by TEP, UNS Gas and UNS Electric include pass-through mechanisms that allow each utility to recover the actual costs of their fuel and power purchases.

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 2010, TEP’s electric utility operations contributed 77% 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 403,000 retail customers in southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately 1 million people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells electricity to other utilities and power marketing entities in the western United States.

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 economic conditions, seasonal weather patterns, demand side management (DSM) initiatives and increasing use of energy efficient products.

K-2

Customer Base

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

	2010			2009			2008
Residential		42	%		42	%		41	%
Commercial		21	%		21	%		21	%
Non-mining Industrial		23	%		23	%		24	%
Mining		12	%		11	%		11	%
Public Authority		2	%		3	%		3	%

Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. As a result of weak economic conditions during the last three years, TEP’s customer base grew at a slower rate than it had in prior years. In 2008, 2009 and 2010 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.

Two of TEP’s largest retail customers are in the copper mining industry. TEP’s kilowatt-hour (kWh) sales to mining customers depend on a variety of factors including the market price of copper, the rates paid by mining customers and the mines’ potential development of their own electric generation resources.

We expect the number of TEP’s retail customers to increase at a rate of 0.5% in 2011 and approximately 1% in 2012. We cannot predict if the rate of growth will return to historic levels.

Sales Volumes

Weak economic conditions and the implementation of energy efficiency programs have had a negative impact on electricity sales. In 2008, TEP’s total retail kWh sales decreased by 1.4% compared with 2007. This was the first year-over-year decrease in TEP’s retail kWh sales since 2002. In 2009 and 2010, TEP’s kWh sales declined by 1.4% and 0.8%, respectively, below the prior year level.

This compares with average annual increases in retail kWh sales of 4% from 2003 to 2007. In 2011, we expect kWh sales to TEP’s retail customers to increase by less than 1% over the 2010 sales level.

Energy Service Providers

TEP’s retail customers are eligible to choose an alternative energy service provider (ESP); however, none are currently being served 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. SeeGenerating and Other Resources, Purchases and Interconnections, below.

K-3

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 cover 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 (SRP) Agricultural Improvement and Power District — 100 MW, expires in May 2016. Under the current terms of the contract, TEP receives a demand charge of approximately $1.8 million per month, or $22 million annually, and provides the energy at a price based on TEP’s average fuel cost. Beginning in June 2011, SRP will be required to purchase 73,000 MWhs per month, or 876,000 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 Market 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 225,000 MWhs. Since 2010, the price of 50% of the MWh sales from June to September has been based on the Palo Verde Market Index. In 2010, approximately 25% of the total energy sold to NTUA was priced based on the Palo Verde Market Index.

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

Short-Term Sales

Forward contracts commit TEP 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. TEP also engages in short-term sales by selling energy in the daily or hourly markets at fluctuating spot market prices and making other non-firm energy sales. Since January 1, 2009, all revenues from short-term wholesale sales offset fuel and purchased power costs and 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.

K-4

GENERATING AND OTHER RESOURCES

At December 31, 2010, TEP owned or leased 2,245 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		4	Tucson, AZ		1967	Coal/Gas		156	TEP		100.0		156
Sundt Internal Combustion Turbines			Tucson, AZ		1972-1973	Gas/Oil		50	TEP		100.0		50
DeMoss Petrie			Tucson, AZ		1972	Gas/Oil		85	TEP		100.0		85
North Loop			Tucson, AZ		2001	Gas		95	TEP		100.0		95
Springerville Solar Station			Springerville, AZ		2002-2010	Solar		6	TEP		100.0		6
Community Solar Projects			Tucson, AZ		2010	Solar		2	TEP		100.0		2
Total TEP Capacity(2)													2,245

(1)	Leased assets, as of December 31, 2010.
(2)	Excludes 799 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2010, total owned capacity was 1,858 MW and leased capacity was 387 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 optional fair market value renewal options as well as 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 optional fair market value renewal options as well as a fixed-price purchase provision of $120 million. TEP is currently exploring its purchase and lease renewal options on all of these leases.

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.

See Note 6 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 leases.

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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.

Until March 2010, Sundt Unit 4 was leased by TEP with a lease term expiration of January 2011. In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4 from the equity owner for approximately $52 million. In April 2010, TEP redeemed the outstanding Sundt Unit 4 lease debt of $5 million, terminated the lease agreement and caused the title of Sundt Unit 4 to be transferred to TEP.

Renewable Energy Resources

Owned Resources

The Springerville Generating Station Solar System, which is located near TEP’s Springerville coal-fired facility in eastern Arizona, includes 43,380 photovoltaic (PV) modules, with a total capacity of 6.4 MW. TEP began building the system in 2000 and has continued to expand it for several years, including a 1.8 MW addition in 2010.

In 2010, TEP completed the construction of a 1.6 MW single axis tracking PV array in Tucson.

Power Purchase Agreements

TEP has power purchase agreements (PPAs) for 130 MW of capacity from solar resources, 50 MW of capacity from wind resources and 2 MW of capacity from a landfill gas generation plant. These resources are expected to be developed over the next several years. The 20-year solar PPAs contain options that would allow TEP to purchase all or part of the related project at a future period. SeeRates and Regulation, Renewable Energy Standard and Tariffbelow 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 PPAs 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 doing so is more economical than generating its own energy.

TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities. 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) and subject to the oversight of the 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 that are operated, but not owned by TEP. These facilities are located at the same site as TEP’s Springerville Units 1 and 2. Tri-State Generation and Transmission Association, Inc. (Tri-State) is leasing 100% of Unit 3 from a financial owner. Unit 4 began commercial operation in December 2009 and is owned by Salt River Project (SRP). The owners of Units 3 and 4 compensate TEP for operating the facilities and pay an allocated portion of the fixed costs related to the Springerville Common Facilities and Coal Handling Facilities. 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.

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Peak Demand and Resources

Peak Demand	2010			2009			2008			2007			2006
							-MW-
Retail Customers		2,333			2,354			2,376			2,386			2,365
Firm Sales to Other Utilities		340			385			394			369			331
Coincident Peak Demand (A)		2,673			2,739			2,770			2,755			2,696
Total Generating Resources		2,245			2,229			2,204			2,204			2,194
Other Resources(1)		799			781			966			785			719
Total TEP Resources (B)		3,044			3,010			3,170			2,989			2,913
Total Margin (B) — (A)		371			271			400			234			217
Reserve Margin (% of Coincident Peak Demand)		14	%		10	%		14	%		8	%		8	%

⁽¹⁾ Other Resources include firm power purchases and interruptible retail and wholesale loads. Additional firm power purchases were made in 2009 and 2010 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 through 2010 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 2010 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.

Forecasted retail peak demand for 2011 is 2,241 MW, compared with actual peak demand of 2,333 MW in 2010. In 2010, cooling degree days were 5% above the ten-year average. TEP’s 2011 estimated retail peak demand is based on normal weather patterns and total retail kWh sales similar to 2010 levels. TEP believes it will have sufficient resources to meet expected demand in 2011 with its existing generation capacity and power purchase agreements.

Future Generating Resources

TEP expects to add approximately 28 MW of new solar PV resources in 2011 through 2014. We will 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 peaking resources of 75 to 150 MW may be required in 2018.

K-7

FUEL SUPPLY

Fuel Summary

Fuel cost and usage information is provided below:

	Average Cost per MMBtu						Percentage of Total Btu
	Consumed						Consumed
	2010		2009		2008		2010			2009			2008
Coal	$	2.23	$	2.11	$	2.08		90	%		90	%		93	%
Gas	$	4.69	$	4.51	$	8.02		10	%		10	%		7	%
All Fuels	$	2.47	$	2.34	$	2.52		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 2010, 2009 and 2008 was $41.99, $39.81, and $39.67, respectively.

		2010 Coal				Avg.
		Consumption		Contract		Sulfur
Station	Coal Supplier	(tons in 000’s)		Expiration		Content			Coal Obtained From (A)
Springerville	Peabody Coalsales		5,154		2020		0.9	%	Lee Ranch Coal Co.
Four Corners	BHP Billiton		362		2016		0.8	%	Navajo Indian Tribe
San Juan	San Juan Coal Co.		1,194		2017		0.8	%	Federal and State Agencies
Navajo	Peabody Coalsales		510		2019		0.4	%	Navajo and Hopi Indian Tribes
Sundt	Peabody Coalsales		220		2012		0.5	%	Twentymile Mine

(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 sole owner (or lessee), of the Springerville Units 1 and 2 and Sundt Unit 4. 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. In the past, Sundt Unit 4 has been predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with methane, a renewable energy resource, piped in from a nearby landfill. From September through December of 2010, TEP fueled Sundt Unit 4 on natural gas, taking advantage of the more economic natural gas prices. In 2011 and 2012, TEP expects to obtain coal for Sundt Unit 4 from the Twentymile Mine in Colorado.

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

Generating Facilities Operated by Others

TEP also participates in jointly-owned coal-fired generating facilities at the Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo) and the San Juan Generating Station (San Juan). Four Corners which is operated by Arizona Public Service (APS) and San Juan, which is operated by PNM, are mine mouth generating stations located adjacent to the coal reserves. Navajo, which is 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.

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Natural Gas Supply

TEP typically uses generation from its facilities fueled by natural gas, in addition to energy from its coal-fired facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs. TEP purchases gas from Southwest Gas Corporation under a retail tariff for North Loop’s 95 MWs of internal combustion turbines and receives distribution service under a transportation agreement for DeMoss Petrie, an 85 MW internal combustion turbine, both of which are located in Tucson. TEP purchases capacity from El Paso Natural Gas Company (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 facilities 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 Navajo. TEP has a 7.5% ownership interest in Navajo Units 1, 2 and 3 (totaling 168 MW of 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.

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 build 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 60-mile 345kV transmission line from Tucson to Nogales, Arizona. The project development agreement was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales and surrounding Santa Cruz County by building a second transmission line to Nogales. Since receiving approval from the ACC for construction along a specific route in 2002, TEP has been working to obtain all other required permits from state and federal agencies in addition to evaluating alternatives for improving service reliability in the area.

As of December 31, 2010, 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 Santa Cruz County.

K-9

RATES AND REGULATION

2008 TEP Rate Order

In November 2008, the ACC issued an order that resolved a rate case filed by TEP in July 2007. Prior to the 2008 TEP Rate Order, TEP’s rates had remained unchanged since 2000.

Base Retail Rates

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. The average base rate for the 12 months ended December 31, 2010 was 8.94 cents per kWh and includes approximately 3.01 cents per kWh for fuel and purchased power costs.

Purchased Power and Fuel Adjustment Clause

TEP’s PPFAC became effective January 1, 2009. The PPFAC allows TEP to recover its fuel and purchased power costs, including demand charges, transmission costs and the prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward component and a true-up component.

• The forward component is 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 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.

• As of April 1, 2010, the PPFAC rate of 0.09 cents per kWh includes a forward component credit of 0.08 cents per kWh and a true-up component charge of 0.17 cents per kWh.

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 sulfur dioxide (SO₂) emission allowances.

On a cash basis, Fixed CTC revenue to be refunded ($58 million collected from May 2008 to November 30, 2008) is being credited to customers as an offset to the PPFAC. 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 by the end of 2011.

Base Rate Increase Moratorium

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

Notwithstanding the rate increase moratorium, base rates and adjustor mechanisms may be changed in emergency conditions 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 regulations.

Renewable Energy Standard and Tariff

The ACC’s Renewable Energy Standard and Tariff (RES) requires TEP, UNS Electric and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC and the approved cost of carrying out those plans are recovered from retail customers through the RES surcharge. Any surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in TEP’s financial statements as a regulatory asset or liability.

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In 2010, TEP spent $36 million on RES implementation and met the 2010 renewable energy target of 2.5%. TEP expects to collect $36 million in surcharges from retail customers in 2011 to implement its RES plan and expects to meet the 2011 renewable energy target of 3%.

For more information, seeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff.

Electric Energy Efficiency Standards and Decoupling

In August 2010, the ACC approved new Electric Energy Efficiency Standards (EE Standards) designed to require TEP, UNS Electric and other affected electric utilities to implement cost effective DSM programs. In 2011, the EE Standards target total retail kWh savings equal to 1.25% of 2010 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail kWh sales of 22% by 2020. The EE Standards provide for the recovery of costs to implement the DSM programs.

The EE Standards can be met by: new and existing DSM programs; direct load control programs; and by a portion of energy efficient building codes. The EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s DSM programs and rates charged to customers for such programs are subject to approval by the ACC.

Decoupling

In December 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona’s EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring utility rates to separate the recovery of fixed costs from the level of energy consumed. The policy statement allows affected utilities to file rate decoupling proposals in their next general rate case. TEP expects to file its next general rate case on or after June 30, 2012.

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.

Line Extension Policy

Pursuant to the 2008 TEP Rate Order, TEP began charging customers for the total cost of new line extensions, eliminating TEP’s prior practice of providing a portion of line extensions free of charge to its customers. Such charges are accounted for by TEP as contributions in-aid of construction. 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 was eligible for inclusion in rate base.

Based on actions recently taken by the ACC in other utility proceedings, it is possible the ACC may take action to reinstate free footage for TEP customers in the future. Such a change would serve to decrease contributions in-aid of construction and increase net capital outlays by TEP.

K-11

TEP UTILITY OPERATING STATISTICS

	For Years Ended December 31,
	2010			2009			2008			2007		2006
Generation and Purchased Power — kWh (000)
Remote Generation (Coal)		9,077,032			9,134,183			10,438,864			11,001,318		10,854,710
Local Tucson Generation (Oil, Gas & Coal)		1,492,885			1,131,399			1,016,254			1,065,778		966,476
Purchased Power		2,760,002			3,677,930			3,692,873			2,046,864		1,680,495
Total Generation and Purchased Power		13,329,919			13,943,512			15,147,991			14,113,960		13,501,681
Less Losses and Company Use		779,993			793,791			1,265,831			921,024		885,120
Total Energy Sold		12,549,926			13,149,721			13,882,160			13,192,936		12,616,561
Sales — kWh (000)
Residential		3,869,540			3,905,696			3,852,707			4,004,797		3,778,269
Commercial		1,963,469			1,988,356			2,034,453			2,057,982		1,959,141
Industrial		2,138,749			2,160,946			2,263,706			2,341,025		2,278,344
Mining		1,079,327			1,064,830			1,095,962			983,173		924,898
Public Authorities		240,703			250,915			255,817			247,430		260,767
Total — Electric Retail Sales		9,291,788			9,370,743			9,502,645			9,634,407		9,201,419
Electric Wholesale Sales		3,258,138			3,778,978			4,379,515			3,558,529		3,415,142
Total Electric Sales		12,549,926			13,149,721			13,882,160			13,192,936		12,616,561
Operating Revenues (000)
Residential	$	372,212		$	377,761		$	351,079		$	362,967	$	343,459
Commercial		217,032			219,694			211,639			213,364		203,284
Industrial		159,937			163,720			164,849			168,279		165,068
Mining		62,112			61,033			55,619			48,707		43,724
Public Authorities		19,128			19,865			19,146			18,332		18,935
RES and DSM		37,767			25,443			2,781			—		—
Other		—			—			415			4,822		2,684
Total — Electric Retail Sales		868,188			867,516			805,528			816,471		777,154
CTC To Be Refunded		—			—			(58,092	)		—		—
Wholesale Revenue-Long Term		55,653			48,249			57,493			55,788		51,442
Wholesale Revenue-Short Term		71,146			84,059			197,415			125,369		112,309
California Power Exchange Provision for Wholesale Refunds		(2,970	)		(4,172	)		—			—		—
Transmission		20,863			18,974			17,173			14,842		13,391
Other Revenues		112,099			84,361			72,292			58,033		34,698
Total Operating Revenues	$	1,124,979		$	1,098,987		$	1,091,809		$	1,070,503	$	988,994
Customers (End of Period)
Residential		366,217			365,157			363,861			361,945		357,646
Commercial		35,877			35,759			35,432			34,759		34,104
Industrial		635			629			633			641		664
Mining		2			2			2			2		2
Public Authorities		62			61			61			61		61
Total Retail Customers		402,793			401,608			399,989			397,408		392,477
Average Retail Revenue per kWh Sold (cents)
Residential		9.6			9.7			9.1			9.1		9.1
Commercial		11.1			11.0			10.4			10.4		10.4
Industrial and Mining		6.9			7.0			6.6			6.6		6.6
Average Retail Revenue per kWh Sold		9.3			9.3			8.5			8.5		8.4
Average Revenue per Residential Customer	$	1,018		$	1,036		$	965		$	1,003	$	971
Average kWh Sales per Residential Customer		10,580			10,708			10,621			11,129		10,681

K-12

ENVIRONMENTAL MATTERS

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

Clean Air Act Requirements

TEP generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $18 million in 2010, $24 million in 2009 and $73 million in 2008 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 2011 and $56 million in 2012. In addition, TEP recorded operating expenses of $14 million in 2010, $13 million in 2009 and $14 million in 2008 related to environmental compliance. TEP expects to record $10 million in operating expenses related to environmental compliance in 2011. 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 the PNM Consent Decree, a 2005 settlement agreement between PNM, environmental activist groups, and the New Mexico Environment Department — the co-owners of San Juan installed new pollution control equipment at the generating station to reduce the emissions of mercury, particulate matter, NOx, and SO₂. 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. TEP’s share of stipulated penalties at San Juan was $1 million in 2008. 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.

TEP has sufficient Emission Allowances to comply with Acid Rain SO₂ regulations.

EPA Information Request

TEP is responding to a request received in October 2010 from the EPA under Section 114 of the Clean Air Act for information regarding projects at, and operations of, the Sundt Generating Station. TEP owns and operates all four units at Sundt. Units 1, 2 and 3 can be operated on either gas or diesel oil. Unit 4 can be operated on either gas or coal.

In April 2009, APS received a request from the EPA under Section 114 of the Clean Air Act for information regarding projects at, and operations of, Four Corners. Four Corners is operated by APS and includes five coal-fired generating units. TEP has a 7% ownership interest in Units 4 and 5, totaling 110 MW. APS responded to the request in August 2009.

The EPA uses information obtained from such requests to determine if additional action is necessary. TEP cannot predict whether the EPA will take further action at Sundt or Four Corners, or project the impact of any such action.

Hazardous Air Pollutant Requirements

The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In October 2009, EPA entered into a consent order through which it agreed to develop rules establishing standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units and to issue final rules by November 2011.

Depending on the stringency of the EPA rule, emission controls may be required at some or all coal-fired units by 2014 or later. Whether emission 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 mercury requirements under the federal standard.

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Arizona adopted mercury emission rules in 2007 requiring a 90% reduction in emissions from coal-fired units. Due to potential inconsistency between the Arizona rule and the pending EPA rule, TEP and the Arizona Department of Environmental Quality reached an agreement in January 2009 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. In 2010, the agreement provisions were incorporated into the Springerville and Sundt operating permits and the agreement was terminated.

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 $5 million for Springerville Units 1 and 2. TEP expects the annual operating expenses for such equipment would be approximately $3 million, once all installations were completed.

Climate Change

In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al v. EPA, that carbon dioxide (CO₂) and other greenhouse gases (GHGs) are air pollutants under the Clean Air Act. In December 2009, EPA issued a final Endangerment Finding, stating that GHGs endanger public health and welfare. The EPA issued final GHG regulations for new motor vehicles in April 2010, triggering GHG permitting requirements for power plants under the Clean Air Act. As of January 2, 2011, air quality permits for new sources and modifications of existing sources must include an analysis for GHG controls. In the near term, based on our current construction plans, we do not expect the new permitting requirements to impact TEP or UNS Electric.

On a national level, the debate continues over the direction of domestic climate policy. Meanwhile, several states have developed state-specific policies or regional initiatives to reduce GHG 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.

In 2010, New Mexico adopted regulations limiting GHG emissions from power plants and providing for participation in the Western Climate Initiative. Several parties are attempting to modify or rescind these regulations. We cannot predict if, or when, these new regulations will impact the generating output or cost of operations at San Juan and Luna.

Based on the competing proposals to regulate GHG 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 Rules

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 rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA.

The San Juan, Four Corners and Navajo 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. TEP cannot predict the ultimate outcome of these matters.

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San Juan

In December 2010, the EPA proposed a federal implementation plan under the Clean Air Act, addressing, among other things, regional haze requirements for San Juan. The EPA plan proposes that the BART for nitrogen oxides at San Juan is a technology known as selective catalytic reduction (SCR). The EPA’s proposal gives the San Juan participants three years from the date of the final rule to achieve compliance. A final federal implementation plan is expected in 2011.

In June 2010, the New Mexico Environment Department (NMED) filed its proposed regional haze state implementation plan with the New Mexico Environmental Improvement Board. The plan also proposed that the BART for nitrogen oxides at San Juan is the installation of SCRs. However, the NMED’s plan also required a technology known as sorbent injection, and it gave the San Juan participants five years to achieve compliance. The NMED withdrew its proposed implementation plan after the EPA filed its proposal.

PNM, the operator at San Juan, has indicated that it intends to vigorously challenge the EPA’s proposal, based on its own analysis concluding that SCR is not the BART for that plant.

TEP’s share of capital expenditures related to the installation of SCRs at San Juan is estimated to be $202 million. This estimate is based on a 2010 cost analysis of the installation of SCR technology over a five-year period. The cost of the three-year installation proposed by the EPA could increase the cost of compliance. Adding this technology to San Juan would also increase operating costs at the generating station.

Four Corners

In October 2010, EPA issued a proposed federal implementation plan for BART at Four Corners, which was supplemented in February 2011. If approved, the revised plan would require the installation of SCRs on Units 4 and 5. TEP’s estimated share of the capital costs to install these SCRs is approximately $35 million. Once the EPA finalizes the BART rule for Four Corners, the Four Corners participants would have until 2018 to achieve compliance.

Navajo

SRP, on behalf of the owners, is currently participating in an EPA-sanctioned stakeholder process designed to determine BART for Navajo. If SCR is determined by the EPA to be BART at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCRs at Navajo could result in an increase in the level of particulate emissions from the plant and require the installation of baghouses. TEP’s estimated share of capital expenditures related to the installation of baghouses at Navajo is $43 million. The exact level and cost of pollution control required will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.

Coal Combustion Residuals

In June 2010, the EPA published its proposed regulations governing the handling and disposal of coal combustion residuals (CCRs), which are primarily composed of coal ash. The EPA proposes regulating CCRs as either non-hazardous solid waste or as a hazardous waste. The hazardous waste proposal would require certain additional capital investments at plants and disposal locations while phasing out the use of ash ponds for disposal of CCRs. The EPA advanced two proposals for regulating CCRs as non-hazardous solid waste. One of these proposals would require retrofitting or closure of currently unlined ash ponds and would require liners for ash landfill expansions. The other proposal would not require pond closures and would allow existing ash ponds to continue operating for the remainder of their useful lives without installation of liners. The rules will apply to CCRs produced by all of TEP’s coal-fired generating assets except San Juan which is subject to separate regulations.

The EPA has not yet indicated a preference for any of the alternatives. Each alternative would allow CCRs to be beneficially reused or recycled as components of other products instead of placed in impoundments or landfills. We do not know when the EPA will issue a final rule, including required compliance dates, and cannot predict the outcome of the EPA’s actions. The financial impact of this rulemaking to TEP, if any, cannot be determined at this time.

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Ozone National Ambient Air Quality Standard

In January 2010, the EPA issued a proposed rule to reduce the National Ambient Air Quality Standard for ozone. Based on the range of standards proposed, certain counties in which TEP conducts operations could be in violation of the standard. A final rule is expected in July 2011. The financial impact to TEP, if any, cannot be determined at this time.

Notice of Intent to Sue

On May 7, 2010, APS received a Notice of Intent to Sue (the Notice) from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners. The Notice alleges New Source Review-related violations and New Source Performance Standard violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA’s lawsuit. The 60-day period lapsed in early July without EPA action. At this time, TEP cannot predict whether or when Earthjustice might file a lawsuit.

UNS GAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 146,500 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as Santa Cruz County in southeastern Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 700,000. UNS Gas’ customer base is primarily residential. Sales to residential customers provided approximately 61% of total revenues in 2010, while sales to other retail customer classes accounted for about 27% of total revenues.

From 2003 to 2007, the customer growth rate in UNS Gas’ service territory averaged 3% per year. As a result of weak economic conditions, UNS Gas’ annual retail customer growth rate was less than 1% from 2008 through 2010. In 2011, we expect UNS Gas’ retail customer base to increase by less than 1%.

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 and is affected by weather, supply issues, the economy and other factors. 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 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 and also the Griffith Power Plant in Mohave County.

UNS Gas signed a separate agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line. The 15-year agreement began in 2009, when construction of that pipeline was completed. UNS Gas’ average daily capacity right is 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.

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RATES AND REGULATION

2010 UNS Gas Rate Order

In November 2008, UNS Gas filed a general rate case with the ACC. In March 2010, the ACC issued an order authorizing a base rate increase of $3 million, or 2%, effective April 2010.

Test year – 12 months ended June 30, 2008	Requested by UNS Gas	2010 ACC Order
Original cost rate base	$182 million	$180 million
Revenue deficiency	$10 million	$3 million
Total rate increase (over test year revenues)	6%	2%
Cost of equity	11.0%	9.5%
Actual capital structure	50% equity / 50% debt	50% equity / 50% debt
Weighted average cost of capital	8.75%	8.0%

Purchased Gas Adjustor (PGA)

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.

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. The annual cap on the maximum increase in the PGA factor is $0.15 per therm in a twelve month period.

At any time UNS Gas’ PGA balancing account, called the 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, 2010, the PGA bank balance was over-collected by $2 million on a billed-to-customers basis.

Gas Utility Energy Efficiency Standards and Decoupling

In August 2010, the ACC approved new Gas Utility Energy Efficiency Standards (Gas EE Standards) designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2011, the Gas EE Standards target total retail therm savings equal to 0.5% of 2010 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.

The Gas EE Standards can be met by: new and existing DSM programs, renewable energy technology that displaces gas, and by a portion of energy efficient building codes. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas’ DSM programs and rates charged to customers for these programs are subject to ACC approval.

In December 2010, the ACC approved a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona’s Gas EE Standards viable. For more information about decoupling, seeTEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling, above.

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

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UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is an electric transmission and distribution company serving approximately 91,000 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, the annual increase in the number of retail customers and average energy use by retail customers is below the average levels experienced by UNS Electric in prior periods. From 2003 to 2007, the number of retail customers in UNS Electric’s service territory increased by an average of 3% per year, compared with no change in the average number of retail customers during 2008 and less than 1% growth in 2009 and 2010. We estimate that UNS Electric’s retail customer base will increase by less than 1% in 2011. UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers. Peak demand for 2010 was 471 MW.

POWER SUPPLY AND TRANSMISSION

Purchased Energy

UNS Electric relies on a portfolio of long, intermediate and short-term purchases to meet customer load requirements. The portfolio includes the output of UED’s 90 MW BMGS, which has been purchased through a PPA with UED. The PPA, which expires in June 2013, 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 capacity charge and other costs associated with the PPA are recoverable through UNS Electric’s PPFAC. UNS Gas purchases and transports natural gas to BMGS for UNS Electric under long-term natural gas transportation and sales agreements.

In UNS Electric’s 2010 Rate Order, the ACC approved the acquisition and inclusion of BMGS in UNS Electric’s rate base, subject to various conditions. SeeRates and Regulation, 2010 UNS Electric Rate Order, below for more information.

Generating Resources

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. As noted above, UNS Electric also is in the process of acquiring the gas-fired BMGS from UED. SeeRates and Regulation, 2010 UNS Electric Rate Order, below for more information.

Renewable Energy Resources

UNS Electric has agreed to purchase the output of a combined wind farm and solar generating facility being built near Kingman. The above-market cost of energy purchased through the 20-year PPA will be recovered through the RES surcharge. For more information seeRates and Regulation, Renewable Energy Standard and Tariffbelow.

Future Generating Resources

UNS Electric expects to invest approximately $5 million annually from 2011 through 2014 to build about 1.25 MW per year in company-owned solar PV capacity. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tarifffor 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 June 2011. UNS Electric is in the process of extending its agreement with WAPA.

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UNS Electric plans to upgrade the existing 115 kV transmission line serving Santa Cruz County to 138 kV by the end of 2012 to improve service reliability. 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

2010 UNS Electric Rate Order

On April 30, 2009, UNS Electric filed a rate case application with the ACC. In September 2010, the ACC issued an order authorizing a base rate increase of $7.4 million, or 4%, effective October 1, 2010.

	Requested by
Test year – December 31, 2008	UNS Electric	2010 ACC Order
Original cost rate base	$176 million	$169 million
Revenue deficiency	$13.5 million	$7.4 million
Total rate increase (over test year revenues)	7%	4%
Cost of debt	7.05%	7.05%
Cost of equity	11.40%	9.75%
Actual capital structure	46% equity / 54% debt	46% equity / 54% debt
Weighted average cost of capital	9.04%	8.28%

The ACC also approved the acquisition and inclusion of BMGS in UNS Electric’s rate base, subject to FERC approval and other conditions. Upon its purchase, BMGS will be included in UNS Electric’s rate base through a revenue-neutral rate reclassification of approximately 0.7 cents per kWh from base power supply rate to non-fuel base rates. UNS Electric currently purchases all the output of BMGS under a contract with UED.

UNS Electric expects to file an application with FERC in early 2011 requesting approval to purchase BMGS. If UNS Electric receives FERC approval and meets the other conditions set forth in the 2010 UNS Electric Rate Order, we expect the acquisition of BMGS to be completed and included in UNS Electric’s rate base during 2011.

The 2010 UNS Electric Rate Order also approved a plan for UNS Electric to invest $5 million each year from 2011 through 2014 in solar projects that would be owned by UNS Electric. SeeItem 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.

Purchased Power and Fuel Adjustment Clause

The PPFAC allows UNS Electric to recover its fuel and purchased power costs, including demand charges, transmission costs and the prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward component and a true-up component.

• The forward component is updated on June 1 of each year. The forward component is based on the forecasted fuel and purchased power costs for the 12-month period from June 1 to May 31, less the base cost of fuel and purchased power embedded in base rates. The cap on the PPFAC forward component, over the 6.77 cents per kWh in base rates, is 1.845 cents per kWh.

• 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.

Renewable Energy Standard and Tariff

The ACC’s RES requires UNS Electric, TEP and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC and the approved cost of carrying out those plans are recovered from retail customers through the RES surcharge. Any surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in UNS Electric’s financial statements as a regulatory asset or liability.

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In 2010, UNS Electric spent $9 million on RES implementation and met the 2010 renewable energy target of 2.5%. UNS Electric expects to collect $8 million in surcharges from retail customers in 2011 to implement its RES plan and expects to meet the 2011 renewable energy target of 3%.

For more information seePower Supply and Transmission, Renewable Energy Resources,above, andItem 7. Management’s Discussion and Analysis, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff.

Electric Energy Efficiency Standards and Decoupling

In August 2010, the ACC approved new EE Standards designed to require UNS Electric, TEP and other affected electric utilities to implement cost effective DSM programs. For more information, seeTEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling, above.

Line Extension Policy

As part of the 2008 UNS Electric rate order, the ACC required UNS Electric to charge customers for the total cost of line extensions beginning in March 2010. Such charges are accounted for by UNS Electric as contributions in aid of construction. 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.

In January 2011, based in part on strong community support for UNS Electric’s former line extension policy, the ACC reinstated UNS Electric’s line extension policy that was in effect prior to the 2008 rate order. The result of this change will be to reduce contributions in-aid of construction thereby increasing net capital spending by UNS Electric.

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.

MILLENNIUM

Through affiliates, Millennium holds investments in unregulated energy and emerging technology companies. Millennium is in the process of exiting its remaining investments which may yield gains or losses. At December 31, 2010, Millennium had assets of $22 million, including a $15 million note receivable; land and buildings of $2 million; deferred tax assets of $2 million; and $3 million in cash. In total, Millennium’s assets represented less than 1% of UniSource Energy’s total consolidated assets. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Millennium,for more information.

SES, a wholly owned subsidiary of Millennium, provides commercial and residential electrical contracting and meter reading services in southern Arizona.

Sabinas

In 2009, Millennium sold its 50% interest in Sabinas and recorded a $6 million pre-tax gain on the sale. 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.

OTHER

UED

UED developed and owns the 90 MW BMGS. SeeUNS Electric, Power Supply and Transmission, above for more information regarding BMGS.

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EMPLOYEES (As of December 31, 2010)

TEP had 1,384 employees, of which approximately 52% 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 194 employees, of which 83 employees were represented by IBEW Local No. 1116 and five 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 2014, respectively.

UNS Electric had 155 employees, of which 27 employees were represented by the IBEW Local No. 387 and 97 employees were represented by the IBEW Local No. 769. The existing agreement with the IBEW Local No. 387 and No. 769 expire in February 2014 and June 2013, respectively.

SES had 260 employees, of which approximately 96% are represented by unions. Of the employees represented by unions, 233 are represented by IBEW Local No. 1116 and 17 by IBEW Local No. 570; these agreements expire on December 31, 2012, and May 31, 2012, respectively.

EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers — UniSource Energy and TEP

The Executive Officers of UniSource Energy are the same as TEP. Executive Officers of UniSource Energy and TEP, who are elected annually by UniSource Energy’s Board of Directors and TEP’s Board of Directions, respectively, are as follows:

			Executive
Name	Age	Position(s) Held	Officer Since
Paul J. Bonavia	59	Chairman, President and Chief Executive Officer	2009
Michael J. DeConcini	46	Senior Vice President, Operations(1)	1999
Raymond S. Heyman	55	Senior Vice President and General Counsel	2005
Kevin P. Larson	54	Senior Vice President, Chief Financial Officer and Treasurer	2000
Philip J. Dion III	42	Vice President, Public Policy	2008
Kentton C. Grant	52	Vice President, Finance and Rates	2007
Arie Hoekstra	63	Vice President, Generation	2007
David G. Hutchens	44	Vice President, Energy Efficiency and Resource Planning	2007
Karen G. Kissinger	56	Vice President, Controller and Chief Compliance Officer	1998
Steven W. Lynn	64	Vice President and Chief Customer Officer	2003
Thomas A. McKenna	62	Vice President, Engineering	2007
Catherine E. Ries	51	Vice President, Human Resources	2007
Herlinda H. Kennedy	49	Corporate Secretary	2006

⁽¹⁾    Mr. DeConcini holds the positions of Senior Vice President of UniSource Energy and Chief Operating Officer of TEP.

Paul J. Bonavia	Mr. Bonavia has served as Chairman, President and Chief Executive Officer of UniSource Energy and TEP since January 2009. Prior to joining UniSource Energy, 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 has served as Senior Vice President, Operations of UniSource Energy since May 2010 and Senior Vice President and Chief Operating Officer of TEP since May 2009. 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.
Raymond S. Heyman	Mr. Heyman has served as Senior Vice President and General Counsel of UniSource Energy and TEP since 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 has served as Senior Vice President and Chief Financial Officer of UniSource Energy and TEP since September 2005. Mr. Larson is also Treasurer of UniSource Energy. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He was elected Treasurer in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer.

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Philip J. Dion III	Mr. Dion has served as Vice President of Public Policy of UniSource Energy and TEP since April 2010. Mr. Dion joined UniSource Energy in February 2008 as Vice President of Legal and Environmental Services. Prior to joining UniSource Energy, Mr. Dion was chief of staff and chief legal advisor to Commissioner Marc Spitzer of the FERC. 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 has served as Vice President of Finance and Rates of UniSource Energy and TEP since January 2007. Mr. Grant also serves as Treasurer of TEP and UES. Mr. Grant joined TEP in 1995.
Arie Hoekstra	Mr. Hoekstra has served as Vice President of Generation of UniSource Energy and TEP since January 2007. Mr. Hoekstra joined TEP in 1979 and thereafter served in various positions at TEP’s generating stations in Tucson and Springerville.
David G. Hutchens	Mr. Hutchens has served as Vice President of Energy Efficiency and Resource Planning of UniSource Energy and TEP since May 2009. Mr. Hutchens joined TEP in 1995. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UniSource Energy and TEP and Vice President of UNS Gas.
Karen G. Kissinger	Ms. Kissinger has served as Vice President, Controller and Principal Accounting Officer of UniSource Energy and TEP since January 1998 and has served as Chief Compliance Officer since 2003. Ms. Kissinger joined TEP as Vice President and Controller in January 1991.
Steven W. Lynn	Mr. Lynn has served as Vice President and Chief Customer Officer of UniSource Energy and TEP since April 2010. Mr. Lynn joined UniSource Energy in 2000 and in January 2003, was elected Vice President of Communications and Government Relations.
Thomas A. McKenna	Mr. McKenna has served as Vice President of Engineering of UniSource Energy and TEP since January 2007. Mr. McKenna has also served as Vice President of UNS Electric since January 2007 and in May 2009 was named Vice President of UNS Gas. Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of Millennium) in 1998.
Catherine E. Ries	Ms. Ries has served as Vice President of Human Resources of UniSource Energy and TEP since June 2007. Prior to joining UniSource Energy, 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.
Herlinda H. Kennedy	Ms. Kennedy has served as Corporate Secretary of UniSource Energy and TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999.

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, which applies to the Board of Directors and all officers and employees of UniSource Energy and its subsidiaries, and any amendments or any waivers made to the code of ethics, is also available on UniSource Energy’s website.

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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, environmental, financial 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. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 1% per year in 2008 through 2010. In 2010, total retail kWh sales were 0.8% below 2009 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.

Similar impacts were felt at UNS Gas and UNS Electric. Annual increases in the number of retail customers at both companies remained below 1% in 2008 through 2010 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 an application for new base rates before June 30, 2012, and new rates cannot go into effect prior to January 1, 2013. If the cost of serving TEP’s customers rises more quickly than the revenues it collects from customers, TEP’s results of operations, net income and cash flows could be negatively impacted.

New technological developments and the implementation of new Energy Efficiency Standards 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 has increased demand for products intended to reduce consumers’ use of electricity. TEP and UNS Electric also are promoting DSM programs designed to help customers reduce their energy use, and these efforts will increase significantly under new energy efficiency rules approved in 2010 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. 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. 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.

K-23

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 the results of operations, net income and cash flows of TEP, UNS Gas and UNS Electric.

TEP, UNS Gas and UNS Electric are subject to the impact of 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.

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. Many of these regulations could have a significant impact on TEP due to its reliance on coal as its primary fuel for energy generation.

UniSource Energy’s utility subsidiaries are subject to numerous federal, state and local environmental laws and regulations affecting present and future operations. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste and management of CCRs.

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’s obligation to comply with the EPA’s BART determinations as a participant in the San Juan, Four Corners and Navajo plants, 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. TEP cannot predict the ultimate outcome of these matters.

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 it may be obligated 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 that emissions of greenhouse gases endanger public health and welfare, the agency is in the process of regulating 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 2010, 76% 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 costly modifications to, or reexamination of the economic viability of, our existing coal plants; changes in the overall fuel mix of our generating fleet; or additional costs to fund energy efficiency activities. The impact of legislation or regulation to address global climate change would depend on the specific terms of those measures and cannot be determined at this time.

FINANCIAL

Volatility or disruptions in the financial markets 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 experienced over the last three years 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.

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

As of February 15, 2011, TEP had $365 million of tax-exempt variable rate debt obligations, $50 million of which was hedged with a fixed for floating interest rate swap through September 2014. The interest rates are set weekly with maximum interest rates of 20% on $329 million of debt obligations and 10% on the remaining $36 million. The average weekly interest rate ranged from 0.17% to 0.39% in 2010. A 1% increase in the average interest rates on this debt over a twelve-month period would increase TEP’s 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 November 2014. UED is also subject to risk from changes in the interest rate on its term loan maturing in March 2012.

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’s results of operations, net income and cash flows.

K-25

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 $200 million. As of February 15, 2011, TEP had $164 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 $70 million, so long as the combined amount drawn by both companies does not exceed $100 million. As of February 15, 2011, UNS Gas and UNS Electric had $70 million and $57 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, 2010, TEP, UNS Gas and UNS Electric had posted $1 million, $3 million, and $13 million, respectively, with counterparties in the form of cash or letters of credit.

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, 2010, 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 69%. 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 purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power in 2015, could require significant outlays of cash in one year, which could be difficult to finance.

TEP leases the following generation facilities under separate sale and leaseback arrangements that expire in 2015:

Leased Asset	Expiration	Purchase Option
Springerville Unit 1	2015	Fair market value purchase option
Springerville Coal Handling Facilities	2015	Fixed price purchase option of $120 million

TEP may renew the leases or purchase the assets when the leases expire in 2015. The renewal and purchase options for Springerville Unit 1 are generally for fair market value as determined at that time. The Springerville Coal Handling Facilities can be purchased in 2015 for a fixed price of $120 million. TEP also leases a 50% undivided interest in Springerville Common Facilities with primary lease terms ending in 2017 and 2021. Upon expiration of the Springerville 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 owners of Springerville Units 3 and 4 to purchase such facilities. Upon acquisition by TEP, the owners of Springerville Unit 3 have the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 14% interest in the Common Facilities and a 17% interest in the Coal Handling Facilities.

K-26

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.

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.

Unanticipated financing needs or reductions to net income could adversely impact our ability to comply with financial covenants in the UniSource Energy and TEP Credit Agreements.

The UniSource Energy, TEP and UES credit and reimbursement agreements include a maximum leverage ratio. The leverage ratios are calculated as the ratio of total indebtedness to total capital. The ability to comply with these covenants could be adversely impacted by unanticipated borrowing needs or unexpected charges to earnings or shareholder equity. 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.

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’s 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’s or UNS Electric’s transmission and distribution systems experience a significant failure, TEP or UNS Electric could be adversely affected

TEP could be subject to higher costs and the possibility of significant penalties as a result of mandatory transmission 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 transmission standards developed and enforced by NERC and subject to the oversight of FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties.

K-27

TEP or UNS Electric might not be able to secure adequate right-of-way to construct transmission lines and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers.

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.

ITEM 1B. — UNRESOLVED STAFF COMMENTS

None.

ITEM 2. — PROPERTIES

TEP PROPERTIES

TEP’s transmission facilities, located in Arizona and New Mexico, transmit the output 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, TEP, Generating and Other Resources). The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. TEP has arrangements with approximately 130 companies to interchange generation capacity and transmission of energy.

As of December 31, 2010, 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;

• 379 circuit-miles of 138-kV lines;

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

• 2,621 circuit-miles of lower voltage primary lines.

TEP’s underground electric distribution system includes 4,367 cable-miles. TEP owns approximately 76% of the poles on which its lower voltage lines are located. Electric substation capacity consisted of 102 substations with a total installed transformer capacity of 13,216,805 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 places in the public domain, as well as in 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.

K-28

Springerville is located on property owned 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 also has 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.

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):

• Springerville Coal Handling Facilities;

• a 50% undivided interest in the Springerville Common Facilities; and

• Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities.

See Note 6and 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, 2010, UNS Gas’ transmission and distribution system consisted of approximately 30 miles of steel transmission mains, 4,211 miles of steel and plastic distribution piping, and 136,439 customer service lines.

UNS Electric

As of December 31, 2010, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 271 circuit-miles of 69-kV transmission lines, and 3,599 circuit-miles of underground and overhead distribution lines. UNS Electric also owns the 65 MW Valencia plant as well as 39 substations having a total installed capacity of 1,788,050 kilovolt amperes.

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 places in the public domain, as well as 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.

K-29

UED PROPERTIES

As of December 31, 2010, UED owned a 90-MW gas-fired generation facility in Mohave County, known as BMGS. 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 was a defendant in a class action filed in February 2009, in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs alleged, among other things, that the rights of way for defendants’ transmission lines on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs were 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. In March 2010, the Court granted several of the defendants’ motions to dismiss and entered a final judgment dismissing the case in April 2010. The plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (BIA) in May 2010, appealing the BIA’s decision to grant the rights of way that were the subject of the now-dismissed complaint. In June 2010, the BIA found that the Notice of Appeal failed to meet the minimum filing requirements. In September 2010, the plaintiffs filed new Notices of Appeal concerning the same rights of way. TEP cannot predict the outcome of these appeals.

Sierra Club San Juan Allegations

In April 2010, the Sierra Club filed a citizens suit under the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA) in the U.S. District Court for the District of New Mexico against PNM, as operator of San Juan; PNM’s parent, PNM Resources, Inc. (PNMR); San Juan Coal Company (SJCC), which operates the San Juan mine that supplies coal to San Juan; and SJCC’s parent, BHP Minerals International Inc. (BHP). The Sierra Club alleges in the suit that certain activities at San Juan and the San Juan mine associated with the treatment, storage and disposal of coal and CCRs — primarily coal ash — are causing imminent and substantial harm to the environment, including ground and surface waters in the region, and that placement of CCRs at the mine constitute “open dumping” in violation of RCRA. The RCRA claims are asserted against PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA which are directed only against SJCC and BHP.

The suit seeks the following relief: an injunction requiring the parties to either cease placement of CCRs at the mine or undertake certain mitigation measures with respect to their placement; the imposition of civil penalties; and, attorney’s fees and costs. The parties agreed to and the court entered a stay of the action on August 27, 2010 to allow the parties to try to address Sierra Club’s concerns. If the parties are unable to settle the matter, PNM plans an aggressive defense of the RCRA claims in the suit. TEP owns 50% of San Juan Units 1 and 2, which represent approximately 20% of the total generation capacity of the entire San Juan Generating Station, and is liable for its share of any resulting liabilities. TEP cannot predict the outcome of this matter at this time.

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

In addition, see legal proceedings described in Note 4.

ITEM 4. — REMOVED AND RESERVED

K-30

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 15, 2011, the closing price was $36.24, with 8,789 shareholders of record.

Dividends

UniSource Energy’s Board of Directors expects to continue to pay regular quarterly cash dividends on our common stock subject; however, such dividends are subject 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

Common Stock Dividends and Price Ranges

	2010						2009
	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	$	33.54	$	29.13	$	0.39	$	29.97	$	22.76	$	0.29
Second		34.42		29.04		0.39		28.76		24.78		0.29
Third		33.75		29.85		0.39		31.11		25.96		0.29
Fourth		36.92		33.19		0.39		33.11		28.04		0.29
Total					$	1.56					$	1.16

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

On February 25, 2011, UniSource Energy declared a cash dividend of $0.42 per share on its common stock. The dividend will be paid March 23, 2011 to shareholders of record at the close of business on March 11, 2011.

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 2010, $60 million in 2009 and $3 million in 2008.

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 28.100 shares of our Common Stock at any time, representing a conversion price of approximately $35.59 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, UniSource Energy Consolidated Cash Flows, Financing Activities.

Issuer Purchases of Common Equity

UniSource Energy did not purchase any of its common stock during 2010, 2009, or 2008.

K-31

ITEM 6. — SELECTED CONSOLIDATED FINANCIAL DATA

UniSource Energy

	2010			2009			2008			2007			2006
	- In Thousands -
	(except per share data)
Summary of Operations
Operating Revenues	$	1,453,677		$	1,396,701		$	1,410,066		$	1,381,373		$	1,308,141
Income Before Discontinued Operations	$	111,477		$	104,258		$	14,021		$	58,373		$	69,243
Net Income(1)	$	111,477		$	104,258		$	14,021		$	58,373		$	67,447
Basic Earnings per Share:
Before Discontinued Operations	$	3.06		$	2.91		$	0.39		$	1.64		$	1.96
Net Income	$	3.06		$	2.91		$	0.39		$	1.64		$	1.91
Diluted Earnings per Share:
Before Discontinued Operations	$	2.82		$	2.69		$	0.39		$	1.57		$	1.85
Net Income	$	2.82		$	2.69		$	0.39		$	1.57		$	1.80
Shares of Common Stock Outstanding
Average		36,415			35,858			35,632			35,486			35,264
End of Year		36,542			35,851			35,458			35,315			35,190
Year-end Book Value per Share	$	22.46		$	20.94		$	19.16		$	19.54		$	18.59
Cash Dividends Declared per Share	$	1.56		$	1.16		$	0.96		$	0.90		$	0.84
Financial Position
Total Utility Plant — Net	$	2,961,498		$	2,785,714		$	2,617,693		$	2,407,295		$	2,259,620
Investments in Lease Debt and Equity		105,277			132,168			126,672			152,544			181,222
Other Investments and Other Property		61,676			60,239			64,096			70,677			66,194
Total Assets	$	3,779,323		$	3,601,242		$	3,496,847		$	3,185,716		$	3,187,409
Long-Term Debt	$	1,352,977		$	1,307,795		$	1,313,615		$	993,870		$	1,171,170
Non-Current Capital Lease Obligations		429,074			488,349			513,517			530,973			588,771
Common Stock Equity		820,786			750,865			679,274			690,075			654,149
Total Capitalization	$	2,602,837		$	2,547,009		$	2,506,406		$	2,214,918		$	2,414,090
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	342,359		$	343,197		$	273,767		$	320,642		$	280,522
Capital Expenditures	$	(265,141	)	$	(282,991	)	$	(354,080	)	$	(243,242	)	$	(236,124	)
Other Investing Cash Flows(2)		(35,358	)		(9,540	)		(95,493	)		27,961			(7,820	)
Net Cash Flows From Investing Activities	$	(300,499	)	$	(292,531	)	$	(449,573	)	$	(215,281	)	$	(243,944	)
Net Cash Flows From Financing Activities	$	(51,183	)	$	(28,916	)	$	140,605		$	(119,229	)	$	(77,016	)
Ratio of Earnings to Fixed Charges(3)		2.64			2.47			1.24			1.68			1.73

(1)	Net Income includes an after-tax loss for discontinued operations of $2 million in 2006.
(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.
SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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TEP

	2010			2009			2008			2007			2006
	-Thousands of Dollars-
Summary of Operations
Operating Revenues	$	1,124,979		$	1,098,987		$	1,091,809		$	1,070,503		$	988,994
Net Income	$	106,978		$	89,248		$	4,363		$	53,456		$	66,745
Financial Position
Total Utility Plant — Net	$	2,410,077		$	2,261,325		$	2,120,619		$	1,957,506		$	1,887,387
Investments in Lease Debt and Equity		105,277			132,168			126,672			152,544			181,222
Other Investments and Other Property		43,588			31,813			31,291			35,460			30,161
Total Assets	$	3,066,108		$	2,914,299		$	2,841,771		$	2,573,036		$	2,623,063
Long-Term Debt	$	1,003,615		$	903,615		$	903,615		$	682,870		$	821,170
Non-Current Capital Lease Obligations		429,074			488,311			513,370			530,714			588,424
Common Stock Equity		701,155			643,144			583,606			577,349			554,714
Total Capitalization	$	2,133,844		$	2,035,070		$	2,000,591		$	1,790,933		$	1,964,308
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	297,755		$	264,548		$	265,756		$	262,714		$	225,752
Capital Expenditures	$	(215,697	)	$	(231,969	)	$	(291,990	)	$	(161,141	)	$	(154,704	)
Other Investing Cash Flows(1)		(32,611	)		(14,116	)		(95,814	)		25,414			(25,786	)
Net Cash Flows From Investing Activities	$	(248,308	)	$	(246,085	)	$	(387,804	)	$	(135,727	)	$	(180,490	)
Net Cash Flows From Financing Activities	$	(51,882	)	$	(29,320	)	$	128,713		$	(120,088	)	$	(78,984	)
Ratio of Earnings to Fixed Charges(2)		2.76			2.58			1.13			1.75			1.84

(1)	Other Investing Cash Flowsin 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds.
(2)	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 four primary business segments and includes the following:

• outlook and strategies;

• operating results during 2010 compared with 2009, and 2009 compared with 2008;

• 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 with no significant operations of its own. Operations are conducted by its 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 in the Tucson metropolitan area. 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 northwestern Arizona that provides energy to UNS Electric through a power sales agreement.

Millennium has existing investments in unregulated businesses that represented less than 1% of UniSource Energy’s total assets as of December 31, 2010; no new investments are planned in Millennium. Southwest Energy Solutions (SES), a subsidiary of Millennium, provides supplemental labor and meter reading services to TEP, UNS Gas and UNS Electric.

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 which freezes base rates through 2012; the weak national and regional economic conditions; volatility in the financial markets; the increasing number of environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:

• Focusing on our core utility businesses including: operational excellence; investing in utility rate base; customer satisfaction; maintaining a strong community presence; and achieving constructive regulatory outcomes.

• Expanding TEP and UNS Electric’s portfolio of renewable energy sources and programs to meet Arizona’s Renewable Energy Standards while creating ownership opportunities for renewable energy projects that benefit customers, shareholders and the communities we serve.

• Developing strategic responses to energy efficiency requirements that protect the financial stability of our utility businesses and provide benefits to our customers.

• Developing strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas emissions. We are evaluating TEP’s existing mix of generation resources and defining steps to achieve environmental objectives that provide an appropriate return on investment and are consistent with earnings growth.

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RESULTS OF OPERATIONS

Contribution by Business Segment

We conduct our business through four primary business segments — TEP, UNS Gas, UNS Electric and Millennium. The table below shows the contributions to our consolidated after-tax earnings by these business segments.

	2010			2009		2008
	-Millions of Dollars-
TEP	$	107		$	89	$	4
UNS Gas		9			7		9
UNS Electric		10			6		4
Millennium		(13	)		2		—
Other Non-Reportable Segments(1)		(2	)		—		(3	)
Consolidated Net Income	$	111		$	104	$	14

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

Executive Overview

2010 Compared with 2009

UniSource Energy’s net income in 2010 was $111 million compared with $104 million in 2009. The primary factors that contributed to the increase are described below by business segment.

TEP

TEP reported net income of $107 million in 2010 compared with net income of $89 million in 2009. The increase was due primarily to:

• a $17 million decrease in depreciation and amortization expense resulting from a change in depreciation rates for TEP’s transmission assets, the purchase of Sundt Unit 4 and a decline in amortization on capital lease obligations. The decrease excludes adjustments made to depreciation and amortization in 2009 related to an investment in Springerville Unit 1 lease equity;

• operating benefits of $11 million related to the start of commercial operation of Springerville Unit 4 in December 2009;

• a $3 million decrease in base operating and maintenance expense (Base O&M) resulting from a decline in planned power plant maintenance outages, cost-containment efforts and lower pension and post retirement medical expense. Base O&M excludes third-party expense reimbursements and expenses related to customer-funded renewable energy and demand-side management programs; partially offset by

• a $5 million decrease in TEP’s retail margin revenues resulting from a 0.8% decrease in retail kWh sales. TEP’s retail kWh sales were negatively impacted by weak economic conditions and a decline in cooling degree days compared with 2009.

SeeTucson Electric Power Company, Results of Operations,below for more information;

UNS Gas and UNS Electric

UNS Gas and UNS Electric reported combined net income of $19 million in 2010 compared with $13 million in 2009. The increase was due primarily to:

• a $4 million increase in net income at UNS Electric resulting from an increase in demand from a mining customer, the addition of a new industrial customer, an increase in base retail rates that took effect in October 2010, and a pre-tax gain of $3 million related to the settlement of a dispute regarding wholesale energy transactions; and

• a $2 million increase in net income at UNS Gas resulting from increased sales due to colder winter weather compared with 2009 and an increase in base retail rates that took effect in April 2010.

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Millennium

Millennium recorded a net loss of $13 million in 2010 compared with net income of $2 million in 2009. The net loss in 2010 resulted from several factors, including the write-off of deferred tax assets and impairment losses on certain investments. Millennium’s results in 2009 included a $6 million pre-tax gain on the sale of an investment.

2009 Compared with 2008

UniSource Energy’s net income in 2009 was $104 million compared with net income of $14 million in 2008. The primary factors that contributed to the increase are described below by business segment.

TEP

TEP reported net income of $89 million in 2009 compared with net income of $4 million in 2008. The increase was due primarily to:

• a 6% base rate increase at TEP that took effect December 1, 2009. The base rate increase, as well as hot summer weather, contributed to a $40 million increase in retail revenues during 2009. The increase excludes revenues collected from customers for renewable energy and energy efficiency programs;

• a $31 million decrease in total fuel and purchased energy expense (net of short-term wholesale revenues) due to lower wholesale prices; and

• $50 million of regulatory expenses, revenue deferrals and accounting adjustments in 2008 that did not recur in 2009.

Millennium

Millennium recorded net income of $2 million in 2009 and recorded no net income or loss in 2008. Millennium’s results in 2009 included a $6 million pre-tax gain on the sale of an investment.

O&M

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

	2010			2009			2008
	-Millions of Dollars-
TEP Base O&M (Non-GAAP) (1)	$	228		$	231		$	220
UNS Gas Base O&M (Non-GAAP) (1)		25			25			25
UNS Electric Base O&M (Non-GAAP) (1)		21			21			21
Consolidating Adjustments and Other(2)		(9	)		(7	)		(8	)
UniSource Energy Base O&M (Non-GAAP)		265			270			258
Reimbursed Expenses Related to Springerville Units 3 and 4		65			41			35
Gain on the Sale of SO2 Emissions Allowances		—			—			(1	)
Expenses Related to Customer-funded Renewable Energy and Demand-side Management Programs(3)		40			23			5
Reinstatement of Regulatory Accounting		—			—			(1	)
UniSource Energy Other O&M (GAAP)	$	370		$	334		$	296

(1)	Base O&M, a Non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is Other O&M less reimbursed expenses, gains on the sale of SO2 Allowances and expenses related to customer-funded renewable energy and demand-side management programs, provides useful information to investors.
(2)	Includes Millennium, UED and parent company O&M, and inter-company eliminations
(3)	Represents expenses related to customer-funded renewable energy programs; the offsetting funds collected from customers are recorded in retail revenue.

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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.

			Borrowings		Amount Available
Balances As of	Cash and Cash		under Revolving		under Revolving
February 15, 2011	Equivalents		Credit Facility(3)		Credit Facility
	-Millions of Dollars-
UniSource Energy stand-alone	$	1	$	31	$	94
TEP		36		36		164
UNS Gas		39		—		70	(1)
UNS Electric		16		13		57	(1)
Millennium		3		N/A		N/A
Other(2)		3		N/A		N/A
Total	$	98

(1)	Currently, either UNS Gas or UNS Electric may borrow up to a maximum of $70 million, but the total combined amount borrowed by both companies cannot exceed $100 million.
(2)	Includes cash and cash equivalents at UED.
(3)	Includes LOCs issued under Revolving Credit Facilities

Short-term Investments

UniSource Energy’s short-term investment policy 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, 2010, 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 that is available for working capital purposes. Each of these agreements is a committed facility and expires in November 2014. 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 also may be used to issue letters of credit for general corporate purposes.

UniSource Energy and its subsidiaries believe 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. SeeItem 7A.Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Liquidity Outlook

In November 2010, UniSource Energy, TEP, UNS Gas and UNS Electric each refinanced their respective Credit Agreements that were due to expire in 2011. The expiration dates were extended to November 2014. UNS Gas has $50 million of unsecured notes that mature in August 2011.

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UniSource Energy Consolidated Cash Flows

	2010			2009			2008
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$	342		$	343		$	274
Investing Activities		(300	)		(293	)		(450	)
Financing Activities		(51	)		(29	)		141

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 their revolving credit facilities as needed to fund their business activities.

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 2010, net cash flows from operating activities were $1 million lower than 2009 primarily due to:

• a $14 million increase in income taxes paid due to higher pre-tax income;

• a $20 million decrease in income tax refunds;

• a $4 million increase in total interest paid; and

• a $13 million decline in cash deposits received from power and gas trading counterparties; partially offset by

• approximately $11 million of operating benefits due primarily to the start-up of Springerville Unit 4; and

• a $41 million increase in cash receipts from total electric and gas sales net of fuel and purchased energy costs partially related to higher collections to fund renewable energy and energy efficiency programs.

Investing Activities

Net cash used for investing activities was $7 million higher in 2010 compared with 2009.

Investing activities in 2010 included:

• the purchase of Sundt Unit 4 by TEP for $51 million;

• an $18 million decline in capital expenditures resulting primarily from the effect of weakened economic conditions on customer growth;

• a $13 million increase in the return of investment in Springerville Unit 1 lease debt; and

• the purchase of renewable energy credits of $7 million by TEP and UNS Electric which is recovered through the RES surcharge.

Investing activities in 2009 included:

• the use of $31 million by TEP for an investment in Springerville Unit 1 lease debt; and

• the receipt of $8 million related to the sale of an investment by Millennium.

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Capital Expenditures Forecast

	Actual						Estimated
Business Segment	2010		2011		2012		2013		2014		2015
	-Millions of Dollars-
TEP	$	267	$	306	$	273	$	372	$	322	$	286
UNS Gas		10		12		11		14		16		22
UNS Electric (1)		22		37		51		25		30		32
Other Capital Expenditures		17		36		1		—		—		—
	$	316	$	391	$	336	$	411	$	368	$	340

(1) UNS Electric is expected to purchase BMGS from UED for approximately $62 million during 2011. Since this is an inter-company transaction, it is not included in the chart, as it is eliminated from UniSource Energy consolidated capital expenditures. SeeUNS Electric,Factors Affecting Results of Operations, Rates, 2010 UNS Electric Rate Order,below, for more information.

TEP’s capital expenditures in 2010 include $52 million for the purchase of Sundt Unit 4. TEP’s estimated capital expenditures in 2015 exclude the potential purchase of Springerville Unit 1 and Springerville Coal Handling Facilities upon the expiration of their respective leases in January 2015.

Other capital expenditures reflect UniSource Energy’s standalone capital expenditures, including the purchase of land and construction costs for a new corporate headquarters.

These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to changes in business conditions, construction schedules, environmental requirements, state or federal regulations and other factors.

For more information regarding TEP’s capital expenditures, seeTucson Electric Power Company, Liquidity and Capital Resources, Investing Activities, Capital Expenditures,below.

Financing Activities

Net cash proceeds used for financing activities were $22 million higher in 2010 than they were in 2009 due to:

• $30 million of net revolving credit facility repayments in 2010 compared with net proceeds of $5 million in 2009;

• a $32 million increase in payments of capital lease obligations;

• $30 million of short-term debt proceeds in 2009 compared with none in 2010; and

• a $15 million increase in dividends paid to common shareholders; partially offset by

• an $82 million increase in proceeds from long-term debt net of repayments of long-term debt.

Capital Contributions

In the first quarter of 2010, UED paid a $9 million dividend to UniSource Energy, of which $4 million represented a return of capital distribution. In March 2010, UniSource Energy contributed $15 million in capital to TEP to help fund the purchase of Sundt Unit 4.

In 2009, UED paid a $30 million dividend to UniSource Energy which also represented a return of capital distribution. UniSource Energy used the proceeds to contribute $30 million of capital to TEP to purchase lease debt related to Springerville Unit 1.

SeeOther Non-Reportable Business Segments, UEDandTucson Electric Power Company, Liquidity and Capital Resources, below for more information.

UniSource Credit Agreement

In November 2010, UniSource Energy amended and restated its existing credit agreement (UniSource Credit Agreement). The UniSource Credit Agreement had previously included a $30 million term loan facility and a $70 million revolving credit facility. As amended, the UniSource Credit Agreement consists of a $125 million revolving credit and revolving letter of credit facility. The UniSource Credit Agreement will expire in November 2014. At December 31, 2010, there was $27 million outstanding at a weighted average interest rate of 3.26%.

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The UniSource Credit Agreement restricts additional indebtedness, liens, mergers and sales of assets. The UniSource Credit Agreement also requires UniSource Energy to meet a minimum cash flow to interest coverage ratio determined on a UniSource Energy standalone basis and not to exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UniSource Credit Agreement, UniSource Energy may pay dividends so long as it maintains compliance with the agreement.

As of December 31, 2010, we were in compliance with the terms of the UniSource Credit Agreement.

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. If LIBOR and other benchmark interest rates increase, 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 28.100 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $35.59 per share of our Common Stock, subject to adjustments. The closing price of UniSource Energy’s Common Stock was $36.24 on February 15, 2011.

Beginning on March 5, 2010, UniSource Energy has 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.

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, 2010 were:

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

• UES’ guarantee of the $100 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 $30 million of outstanding loans under the UED Credit Agreement.

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

In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4. TEP has 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, TEP believes that the parties to the agreement have abided by all tax laws, and TEP does not have any additional tax obligations. TEP has 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, 2010.

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UniSource Energy’s Contractual Obligations
- - Millions of Dollars -

Payment Due in Years											2016
Ending December 31,	2011		2012		2013		2014		2015		and after		Other		Total
Long Term Debt
Principal(1)	$	57	$	23	$	—	$	392	$	100	$	838	$	—	$	1,410
Interest(2)		67		64		66		64		54		692		—		1,007
Capital Lease Obligations(3)		107		118		122		195		24		79		—		645
Purchase Obligations:
Fuel(4)		77		52		41		39		38		123		—		370
Purchased Power		73		48		43		4		—		—		—		168
Transmission		4		4		4		4		4		10		—		30
Coal Transportation Agreement		1		1		1		1		—		—				4
Other Long-Term Liabilities(5):
Pension & Other Post Retirement Obligations(6)		29		5		6		6		6		36		—		88
Acquisition of Springerville Coal Handling and Common Facilities(7)		—		—		—		—		120		106		—		226
Building Commitments		32		—		—		—		—		—		—		32
Solar Installation Commitments		1		—		—		—		—		—		—		1
Unrecognized Tax Benefits		—		—		—		—		—		—		40		40
Total Contractual Cash Obligations	$	448	$	315	$	283	$	705	$	346	$	1,884	$	40	$	4,021

(1)	TEP’s variable rate IDBs are secured by letters of credit issued pursuant to TEP’s Credit Agreement and 2010 Reimbursement Agreement which expire in 2014. Although the variable rate IDBs mature between 2018 and 2032, the above maturity reflects a redemption or repurchase of such bonds in 2014 as though the letters of credit terminate without replacement upon expiration of the TEP Credit Agreement and 2010 Reimbursement Agreement.
(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 a total of $14 million annually related to the Springerville Common and Springerville Coal Handling Facilities Leases. TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement.
(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 2011, TEP’s expected benefit payments for its unfunded Supplemental Executive Retirement Plan 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 2011 for their funded pension plans 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 2011 obligation includes expected VEBA contributions. VEBA contributions for periods beyond 2011 cannot be determined at this time.
(7)	TEP has agreed with the owners of Springerville Units 3 and 4 that, prior to expiration of the Springerville Coal Handling Facilities and Common Leases, TEP will either renew such leases or exercise its fixed price purchase option under such leases and acquire the leased facilities. TEP has the option of purchasing the facilities at the end of the initial lease term or after one or more renewal periods through 2025 for the Springerville Common Facilities and through 2035 for the Springerville Coal Handling Facilities. The table above reflects the purchase as if TEP exercised the fixed price purchase option at the end of the initial lease term. Upon such acquisitions by TEP, the owners of Springerville Unit 3 have the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 17% interest in the Springerville Coal Handling Facilities and a 14% interest in the Springerville Common Facilities.

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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 25, 2011, UniSource Energy declared a first quarter cash dividend of $0.42 per share on its common stock. The first quarter dividend, totaling approximately $15 million, will be paid March 23, 2011 to shareholders of record at the close of business March 11, 2011. The table below summarizes UniSource Energy’s dividends paid in 2008 through 2010.

	2010		2009		2008
Quarterly Dividend Per Common Share	$	0.39	$	0.29	$	0.24
Annual Dividend Per Common Share	$	1.56	$	1.16	$	0.96
Total Dividends Paid	$	57 million	$	41 million	$	34 million

Income Taxes

At December 31, 2010, UniSource Energy had federal AMT credit carryforwards of $34 million, including $16 million for TEP, which do not expire. UniSource Energy has a capital loss carryforward of $8 million that expires on December 31, 2015. This capital loss carryforward results in a $3 million deferred tax asset, against which a $3 million valuation allowance has been recorded. In addition, a valuation allowance of $5 million has been provided at UniSource Energy against deferred tax assets stemming from the difference between the book and tax basis of certain Millennium investments. We believe it is likely that the reversal of these basis differences will result in capital losses that cannot be currently realized. These two issues constitute the $8 million valuation allowance described in Note 8.

The 2010 Federal Tax Relief Act includes provisions that make qualified property placed into service between September 8, 2010 and January 1, 2012 eligible for 100% bonus depreciation for tax purposes and qualified property placed in service during 2012 is eligible for 50% bonus depreciation for tax purposes. This is an acceleration of tax benefits UniSource Energy otherwise would have received over 20 years. As a result of these provisions, UniSource Energy may not pay any federal income taxes in 2011 or 2012.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

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

2010 Compared with 2009

TEP recorded net income of $107 million in 2010 compared with net income of $89 million in 2009. The following factors contributed to the change in TEP’s net income:

• $11 million of pre-tax benefits recognized by TEP related primarily to Springerville Unit 4 for operating fees and contributions toward common facility costs received from the owner of Springerville Unit 4. Commercial operation of the unit began in December 2009. SeeFactors Affecting Results of Operations, Springerville Units 3 and 4, below for more information;

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• a $10 million decrease in depreciation expense due to lower depreciation rates on TEP’s transmission assets and a lengthened depreciation period for leasehold improvements at Sundt Unit 4, partially offset by depreciation related to an increase in plant-in-service. The decrease excludes a $7 million adjustment that increased depreciation expense in the second quarter of 2009, related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity. SeeFactors Affecting Results of Operations, Depreciation,below for more information;

• A $3 million decrease in base O&M expense, which excludes costs directly offset by customer surcharges for renewable energy and demand side management programs and third party reimbursements. The decrease resulted from a decline in pension and postretirement medical expense and lower power plant maintenance expense. SeeOperating Expenses, O&M,below for more information;

• a $7 million decrease in amortization expense due to a decline in the balance of capital lease obligations. The decrease excludes a $3 million adjustment made in the second quarter of 2009 that decreased amortization expense. The adjustment was related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity;

• a $5 million decrease in interest expense on capital lease obligations, excluding an adjustment made in 2009 related to an investment in Springerville Unit 1 lease equity. As TEP pays down its capital lease obligations over time, the resulting interest expense also declines. The decrease in capital lease interest expense was offset by a $5 million decline in interest income during 2010. TEP’s investment in lease debt balance, and resulting interest income, also declines over time as TEP pays down its capital lease obligations;

• a $3 million increase in long-term wholesale margin revenues due primarily to an increase in sales volumes to one of TEP’s long-term wholesale customers; and

• a $2 million increase in wholesale transmission revenues as TEP temporarily provided transmission capacity for Springerville Unit 4 during the first quarter of 2010.

These factors were partially offset by:

• an $8 million decrease in total other income due in part to interest related to an income tax refund received in 2009 and a decline in gains recognized on company owned life insurance. The decrease excludes a $3 million adjustment that increased other income in the second quarter of 2009, related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity;

• a $6 million increase in interest expense on long-term debt due primarily to the conversion of $130 million of debt from a variable rate to a fixed rate. 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 provided other benefits; and

• a $5 million decrease in total retail margin revenues. Weather, the implementation of energy efficiency measures and weak economic conditions contributed to a 0.8% decrease in kWh sales compared with 2009. Cooling Degree Days during 2010 were 3.5% below last year.

In June 2009, TEP adjusted its accounting for a 2006 investment in 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 $7 million; a reduction in amortization expense of $3 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.

2009 Compared with 2008

TEP recorded net income of $89 million in 2009 compared with net income of $4 million in 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 $22 million increase in revenues collected from customers for renewable energy and energy efficiency programs; and hot summer weather during the third quarter of 2009;

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

• a $31 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;

• 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; and

• 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.

These factors were partially offset by:

• 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;

• an $11 million increase in Base O&M expense, which excludes costs directly offset by customer surcharges for renewable energy and demand side management programs and third party reimbursements. The increase resulted primarily from higher pension-related expenses and plant maintenance expense;

• 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); and

• a $6 million increase in taxes other than income taxes. The increase was due primarily to a $7 million gain recorded in 2008 upon the reinstatement of regulatory accounting.

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.

Utility Sales and Revenues

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

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

					2010 vs.						2009 vs.
					2009						2008
Energy Sales, kWh (in millions)	2010		2009		% Change*			2008			% Change*
Electric Retail Sales:
Residential		3,870		3,906		(0.9	%)		3,852			1.4	%
Commercial		1,963		1,988		(1.3	%)		2,034			(2.3	%)
Industrial		2,139		2,161		(1.0	%)		2,264			(4.5	%)
Mining		1,079		1,065		1.4	%		1,096			(2.8	%)
Public Authorities		241		251		(4.1	%)		256			(1.9	%)
Total Electric Retail Sales		9,292		9,371		(0.8	%)		9,502			(1.4	%)
Electric Retail Revenues (in millions):
Residential	$	372	$	378		(1.5	%)	$	351			7.6	%
Commercial		217		220		(1.2	%)		212			3.8	%
Industrial		160		164		(2.3	%)		165			(0.7	%)
Mining		62		61		1.8	%		55			9.7	%
Public Authorities		19		20		(3.7	%)		19			3.8	%
Revenues excluding RES & DSM	$	830	$	843		(1.4	%)	$	802			5.0	%
RES and DSM Revenues		38		25	NM				3		NM
Provision for Rate Refunds		—		—	NM				(58	)	NM
Net Electric Retail Sales	$	868	$	868		0.1	%	$	747			16.2	%

					2010 vs.					2009 vs.
					2009					2008
Weather Data:	2010		2009		% Change*			2008		% Change*
Cooling Degree Days
Actual		1,543		1,599		(3.5	%)		1,336		19.7	%
10-Year Average		1,468		1,469	NM				1,431	NM
Heating Degree Days
Actual		1,469		1,287		14.1	%		1,367		(5.9	%)
10-Year Average		1,430		1,434	NM				1,444	NM

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

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Retail Margin Revenues

The table below provides a summary of the margin revenues (retail revenues excluding base fuel, PPFAC and RES and DSM charges) on TEP’s retail sales for 2010 and 2009. Comparable data is not available for 2008 because TEP’s new rate structure took effect in December 2008.

					Increase (Decrease)
	2010		2009		Amount			Percent*
Retail Margin Revenues (in millions):
Residential	$	252	$	254	$	(2	)		(0.9	%)
Commercial		159		160		(1	)		(0.5	%)
Industrial		97		100		(3	)		(3.1	%)
Mining		31		30		1			3.0	%
Public Authorities		12		12		—			(2.4	%)
Total Retail Margin Revenues (non-GAAP)**	$	551	$	556	$	(5	)		(1.0	%)
Retail Fuel Revenues		279		287		(8	)		(2.2	%)
RES & DSM Revenues		38		25		13			48.8	%
Net Electric Retail Sales (GAAP)	$	868	$	868	$	0			0.1	%
Avg. Retail Margin Rate (cents / kWh):
Residential		6.50		6.49		0.01			0.1	%
Commercial		8.10		8.04		0.06			0.8	%
Industrial		4.53		4.62		(0.09	)		(2.1	%)
Mining		2.87		2.82		0.05			1.6	%
Public Authorities		5.07		4.98		0.07			1.7	%
Avg. Retail Margin Rate		5.93		5.93		0.00			-0.1	%
Avg. PPFAC Rate		3.01		3.05		(0.04	)		(1.4	%)
Avg. RES & DSM Rate		0.41		0.27		0.14			50.0	%
Total Avg. Retail Rate		9.34		9.26		0.10			0.9	%

*	Percent change is calculated on un-rounded data; may not correspond to data shown in table.
**	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, PPFAC revenues, and revenues for DSM and RES programs, provides useful information to investors.

2010 Compared with 2009

Residential

Residential kWh sales were 0.9% lower in 2010 compared with 2009, which led to a decrease in residential margin revenues of $2 million. The decline in residential kWh sales can be attributed to a 3.5% decrease in Cooling Degree Days compared with 2009, weak local economic conditions and energy efficiency measures.

Commercial

Commercial kWh sales in 2010 were 1.3% below 2009 levels. A decline in Cooling Degree Days and weak economic conditions contributed to the sales decline. The lower sales volumes, and resulting lower demand charges, led to a decline in commercial margin revenues of $1 million.

Industrial

Industrial kWh sales declined by 1.0% compared with 2009, due primarily to weak economic conditions. Margin revenues from industrial customers decreased by 3.1%, or $3 million due to changing usage patterns that reduced demand charges.

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Mining

Higher copper prices led to increased mining activity resulting in a 1.4% increase in sales volumes in 2010 compared with 2009. Margin revenues from mining customers increased $1 million, or 3.0%, compared with the prior year due to changing usage patterns that increased demand charges.

Long-Term Wholesale and Transmission Revenues

					2010 vs.					2009 vs.
					2009					2008
	2010		2009		% Chng.*			2008		% Chng.*
Long-Term Wholesale Contracts
kWh Sales (Millions)		988		833		18.6	%		1,096		(24.0	%)
Revenues ($ Millions)	$	56	$	48		15.4	%	$	57		(16.1	%)
Wholesale Transmission Revenues ($ Millions)	$	21	$	19		9.9	%	$	17		10.5	%

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

Revenues from long-term wholesale contracts increased by $8 million in 2010 compared with 2009, due to an 18.6% increase in kWh sales. The increase in sales volumes and revenues is due to higher kWh sales to TEP’s two primary long-term wholesale customers, SRP and NTUA. The margin on TEP’s long-term wholesale sales in 2010 and 2009 was $28 million and $25 million, respectively. The increase in margin in 2010 is due primarily to a 26% increase in sales volumes to NTUA. During 2009, NTUA received a greater allotment of federal hydro power as hydro conditions in the Colorado River basin were above normal, reducing its need for power from TEP.

Wholesale transmission revenues in 2010 increased by $2 million as TEP temporarily provided transmission capacity to SRP for Springerville Unit 4.

In April 2010, TEP settled all remaining claims arising out of certain of its transactions with the California Power Exchange (CPX) and the California Independent System Operator (CISO) during the California energy crisis of 2000 and 2001. As a result of this settlement, TEP recorded a $3 million pre-tax charge against income in the first quarter of 2010. In December 2009, TEP recorded a pre-tax charge of $4 million against income also related to transactions with the CPX and CISO in 2000 and 2001. See Note 4.

Short-Term Wholesale and Trading Revenues

In the 2010 and 2009, TEP’s short-term wholesale and trading revenues were $71 million and $84 million, respectively. All of the revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.

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%, that year due to hot summer weather as well as a base rate increase that took effect 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 took effect 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 $6 million higher than the same period last year as a result of the base rate increase that became effective in December 2008.

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Long-Term Wholesale Revenues

Revenues from long-term wholesale contracts decreased by $9 million in 2009 compared with 2008 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 were 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 $25 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.

Other Revenues

	2010		2009		2008
	-Millions of Dollars-
Reimbursements related to Springerville Units 3 and 4(1)	$	97	$	59	$	53
Other		22		24		19
Total Other Revenue	$	119	$	83	$	72

⁽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; and miscellaneous service-related revenues such as power pole attachments, damage claims and customer late fees.

Operating Expenses

2010 Compared with 2009

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for 2010, 2009 and 2008 are detailed below:

	Generation/Purchases						Expense
	2010		2009		2008		2010			2009			2008
	-Millions of kWh-						-Millions of Dollars-
Coal-Fired Generation		9,481		9,272		10,573	$	219		$	201		$	235
Gas-Fired Generation		1,078		986		871		60			76			74
Renewable Generation		32		30		34		—			—			—
Total		10,591		10,288		11,478		279			277			309
Regulatory Accounting Reinstatement(1)		—		—		—		—			—			(24	)
Total Generation(2)		10,591		10,288		11,478		279			277			285
Purchased Power		2,760		3,678		3,693		119			144			251
Transmission		—		—		—		3			3			11
Increase (Decrease) to Reflect PPFAC Recovery Treatment		—		—		—		(23	)		(21	)		—
Total Resources		13,351		13,966		15,171	$	378		$	403		$	547
Less Line Losses and Company Use		801		816		1,289
Total Energy Sold		12,550		13,150		13,882

(1)	See Note 2 for more information.
(2)	Fuel expense excludes $7 million in 2010 and $5 million in 2009 and 2008, related to Springerville Units 3 and 4; 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.

Generation

Coal-related fuel expense in 2010 increased by $18 million compared with 2009 due primarily to the switching of fuel at Sundt Unit 4 from natural gas to coal. TEP fueled Sundt 4 on coal for eight months in 2010, compared with two months in 2009. Gas-related fuel expense decreased in 2010 due primarily to a decrease in realized losses on gas hedging activities.

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Purchased Power

Purchased power volumes and expense during 2010 were lower than last year due to a decrease in short-term wholesale sales activity, an increase in coal-fired generating output, and a decline in retail sales volumes.

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

	2010		2009		2008
	-cents per
	kWh generated-
Coal		2.30		2.16		2.22
Gas		5.58		7.66		8.49
Purchased Power		4.17		3.92		6.80

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 Market Index was 13% higher in 2010 compared with 2009. The average annual price for natural gas based on the Permian Index was 25% higher in 2010 compared with last year. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during 2011.

Avg. Market Price for Around-the-Clock Energy - $/MWh	2010		2009		2008
Year ended December 31	$	34	$	30	$	63

Avg. Market Price for Natural Gas - $/MMBtu	2010		2009		2008
Year ended December 31	$	4.18	$	3.34	$	7.41

O&M

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

	2010		2009		2008
	-Millions of Dollars-
Base O&M (Non-GAAP)(1)	$	228	$	231	$	220
Reimbursed Expenses Related to Springerville Units 3 and 4		65		41		35
Gain on the Sale of SO2 Emissions Allowances		—		—		(1	)
Expenses Related to Customer-funded Renewable Energy and Demand-side Management Programs(2)		31		18		3
Reinstatement of Regulatory Accounting		—		—		(1	)
Total Other O&M (GAAP)	$	324	$	290	$	256

(1)	Base O&M, a Non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is Other O&M less reimbursed expenses, gains on the sale of SO2 Allowances and expenses related to customer-funded renewable energy and demand-side management programs, provides useful information to investors.
(2)	Represents expenses related to TEP’s customer-funded renewable energy and DSM programs; the offsetting funds collected from customers are recorded in retail revenue.

TEP’s base O&M expense in 2010 was $228 million, or $3 million below 2009. The decline is due primarily to fewer plant maintenance outages and a decrease in pension and postretirement medical expense in 2010 compared with 2009.

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Income Tax Expense

In 2010, TEP’s effective tax rate was 36% compared with 38% in 2009. The decrease is primarily due to an increase in federal deductions along with federal and state tax credits. See Note 8 for more information.

2009 Compared with 2008

Fuel and Purchased Power Expense

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 decreased by $34 million during 2009, excluding a $24 million gain recorded in 2008 related to the adoption of regulatory accounting. The decrease resulted from 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.

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 $2 million due to a decrease in the average price for natural gas. TEP’s hedging activities have been reflected in the PPFAC since January 1, 2009.

Purchased power expense decreased by $106 million in 2009 compared with 2008. The average price paid by TEP for purchased power during 2009 was approximately $39 per MWh, compared with $68 per MWh in 2008.

O&M

TEP’s base O&M in 2009 increased by $11 million compared with 2008 due primarily to an increase in planned power plant outages and higher pension and postretirement medical expenses.

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 had previously been regulatory assets related to the generation business.

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. See Note 8 for more information.

FACTORS AFFECTING RESULTS OF OPERATIONS

Base Rate Increase Moratorium

Pursuant to the 2008 TEP Rate Order, TEP’s base rates are frozen through December 31, 2012. TEP is prohibited from submitting an application for new base rates before June 30, 2012. The test year to be used in TEP’s next base rate application cannot end earlier than December 31, 2011.

Notwithstanding the rate increase moratorium, base rates and adjustor mechanisms may be changed in emergency conditions 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. For a more detailed description of the terms of the 2008 TEP Rate Order, seeItem 1. — Business, TEP,Rates and Regulation, 2008 TEP Rate Order.

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Springerville Units 3 and 4

TEP operates and receives annual benefits in the form of rental payments and other fees and cost savings from operating Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Springerville Unit 4 began commercial operations in December 2009. TEP recorded pre-tax income of $24 million in 2010 and $13 million in 2009 related to the operation of these units. The table below summarizes the income statement line items where TEP records revenues and expenses related to Springerville Units 3 and 4.

	2010		2009
Springerville Units 3 and 4	-millions of dollars-
Other Revenues	$	97	$	60
Fuel Expense		7		5
Operations and Maintenance Expense		64		41
Taxes other than Income Taxes		2		1
Total Pre-Tax Income	$	24	$	13

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 had the effect of reducing transmission depreciation expense by approximately $14 million in 2010.

TEP’s total depreciation expense in 2010 decreased by $10 million compared with 2009. The lower depreciation rates on TEP’s transmission assets and a lengthened depreciation period for leasehold improvements at Sundt Unit 4 were partially offset by depreciation related to an increase in plant-in-service. The decrease in 2010 compared with 2009 excludes a $7 million adjustment that increased depreciation expense in the second quarter of 2009 related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity.

Sundt Unit 4

Until March 2010, Sundt Unit 4 was leased by TEP with a lease term expiration of January 2011. In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4 from the equity owner for approximately $52 million. In April 2010, TEP redeemed the outstanding Sundt Unit 4 lease debt of $5 million, terminated the lease agreement and caused title of Sundt Unit 4 to be transferred to TEP.

Refinancing Activity

In November 2010, TEP amended and restated its existing credit agreement (TEP Credit Agreement). As a result of the increase in the interest rate on borrowings under the revolving credit facility and the margin rate in effect on the letter of credit facility, we estimate that interest expense related to the TEP Credit Agreement will increase by $6 million in 2011 compared with 2010.

Pension and Postretirement Benefit Expense

In 2010 and 2009, TEP charged $13 million and $17 million, respectively, of pension and postretirement benefit expenses to O&M expense. In 2011, TEP expects to charge $15 million of pension and postretirement benefit expense to O&M expense. See Note 9 for more information.

Long-Term Wholesale Sales

In 2010 and 2009, TEP’s margin on long-term wholesale sales was $28 million and $25 million, respectively. TEP’s two primary long-term wholesale contracts are with SRP and NTUA.

Salt River Project

Prior to June 1, 2011, under the terms of the SRP contract, TEP receives a monthly demand charge of approximately $1.8 million, or $22 million annually, and sells the energy at a price based on TEP’s average fuel cost. Beginning June 1, 2011, SRP will be required to purchase 73,000 MWh per month, or 876,000 MWh annually. TEP will not receive a demand charge and the price of energy will be based on a slight discount to the Palo Verde Market Index. As of February 15, 2011, the average around-the-clock forward price of power on the Palo Verde Market Index for June through December 2011 was $34 MWh.

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Navajo Tribal Utility Authority

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 225,000 MWh. Since 2010, the price of 50% of the MWh sales from June to September has been based on the Palo Verde Market Index. In 2010, approximately 25% of the total energy sold to NTUA was priced based on the Palo Verde Market Index.

For more information on long-term wholesale sales, seeItem. 1 Business, TEP, Service Area and Customers, Wholesale Business.

El Paso Electric Dispute

TEP and El Paso Electric (El Paso) have a dispute regarding transmission service from Luna to TEP’s system. In 2008, the FERC issued an order supporting TEP’s position; and, pending resolution, El Paso refunded $10 million that TEP had paid for transmission service from Luna to TEP’s system from 2006 to 2008, along with interest of $1 million.

In July 2010, the FERC issued an order denying El Paso's request for rehearing of FERC's 2008 order. El Paso filed an appeal in the United States Court of Appeals of the District of Columbia Circuit. In January 2011, in response to a joint motion filed by El Paso and FERC, the United States Court of Appeals of the District of Columbia Circuit ordered the appeal proceeding to be held in abeyance to allow TEP and El Paso time to continue settlement negotiations in this matter. TEP has not recognized income as a result of the July 2010 FERC decision. TEP cannot predict the timing or outcome of this proceeding.

Electric Energy Efficiency Standards

In August 2010, the ACC approved new EE Standards designed to require TEP, UNS Electric and other affected electric utilities to implement cost effective DSM programs. In 2010, TEP’s programs saved 1.1% of 2009 sales. In 2011, the EE Standards target total kWh savings of 1.25% of 2010 sales. The EE Standards increase thereafter up to the targeted cumulative annual reduction in retail kWh sales of 22% by 2020. For more information, seeItem. 1 Business, TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling.

Competition

New technological developments and the implementation of EE Standards may reduce energy consumption by TEP’s retail customers. TEP’s customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP’s services. 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. SeeItem 1. Business, TEP, Rates and Regulation, Energy Efficiency Standards and Decouplingfor more information.

Renewable Energy Standard and Tariff

In 2010, the ACC approved a funding mechanism that allows TEP to use RES funds to recover operating costs, depreciation, property taxes and provide TEP with a return on its investments in TEP-owned solar projects until these costs are recovered as part of TEP’s base rates. TEP invested $14 million in two solar projects that were completed in December 2010 and began cost recovery through the RES surcharge in January 2011. In 2011, TEP expects to earn approximately $0.6 million on its 2010 investment in solar projects.

The ACC approved an additional investment of $28 million for approximately 7 MW of solar capacity in 2011. In 2012, TEP expects to earn approximately $2 million on its company-owned solar projects. TEP expects to invest $28 million annually in 2012 through 2014 in solar PV projects, subject to approval by the ACC. For more information seeItem. 1 Business, TEP, Rates and Regulation, Renewable Energy Standard and Tariff.

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Sales to Mining Customers

The rise in the market price of copper over the last two years has led to increased mining activity at the copper mines operating in TEP’s service area. TEP’s mining customers have indicated they are taking initial steps to increase production either through expansion of their current mining operations or by the re-opening of non-operational mine sites. If efforts to increase production are successful, TEP’s mining load could increase by up to 100 MW over the next several years. The market price for copper and the ability to obtain necessary permits could affect the mining industry’s expansion plans.

In 2010, sales to TEP’s mining customers increased 1.4% compared with 2009 and represented 12% of TEP’s total retail kWh sales and 7% of total retail revenues.

In addition to the mining customers TEP currently serves, 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 must receive a Record of Decision from the USFS prior to receiving permits for mine construction and operations. As part of the USFS’ decision process, it must issue an Environmental Impact Statement (EIS). A draft EIS is expected to be issued in 2011 and will be followed by public hearings. If the Rosemont Copper Mine reaches full production, it would become TEP’s largest retail customer. TEP would serve approximately 100 MW of the Rosemont Copper Mine’s total estimated load of approximately 110 MW.

TEP cannot predict if or when existing mines will expand operations or new or re-opened mines will commence operations.

Fair Value Measurements

TEP’s exposure to risk is mitigated as TEP reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset or a regulatory liability, or as a component of AOCI rather than in the income statement. See Note 11 for more information.

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:

	2010			2009			2008
	-Millions of Dollars-
Net Cash Flows — Operating Activities (GAAP)	$	298		$	265		$	266
Amounts from Statements of Cash Flows:
Less: Capital Expenditures (Including Purchase of Sundt Unit 4)		(267	)		(232	)		(292	)
Net Cash Flows after Capital Expenditures (non-GAAP)*		31			33			(26	)
Amounts from Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations		(56	)		(24	)		(74	)
Plus: Proceeds from Investment in Lease Debt		26			13			25
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)*	$	1		$	22		$	(75	)

	2010			2009			2008
Net Cash Flows — Operating Activities (GAAP)	$	298		$	265		$	266
Net Cash Flows — Investing Activities (GAAP)		(248	)		(246	)		(388	)
Net Cash Flows — Financing Activities (GAAP)		(52	)		(29	)		129
Net Cash Flows after Capital Expenditures (non-GAAP)*		24			33			(26	)
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)*		1			22			(75	)

* Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Capital Expenditures and 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 Capital Expenditures and 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 2011, 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 2010, net cash flows from operating activities increased by $33 million compared with 2009. Net cash flows were impacted by:

• a $34 million increase in cash receipts from operating Springerville Units 3 and 4. Approximately $23 million of the increase is related to the reimbursement of incurred costs that are included primarily in operating and maintenance costs and fuel costs. Approximately $11 million of the increase represents operating synergies that directly benefit TEP’s operating cash flows; and

• a $55 million increase in cash receipts from electric retail and wholesale sales, net of fuel and purchased power costs. The increase is due to: higher customer surcharges under the RES, which is used to fund programs whose costs are primarily included in operating and maintenance costs; an increase in long-term wholesale electric sales; higher wholesale transmission revenues; partially offset by lower retail electric kWh sales.

These factors were partially offset by:

• a $5 million increase in total interest paid due in part to the conversion of $130 million of debt from variable rate to fixed rate. 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 provided other benefits described below inFinancing Activities, Bond Issuances — 2010;

• a $16 million increase in income taxes paid (net of refunds) due primarily to higher taxable income and a decrease in income tax refunds;

• a $5 million increase in wages paid; and

• a $4 million decrease in interest received, due primarily to a lower investment in lease debt balance.

Investing Activities

Net cash used for investing activities increased by $2 million in 2010 compared with 2009.

Investing activities in 2010 included:

• the use of $216 million for capital expenditures;

• the purchase of Sundt Unit 4 for $51 million;

• the receipt of $26 million related to the return of investment in Springerville lease debt;

• the purchase of renewable energy credits for $7 million which TEP recovers through the RES surcharge; and

• insurance proceeds for replacement assets of $1 million.

Investing activities in 2009 included:

• the use of $232 million for capital expenditures;

• an investment of $31 million to purchase Springerville lease debt;

• the receipt of $13 million related to the return of investment in Springerville lease debt; and

• insurance proceeds for replacement assets of $5 million.

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Capital Expenditures

TEP’s forecasted capital expenditures are summarized below:

	2011		2012		2013		2014		2015
Category	-Millions of Dollars-
Transmission and Distribution	$	143	$	99	$	166	$	116	$	82
Generation Facilities		71		49		86		65		69
Renewable Energy Generation		29		30		29		30		30
Environmental		8		56		60		82		71
General and Other		55		39		31		29		34
Total	$	306	$	273	$	372	$	322	$	286

TEP’s estimated capital expenditures for 2011-2014 are $1.3 billion, which is approximately $400 million higher than the estimates reported in UniSource Energy and TEP’s 2009 Annual Report on Form 10-K. The increase is due primarily to: projected investments in renewable energy projects; an increase in TEP’s share of estimated environmental compliance costs at the San Juan and Navajo generating stations; an increase in high voltage transmission investments designed to increase TEP’s energy import capability into its service territory; and an increase in investments to upgrade and maintain TEP’s local distribution system. SeeItem 1. Business, TEP, Environmental Matters, for more information on TEP’s estimated capital costs related to environmental compliance.

TEP’s estimated capital expenditures in 2015 exclude the potential purchase of Springerville Unit 1 and Springerville Coal Handling Facilities upon the expiration of their respective leases in January 2015. SeeCapital Lease Obligations, below for more information.

TEP’s capital expenditure forecast does not include the estimated cost to construct a proposed Tucson to Nogales, Arizona 345 KV transmission line of $120 million. SeeItem 1. Business, TEP, 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, state or federal regulations and other factors.

Investments in Springerville Lease Debt

At December 31, 2010, TEP had $72 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
	December 31, 2010		December 31, 2009
Leased Asset	- In Millions -
Investments in Lease Debt:
Springerville Unit 1	$	67	$	88
Springerville Coal Handling Facilities		1		7
Total Investment in Lease Debt	$	68	$	95

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.

See Note 6 for more information.

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Financing Activities

Net cash proceeds used for financing activities increased by $23 million in 2010 compared with 2009 due to:

• net repayments of revolving credit facility borrowings of $35 million in 2010 compared with net proceeds of $25 million in 2009;

• a $15 million decrease in equity investments from UniSource Energy;

• a $32 million increase in payments of capital lease obligations; and

• a $5 million increase in debt issuance/retirement costs; partially offset by

• an $88 million increase on proceeds from the issuance of long-term debt (net of repayments of long-term debt).

TEP Credit Agreement

In November 2010, TEP amended and restated its existing credit agreement (TEP Credit Agreement). The TEP Credit Agreement had previously included a $150 million revolving credit facility and a $341 million letter of credit facility to support $329 million aggregate principal amount of tax-exempt variable rate bonds. As amended, the TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $341 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2014 and is secured by $541 million of Mortgage Bonds. At December 31, 2010, TEP had no borrowings outstanding and $1 million of letters of credit issued under the revolving credit facility.

The TEP Credit Agreement contains restrictions on liens, mergers and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UniSource Energy. As of December 31, 2010, TEP was in compliance with the terms of the TEP Credit Agreement.

TEP Term Loan

In March 2010, TEP entered into a $30 million term loan agreement to help fund a portion of the purchase of Sundt Unit 4 and for other general corporate purposes. TEP repaid the term loan in October 2010.

TEP Reimbursement Agreement

In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million letter of credit was issued pursuant to the 2010 TEP Reimbursement Agreement. The letter of credit supports $37 million aggregate principal amount of variable rate tax-exempt IDBs that were issued on behalf of TEP in December 2010. SeeBond Issuances — 2010, below.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of December 31, 2010, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

Capital Contribution from UniSource Energy

In March 2010, UniSource Energy contributed $15 million of capital to TEP. TEP used the proceeds to help fund the purchase of Sundt Unit 4.

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 — 2010

In December 2010, the Coconino County, Arizona Pollution Control Corporation (Coconino PCC) issued approximately $37 million of its 2010 Series A tax-exempt pollution control revenue bonds (2010 Coconino A Bonds) for TEP’s benefit. The proceeds of the bonds were used to redeem a corresponding principal amount of 7.125% 1997 Coconino Series A bonds. The 2010 Coconino A Bonds accrue interest at a weekly rate until the interest rate is converted to another mode as provided for in the loan agreement and indenture. The initial weekly interest rate was 0.30%. The variable rate 2010 Coconino A Bonds are supported by a letter of credit issued under the 2010 TEP Reimbursement Agreement. SeeTEP Reimbursement Agreement, above.

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In October 2010, the Pima Authority issued $100 million of its 2010 Series A tax-exempt IDBs for TEP’s benefit. The 2010 Pima Series A IDBs are unsecured, bear interest at a rate of 5.25%, mature in October 2040, and are callable at par on or after October 1, 2020. Net of an underwriting discount, $99 million of proceeds were deposited in a construction fund with the bond trustee. The proceeds are to be applied to the construction of certain of TEP’s transmission and distribution facilities used to provide electric service in Pima County. As of December 31, 2010, TEP had drawn $88 million of the proceeds from the construction fund, with the remaining $11 million expected to be drawn down by the end of the first quarter of 2011.

In January 2010, TEP converted the interest mode on its $130 million of 2008 Pima B Bonds from a variable rate to a fixed rate. The 2008 Pima B bonds were re-offered 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 $132 million letter of credit (LOC) that supported the bonds, and cancel the mortgage bonds that secured the LOC facility.

Bond Issuances — 2009

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 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 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. The average annual interest savings is expected to be approximately $2 million.

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, 2010 and December 31, 2009, TEP had $365 million and $459 million, respectively, 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 $37 million of 2010 Coconino A Bonds and is 20% on the other $329 million in IDBs. During 2010, the average rates paid ranged from 0.17% to 0.39%. During 2009, the average rates paid ranged from 0.25% to 0.79%. At February 15, 2011, the average rate on the debt was 0.27%.

TEP manages its exposure to variable interest rate risk by entering into transactions to maintain a mix of variable rate to fixed rate long-term debt of approximately one-third to two-thirds. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.

TEP is also 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. If LIBOR and other benchmark interest rates increase, TEP may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.

Interest Rate Swaps — Springerville Common Facilities Lease Debt

In 2006 and 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, 2010 and December 31, 2009. The swaps have the effect of fixing the interest rates on $64 million of the lease debt outstanding at December 31, 2010 at rates ranging from 3.18% to 5.77%.

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Mortgage Indenture

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

At December 31, 2010, TEP had a total of $578 million in outstanding Mortgage Bonds, consisting of $541 million in bonds securing the TEP Credit Agreement, and $37 million in bonds securing the 2010 TEP Reimbursement Agreement.

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 Tucson metropolitan area of Pima County as well as Fort Huachuca in contiguous Cochise County.

TEP has financed the following facilities, in whole or in part, with the proceeds of tax-exempt local furnishing bonds: Springerville Unit 2, a portion of TEP’s local must-run generation, 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.

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. In October 2010, the Pima Authority issued $100 million of tax-exempt local furnishing bonds for TEP’s benefit. TEP has until December 2011 to use the remaining 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. TEP received $1 million of its deposit back upon the issuance of the 2010 Pima A Bonds. SeeBond Issuances, above.

As of December 31, 2010, TEP had approximately $680 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.

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Capital Lease Obligations

At December 31, 2010, TEP had $489 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
Leased Asset	at December 31, 2010		Expiration	Purchase Option
	- In Millions -
Springerville Unit 1	$	302	2015	Fair market value purchase option
Springerville Coal Handling Facilities		77	2015	Fixed price purchase option of $120 million
Springerville Common Facilities		110	2017 & 2021	Fixed price purchase option of $106 million
Total Capital Lease Obligations	$	489

Except for 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. 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 owners of Springerville Units 3 and 4 to purchase such facilities. 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.

TEP’s capital lease obligation balances decline over time due to the normal capital lease payments made by TEP. See Note 6 for more information about the fixed purchase price amounts.

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Contractual Obligations

The following chart displays TEP’s contractual obligations as of December 31, 2010 by maturity and by type of obligation.

TEP’s Contractual Obligations
- - Millions of Dollars -

Payment Due in Years											2016
Ending December 31,	2011		2012		2013		2014		2015		and after		Other		Total
Long Term Debt
Principal	$	—	$	—	$	—	$	365	$	—	$	638	$	—	$	1,003
Interest		46		47		49		47		36		535		—		760
Capital Lease Obligations		107		118		122		195		24		79		—		645
Operating Leases		—		—		—		—		—		—		—		—
Purchase Obligations:
Fuel (including Transportation)		52		42		36		35		35		104		—		304
Purchased Power		26		15		8		4		—		—		—		53
Transmission		2		2		2		2		2		10		—		20
Coal Transportation Agreement		1		1		1		1		—		���		—		4
Other Long-Term Liabilities:
Pension & Other Post Retirement Obligations		27		5		6		6		6		36		—		86
Acquisition of Springerville Coal Handling and Common Facilities		—		—		—		—		120		106		—		226
Solar Installation Commitments		1		—		—		—		—		—		—		1
Unrecognized Tax Benefits		—		—		—		—		—		—		35		35
Total Contractual Cash Obligations	$	262	$	230	$	224	$	655	$	223	$	1,508	$	35	$	3,137

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 a leverage test. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At December 31, 2010, TEP was in compliance with these covenants. SeeTEP Credit Agreementabove.

• 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, 2010, TEP had posted a $1 million letter of credit as collateral with counterparties for credit enhancement.

Dividends on Common Stock

TEP declared and paid dividends to UniSource Energy of $60 million in 2010, $60 million in 2009, and $3 million in 2008.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2010, TEP was in compliance with the terms of the TEP Credit Agreement.

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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 $9 million in 2010, $7 million in 2009, and $9 million in 2008. 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.

	2010		2009		2008
	-Millions of Dollars-
Gas Revenues	$	146	$	149	$	172
Other Revenues		4		4		2
Total Operating Revenues		150		153		174
Total Purchased Gas and PGA Expense		91		99		119
Other Operations and Maintenance Expense		26		25		25
Depreciation and Amortization		8		7		7
Taxes other than Income Taxes		3		3		3
Total Other Operating Expenses		128		134		154
Operating Income (Loss)		22		19		20
Total Interest Expense		7		6		6
Total Other Income		—		—		—
Income Tax Expense (Benefit)		6		6		5
Net Income (Loss)	$	9	$	7	$	9

The table below shows UNS Gas’ therm sales and revenues for 2010, 2009 and 2008.

	Gas Sales (Millions of Therms)									Gas Revenues (Millions of Dollars)
					2010 vs.									2010 vs.
					2009									2009
	2010		2009		% Chng*			2008		2010		2009		% Chng*			2008
Retail Therm Sales:
Residential		73		70		4.9	%		72	$	89	$	91		(2.2	%)	$	97
Commercial		30		30		2.0	%		31		31		32		(6.1	%)		36
Industrial		2		2		(8.1	%)		2		2		2		(17.5	%)		2
Public Authorities		7		6		1.6	%		7		6		7		(7.2	%)		8
Total Retail Therm Sales		112		108		3.7	%		112	$	128	$	132		(3.7	%)	$	143
Transport		—		—		—			—		3		3		5.2	%		4
DSM		—		—		—			—		1		1		42.5	%		—
Negotiated Sales Program (NSP)		28		30		(4.6	%)		32		14		13		7.4	%		25
Total Therm Sales		140		138		1.9	%		144	$	146	$	149		(2.3	%)	$	172

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

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The table below summarizes UNS Gas’ retail margin revenues and fuel revenues collected from customers.

					Increase (Decrease)
	2010		2009		Amount			Percent*
Gas Revenues (in millions):
Retail Margin Revenues:
Residential	$	39	$	36	$	3			6.4	%
Commercial		10		10		—			4.8	%
Industrial		—		—		—			(6.0	%)
Public Authorities		2		2		—			2.7	%
Total Retail Margin Revenues (Non-GAAP)**	$	51	$	48	$	3			5.9	%
Transport and NSP		17		16		1			7.4	%
DSM		1		1		—			27.1	%
Retail Fuel Revenues		77		84		(7	)		(9.1	%)
Total Gas Revenues (GAAP)	$	146	$	149	$	(3	)		(2.3	%)

*	Percent change calculated on un-rounded data; may not correspond to data shown in table.
**	Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Retail Therm Revenues, which is determined in accordance with GAAP. UNS Gas believes that Retail Margin Revenues, which is Total Retail Therm Sales less retail fuel revenues and revenues for DSM programs, provides useful information to investors.

Retail therm sales in 2010 increased by 3.7% compared with 2009 due in part to cooler weather. Heating degree days increased 4% compared with both 2009 and the ten-year average. As of December 31, 2010, UNS Gas had approximately 146,500 retail customers, which represents an increase of less than 1% compared with the end of 2009. The increase in gas sales volumes as well as a 2% base rate increase that took effect in April 2010 resulted in a $3 million increase in retail margin revenues.

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 PGA mechanism which reduces the gas commodity price.

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of Gas EE Standards may reduce energy consumption by UNS Gas’ retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas. SeeItem 1. Business, UNS Gas, Rates and Regulation, Gas Utility Energy Efficiency Standards and Decoupling for more information.

Rates

2010 UNS Gas Rate Order

In 2008, UNS Gas filed a general rate case requesting a $10 million increase. In March 2010, the ACC issued an order authorizing a $3 million, or 2%, base rate increase effective April 2010. UNS Gas expects to file a new rate case with the ACC in 2011 to recover increasing costs.

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Fair Value Measurements

UNS Gas’s exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset or a regulatory liability, or as a component of AOCI rather than in the income statement. See Note 11 for more information.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas’ capital requirements consist primarily of capital expenditures. In 2010, capital expenditures were $10 million. UNS Gas expects operating 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 April 2010 covers some, but not all, of UNS Gas’ higher costs and capital investments.

Operating Cash Flow and Capital Expenditures

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

	2010			2009			2008
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$	18		$	37		$	3
Investing Activities		(9	)		(13	)		(16	)
Financing Activities		(11	)		—			1
Net Increase (Decrease) in Cash		(2	)		24			(12	)
Beginning Cash		31			7			19
Ending Cash	$	29		$	31		$	7

Operating cash flows decreased in 2010 due to the return of over-collected PGA gas costs to customers and cash outflows related to cash collateral deposited with gas supply and hedging counterparties.

Forecasted capital expenditures for UNS Gas are as follows:

	2011		2012		2013		2014		2015
	- Millions of Dollars -
UNS Gas	$	12	$	11	$	14	$	16	$	22

UNS Gas/UNS Electric Revolver

In November 2010, UNS Gas and UNS Electric amended and restated their existing credit agreement (UNS Gas/UNS Electric Revolver). The UNS Gas/UNS Electric Revolver was previously a $60 million unsecured revolving credit facility that matured in August 2011. Either borrower could borrow up to a maximum of $45 million so long as the combined amount borrowed by both companies did not exceed $60 million. As amended, the UNS Gas/UNS Electric Revolver is a $100 million unsecured facility that expires in November 2014. Either company can borrow up to a maximum of $70 million so long as the combined amount borrowed by both companies does not exceed $100 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.

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The UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. As of December 31, 2010, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.

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 15, 2011, UNS Gas had no outstanding borrowings or 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. If LIBOR or other benchmark interest rates increase, 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.

Senior Unsecured Notes

UNS Gas has $100 million of 6.23% senior unsecured notes outstanding of which $50 million mature in 2011 and $50 million mature 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, 2010, 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 2010/2011 winter season (November through March). Additionally, UNS Gas has approximately 38% of its expected gas consumption hedged for April through October 2011, and 32% hedged for the period November 2011 through March 2012.

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The following table displays UNS Gas’ contractual obligations as of December 31, 2010 by maturity and by type of obligation.

UNS Gas Contractual Obligations
- -Millions of Dollars-

Payment Due in Years											2016
Ending December 31,	2011		2012		2013		2014		2015		and after		Other		Total
Long Term Debt
Principal	$	50	$	—	$	—	$	—	$	50	$	—	$	—	$	100
Interest		6		3		3		3		4		—		—		19
Purchase Obligations — Fuel		25		10		5		4		3		19		—		66
Pension & Other Post Retirement Obligations		1		—		—		—		—		—		—		1
Unrecognized Tax Benefits		—		—		—		—		—		—		1		1
Total Contractual Cash Obligations	$	82	$	13	$	8	$	7	$	57	$	19	$	1	$	187

UNS Gas conducts certain of its gas procurement and risk management activities under 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, 2010, UNS Gas had posted $3 million in such credit enhancements.

Dividends on Common Stock

UNS Gas paid dividends to UniSource Energy of $10 million in both April 2010 and February 2011. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

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, 2010, UNS Gas was in compliance with the terms its note purchase agreement. SeeSenior Unsecured Notes, above.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $10 million in 2010, $6 million in 2009 and $4 million in 2008. Results in 2010 include $2 million of after-tax income related to a settlement with APS for refunds related to transactions with the California Power Exchange. 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.

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The table below provides summary financial information for UNS Electric.

	2010		2009		2008
	-Millions of Dollars-
Retail Electric Revenues	$	183	$	180	$	183
Wholesale Electric Revenues		31		5		10
Other Revenues		2		2		2
Total Operating Revenues		216		187		195
Purchased Energy and Fuel Expense		148		128		143
Other Operations and Maintenance Expense		29		25		22
Depreciation and Amortization		15		14		14
Taxes other than Income Taxes		4		4		4
Total Other Operating Expenses		196		171		183
Operating Income		20		16		12
Total Other Income		4		1		1
Total Interest Expense		7		7		7
Income Tax Expense		7		4		2
Net Income	$	10	$	6	$	4

The table below summarizes UNS Electric’s kWh sales and revenues for 2010, 2009 and 2008.

	Electric Sales — Millions of kWh									Electric Revenues — Millions of Dollars
					2010 vs.									2010 vs.
					2009									2009
	2010		2009		% Chng*			2008		2010		2009		% Chng*			2008
Electric Retail Sales
Residential		820		814		0.8	%		822	$	81	$	82		(1.6	%)	$	92
Commercial		606		608		(0.3	%)		620		61		63		(3.2	%)		70
Industrial		219		197		11.3	%		189		18		17		7.3	%		17
Mining		210		163		28.0	%		30		14		12	NM				3
Other		2		2		(9.1	%)		2		—		—		—			—
Total		1,857		1,784		4.1	%		1,663	$	174	$	174		0.3	%	$	182
RES & DSM		—		—		—			—		9		6		34.8	%		1
Wholesale Sales		707		154	NM				153		31		5	NM				10
Total Electric Sales		2,564		1,938		32.3	%		1,816	$	214	$	185		15.2	%	$	193

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

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The table below summarizes UNS Electric’s retail margin revenues and fuel revenues collected from customers.

					Increase (Decrease)
	2010		2009		Amount			Percent*
Electric Retail Revenues (in millions):
Retail Margin Revenues
Residential	$	22	$	21	$	1			5.8	%
Commercial		23		22		1			2.7	%
Industrial		7		7		—			14.2	%
Mining		5		3		2			35.9	%
Total Retail Margin Revenues (Non-GAAP)**	$	57	$	53	$	4			7.4	%
Retail Fuel Revenues		117		121		(4	)		(2.8	%)
DSM and RES Revenues		9		6		3		NM
Total Retail Revenues (GAAP)		183		180		3			1.5	%
Electric Wholesale Revenues		31		5		26		NM
Total Electric Revenues	$	214	$	185	$	29			15.2	%

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

In 2010, retail kWh sales increased by 4.1% compared with 2009. The increase is due primarily to increased usage by a copper mining customer and a new industrial customer in UNS Electric’s service area. The increase in retail kWh sales, as well as a 4% base rate increase that took effect in October 2010, contributed to a $4 million increase in retail margin revenues in 2010 compared with 2009.

As of December 31, 2010, UNS Electric had approximately 90,900 retail customers, an increase of less than 1% compared with 2009.

Wholesale revenues increased by $26 million in 2010 due to an increase in short-term wholesale trading activity. All revenues from wholesales sales are credited against costs recovered through UNS Electric’s PPFAC.

FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of EE Standards may reduce energy consumption by UNS Electric’s retail customers. UNS Electric’s customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on UNS Electric’s services. Self-generation by UNS Electric’s customers has not had a significant impact to date. SeeItem 1. Business, UNS Electric, Rates and Regulation, Electric Energy Efficiency Standards and Decouplingfor more information.

Rates

2010 UNS Electric Rate Order

In September 2010, the ACC issued an order authorizing a $7.4 million, or 4%, base rate increase that took effect October 1, 2010. The ACC order requires UNS Electric to file a rate case no later than 12 month after the transfer of BMGS into rate base. SeeItem 1. Business, UNS Electric, Rates and Regulation, 2010 UNS Electric Rate Orderfor more information.

Power Purchase Agreement

In May 2008, UNS Electric and UED entered into a PPA to secure all the output of the 90 MW gas-fired Black Mountain Generating Station (BMGS) from UED 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. A capacity charge and other costs associated with the PPA are recoverable through UNS Electric’s PPFAC.

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Renewable Energy Standard and Tariff

As part of the 2010 UNS Electric Rate Order, the ACC approved a funding mechanism that will allow UNS Electric to use RES funds to recover operating costs, depreciation, property taxes and a return on its investment in the UNS Electric-owned solar projects until these costs could be recovered as part of UNS Electric’s base rates. Under these terms, UNS Electric expects to invest $5 million annually in 2011 through 2014 in solar PV projects. We estimate that each $5 million investment would build approximately 1.25 MW of solar capacity. We expect the first project to be completed by the end of 2011 and UNS Electric to begin cost recovery through the RES in January 2012. For more information, seeItem. 1 Business, UNS Electric, Rates and Regulation, Renewable Energy Standard and Tariff.

Fair Value Measurements

UNS Electric’s exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset or a regulatory liability, or as a component of AOCI rather than in the income statement. See Note 11 for more information.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

In 2010, UNS Electric’s capital expenditures were $22 million. UNS Electric expects operating 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.

Operating Cash Flow and Capital Expenditures

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

	2010			2009			2008
	-Millions of Dollars-
Cash provided by (used in):
Operating Activities	$	23		$	37		$	14
Investing Activities		(23	)		(28	)		(30	)
Financing Activities		1			(8	)		22
Net Increase (Decrease) in Cash		1			1			6
Beginning Cash		10			9			3
Ending Cash	$	11		$	10		$	9

Operating cash flows decreased in 2010 due in part to cash collateral received in 2009 from energy supply and hedging counterparties.

Forecasted capital expenditures for UNS Electric are as follows:

	2011		2012		2013		2014		2015
	- Millions of Dollars -
UNS Electric	$	99	$	51	$	25	$	30	$	32

UNS Electric’s capital expenditure estimate for 2011 includes the purchase of BMGS from UED for approximately $62 million.

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.

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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 15, 2011, UNS Electric had $13 million outstanding under the UNS Gas/UNS Electric Revolver.

Interest Rate Risk

UNS Electric 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. If LIBOR or other benchmark interest rates increase, UNS Electric 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.

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, 2010, 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 that may require UNS Electric 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, 2010, UNS Electric had posted $13 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 2011 and 2017.

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The following table displays UNS Electric’s contractual obligations as of December 31, 2010 by maturity and by type of obligation.

UNS Electric Contractual Obligations
- -Millions of Dollars-

Payment Due in Years											2016
Ending December 31,	2011		2012		2013		2014		2015		and after		Other		Total
Long Term Debt
Principal	$	—	$	—	$	—	$	—	$	50	$	50	$	—	$	100
Interest		7		7		7		7		7		27		—		62
Purchase Obligations:
Purchased Power		47		33		35		—		—		—		—		115
Transmission		2		2		2		2		2		—		—		10
Pension & Other Post Retirement Obligations		1		—		—		—		—		—		—		1
Unrecognized Tax Benefits		—		—		—		—		—		—		4		4
Total Contractual Cash Obligations	$	57	$	42	$	44	$	9	$	59	$	77	$	4	$	292

Dividends on Common Stock

As of December 31, 2010, UNS Electric has not paid dividends to UniSource Energy. UNS Electric’s ability to pay dividends will depend on the cash needs for capital expenditures and various other factors.

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, 2010, UNS Electric was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above.

MILLENNIUM

RESULTS OF OPERATIONS

Millennium recorded a net loss of $13 million in 2010 compared with net income of $2 million in 2009. The net loss in 2010 resulted from several factors including the write-off of deferred tax assets and impairment losses on certain investments. Millennium’s results in 2009 included a $6 million pre-tax gain on the sale of an investment.

In December 2009 and December 2010, Millennium received interest payments of $0.5 million and $1 million, respectively on its $15 million note receivable from Mimosa.

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, 2010, Millennium had assets of $22 million including a $15 million note receivable, land and buildings of $2 million, deferred tax assets of $2 million and a cash balance of $3 million.

In June 2009, Millennium finalized the sale of its 50% interest in Sabinas to Mimosa. The terms called for an upfront $5 million payment which Millennium received in January 2009. Other key terms of the transaction include a three-year, 6% interest-bearing, collateralized $15 million note from Mimosa due June 2012. In June 2009, Millennium recorded a $6 million pre-tax gain on the sale.

Millennium made $8 million in dividend payments to UniSource Energy in 2010, $3 million in 2009 and $25 million in 2008. All of these dividends represented return of capital distributions. Millennium’s remaining commitment for all of its investments combined is less than $1 million.

Millennium’s financial assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2010 consist of Cash Equivalents of $1 million, which are valued based on observable market prices and are comprised of the fair value of money market funds.

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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.

	2010			2009			2008
	- Millions of Dollars -
UniSource Energy Parent Company	$	(6	)	$	(5	)	$	(6	)
UED		4			5			3
Total Other Net Loss	$	(2	)	$	—		$	(3	)

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 2010, UniSource Energy had capital expenditures of $16 million related to the construction of a new headquarters building.

UED

In 2010 and 2009, UED recorded after-tax income of $4 million and $5 million, respectively, related to the operation of BMGS.

In 2010, UED paid a $9 million dividend to UniSource Energy, of which $4 million represented a return of capital distribution. In 2009, UED paid a $30 million dividend to UniSource Energy which also represented a return of capital. In 2008, UED made distributions to UniSource Energy of less than $1 million.

In September 2010, the ACC issued a rate order for UNS Electric that approved the purchase of BMGS by UNS Electric, pending certain conditions. UNS Electric expects to complete the purchase during 2011. SeeUNS Electric, Factors Affecting Results of Operations, Rates, 2010 UNS Electric Rate Order, above for more information.

CRITICAL ACCOUNTING POLICIES

The preparation of the financial statements in accordance with U.S. Generally Accepted Accounting Principles (GAAP) requires management to apply accounting policies, make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. UniSource Energy considers the areas described in the Critical Accounting Policies as those that could yield materially different financial statement results based on application and interpretation of accounting policy, since making estimates and assumptions are subjective and complex, actual results could differ in subsequent periods. For additional information on UniSource Energy’s other significant accounting policies and recently issued accounting standards see Note 1.

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, the ACC can determine that TEP, UNS Gas or UNS Electric are allowed to recover certain expenses at a designated time in the future. In this situation, TEP, UNS Gas or UNS Electric defer these items as regulatory assets on the balance sheet and then reflect the costs as expenses when they are allowed to recover the costs from ratepayers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until rates to customers are reduced. TEP, UNS Electric and UNS Gas evaluate regulatory assets each period and believe recovery is probable.

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If in the future a separable portion of those operations no longer meets the criteria stated in Note 1 the impact of not meeting the criteria would be material to the financial statements. If TEP, UNS Gas and UNS Electric stopped applying regulatory accounting to all its regulated operations, we would write off the related balances of regulatory assets as an expense and record the regulatory liabilities as revenue on the income statement or in accumulated other comprehensive income (AOCI).

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 the period 1999 — 2008, TEP continued to apply regulatory accounting to its transmission and distribution operations.

At December 31, 2010, regulatory liabilities net of regulatory assets, totaled $12 million at TEP and $19 million at UNS Gas. Regulatory assets net of regulatory liabilities totaled $8 million at UNS Electric as of December 31, 2010. TEP, UNS Gas and UNS Electric regularly assess whether we can continue to apply regulatory accounting to cost-based rate regulated operations. Expectations of future recovery are generally based on orders issued by regulatory commissions and 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. See Note 2 for details regarding TEP, UNS Gas and UNS Electric regulatory assets and liabilities.

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. This includes obligations resulting from conditional future events. 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.

A liability for the fair value of an asset retirement obligation (ARO) is recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a part of the carrying amount of the long-lived assets. The asset retirement cost is subsequently charged to depreciation expense over its useful life. 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.

TEP 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, Sundt and Springerville Generating Stations. TEP estimated that its share of the cost to remove the Navajo and Four Corners facilities and settle the San Juan, Sundt and Springerville environmental obligations will be approximately $48 million at the retirement date. 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 that 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 estimated its share of the obligations will be approximately $2 million at the date of retirement.

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 the 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. See Note 2 for details regarding our Asset Retirement Obligation.

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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.

See Note 2 for details regarding net cost of removal.

Pension and Other Postretirement Benefit Plan Assumptions

TEP, UNS Gas and UNS Electric 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 are reasonable based on prior experience, market conditions and the advice of plan actuaries. Note 9 discusses the rate of return and discount rate used in the calculation of pension plan and other postretirement plan obligations for TEP, UNS Gas and UNS Electric.

TEP is required to recognize the underfunded status of its defined benefit pension and other postretirement plans as a liability. The underfunded status is 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. As the funded status, discount rates and actuarial facts change, the liability will vary significantly in future years. TEP records the underfunded amount for its pension and other postretirement obligations as a liability and a regulatory asset to reflect expected recovery of pension and other postretirement obligations through rates.

At December 31, 2010, TEP discounted its future pension plan obligations at 5.6% and its other postretirement plan obligations at a rate of 5.2%. The discount rate for future pension plan and other postretirement plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60^th and 90^th percentile of AA-rated U.S. corporate bonds with future cash flows that 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 $8 million and the 2011 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.

TEP calculates the market-related value of pension plan assets using the fair value of the assets on the measurement date. TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7% at December 31, 2010. In establishing its assumption as to the expected return on assets, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s 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 assets increases. A 25-basis point change in the expected return on assets would impact pension expense in 2011 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, 2010. This rate reflects both market conditions and historical 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 2011 by less than $1 million.

In 2011, TEP will incur pension and other postretirement benefit costs of approximately $12 million and $6 million, respectively. TEP expects to charge approximately $15 million of these costs to O&M expense and $3 million to capital. TEP expects to make pension plan contributions of $20 million in 2011. In 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA) trust to fund its other postretirement benefit plan. In 2011, TEP expects to make benefit payments to retirees under the postretirement benefit plan of approximately $4 million and contributions to the VEBA trust of $2 million.

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UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 5.5% at December 31, 2010. For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2011 pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2011, of which less than $1 million will be capitalized. UNS Gas and UNS Electric expect to make combined pension plan contributions of $3 million in 2011.

UNS Gas and UNS Electric discounted their other postretirement plan obligations using a rate of 5.2% at December 31, 2010. 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 2011.

Accounting for Derivative Instruments, Trading Activities and Hedging Activities

Commodity Derivative Contracts

TEP, UNS Gas and UNS Electric enter into forward contracts to purchase or sell capacity or energy at contract prices 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 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, TEP is permitted to recover in the PPFAC, prudent hedging transactions in a similar manner as UNS Electric and UNS Gas in their PPFAC and PGA, respectively. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or regulatory liability on the balance sheets of TEP, UNS Gas and UNS Electric. 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.

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. See Note 6 for additional details regarding interest rate swaps.

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 AOCI.

The market prices used to determine fair values for TEP, UNS Gas and UNS Electric’s derivative instruments at December 31, 2010, 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. See Note 1 for additional details regarding Cash Flow Hedges.

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

Unbilled Revenue — TEP, UNS Gas and UNS Electric

TEP, UNS Gas and UNS Electric’s retail revenues, which are recognized in the period that electricity or energy is delivered and consumed by customers, include unbilled revenue based on an estimate of MWh/therms delivered 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 MWh/therms delivered to the MWh/therms billed to TEP, UNS Gas and UNS Electric’s retail customers. The excess of estimated MWh/therms delivered over MWh/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 and UNS Electric’s actual load, the unbilled revenue amount increases during the spring and summer and decreases during the fall and winter. Conversely unbilled revenue for UNS Gas sales increases during the fall and winter and decreases during the spring and summer. A provision for uncollectible accounts is recorded as a component of operations and maintenance expense.

Plant Asset Depreciable Lives — TEP, UNS Gas and UNS Electric

TEP, UNS Gas and UNS Electric have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and expected net removal costs. Useful life of plant assets is further detailed in Note 5. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded on the income statement. The estimated useful lives and 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. For current approved ACC depreciation rates see Note 1. 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 have the effect of reducing depreciation expense by approximately $14 million annually.

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. Using the income tax rates in effect on the balance sheet date, this difference is accounted for by recording deferred income tax assets and liabilities on our balance sheets.

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

A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. At December 31, 2010, UniSource Energy had a $7 million valuation allowance. The valuation allowance related to unregulated investments’ losses are treated as capital losses for income tax purposes. If UniSource Energy incurs additional capital losses in the future, a valuation allowance will be recorded against the deferred tax asset unless management can identify future capital gains to offset the losses. For additional information see Note 8.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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

• The Financial Accounting Standards Board 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. After adopting this guidance on January 1, 2011, TEP and UNS Electric will continue to assign costs to both renewable energy credits and energy when purchased through a renewable purchased power agreement.

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• The Financial Accounting Standards Board issued amendments that require some new disclosures and clarify some existing disclosure requirements about fair value measurements. Disclosures about purchases, sales, issuances, and settlements in the rollforward of activity in Level 3 fair value measurements are effective for interim and annual reporting periods beginning January 1, 2011. We will incorporate these new disclosures in our March 31, 2011 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.

Forward-looking statements involve risks and uncertainties, that 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 Discussion and Analysis of Financial Condition and Results of Operations, 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 the 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, seeSafe Harbor 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.

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Interest Rate Risk

Long-Term Debt

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. At December 31, 2010 and December 31, 2009, TEP had $365 million and $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 2010 Coconino A Bonds and 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 0.26% in 2010 and 0.41% in 2009. The average weekly interest rate ranged from 0.17% to 0.39% in 2010 and 0.25% to 0.79% during 2009. Although short-term interest rates have been relatively low and stable in 2010 and 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 $3 million.

TEP manages its exposure to variable interest rate risk by entering into financing transactions to maintain a long-term debt mix of approximately one-third variable rate and two-thirds fixed rate. To maintain this balance, TEP entered into the following transactions in 2009 and 2010:

• In 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 2009 to 2014;

• 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; and

• After issuing $100 million in new fixed rate 2010 Pima A Bonds at a rate of 5.25% in October 2010, TEP refinanced $36.7 million of its 7.125% fixed rate 1997 Coconino A Bonds with a like principal amount of 2010 Coconino A Bonds at a variable rate.

As a result of these transactions, TEP’s variable rate debt comprised approximately 31% of its total long-term debt at December 31, 2010.

Capital Lease Debt

At December 31, 2010 and 2009, TEP’s debt also included variable rate lease debt totaling $63 million and $65 million, respectively, 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, 2010 and December 31, 2009.

Interest Rate Swaps

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, 2010	Fixed Rate			LIBOR Spread
$35 million		5.77	%		1.625	%
$22 million		3.18	%		1.625	%
$7 million		3.32	%		1.625	%

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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):

	2010			2009		2008
	- In Millions-
Unrealized Gains (Losses)	$	(8	)	$	1	$	(5	)

Revolving Credit Facilities

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, 2010, 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, 2010 and 2009, TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $112 million and $140 million, respectively. At December 31, 2010 and 2009, the fair value exceeded the carrying value by $7 million and $8 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.

Commodity Price Risk

TEP

TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, and coal. 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.

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.

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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 power purchases, 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 power purchases 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, 2010, 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 $1 million at December 31, 2010.

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):

	2010		2009		2008
	- In Millions-
Unrealized Gains (Losses)	$	4	$	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, 2010	months			months			over 1 yr.			Gain (Loss)
Prices actively quoted	$	(3	)	$	(3	)	$	(3	)	$	(9	)
Prices based on models and other valuation methods		—			1			2			3
Total	$	(3	)	$	(2	)	$	(1	)	$	(6	)

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%.

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	- Millions of Dollars -
Change in Market Price As of December 31, 2010	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 $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 $7 million in 2011.

TEP does not have a long-term coal supply contract for Sundt Unit 4. TEP purchases coal for Sundt Unit 4 on the spot market and can supply that unit with natural gas when the price is competitive with coal. 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, or the remaining life of Sundt Unit 4. This rail contract requires TEP to transport at least 75,000 tons of coal per year through 2015 at an estimated annual cost of $2 million or to make a minimum payment of $1 million. In 2010, TEP was notified of the closure of the mine that has served as the primary source of coal transported under that contract. The alternate sources identified in the contract are not viable alternatives for TEP. Therefore we recorded a minimum take-or-pay transportation accrual of $4 million for the remaining minimum payments in 2010. We will recover the minimum transportation charges via the PPFAC when they are paid annually.

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 $21 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, 2010, 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 $1 million at December 31, 2010.

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

	2010			2009		2008
	- In Millions -
Unrealized Gains (Losses)	$	(2	)	$	6	$	(13	)

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 reduction in regulatory assets 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.

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 $47 million in 2011, $33 million in 2012, and $35 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 $9 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $9 million.

UNS Electric hedges a portion of its natural gas exposure from gas-indexed purchased 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 satisfy its remaining gas and purchased power needs through a combination of additional forward purchases and purchases in the short-term and spot markets.

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 $1 million at December 31, 2010.

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

	2010			2009		2008		��
	- In Millions -
Unrealized Gains (Losses)	$	(2	)	$	12	$	(33	)

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 reduction in regulatory assets of $1 million.

K-81

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 Gas and UNS Electric each have 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, 2010, the combined credit exposure to TEP, UNS Gas and UNS Electric from financial institution counterparties was approximately $4 million.

As of December 31, 2010, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $20 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit exposure, totaling approximately $5 million.

TEP maintains a margin account with a broker to support certain risk management and trading activities. At December 31, 2010, TEP had less than $1 million in that margin account. At December 31, 2010, 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, 2010, UNS Gas had purchased under fixed price contracts approximately 32% of its expected consumption for the 2011/2012 winter season. At December 31, 2010, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts.As of December 31, 2010, UNS Gas had posted $3 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, 2010, UNS Electric had $3 million in credit exposure under such contracts. As of December 31, 2010, UNS Electric had posted $13 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.

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, 2010. 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, 2010, UniSource Energy Corporation’s internal control over financial reporting was effective.

K-82

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, 2010. 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, 2010, Tucson Electric Power Company’s internal control over financial reporting was effective.

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, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules 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, 2010, 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 schedules, 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 schedules, 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.

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
March 1, 2011

K-84

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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.

/s/ PricewaterhouseCoopers LLPPricewaterhouseCoopers LLP
Phoenix, Arizona
March 1, 2011

K-85

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2010			2009			2008
	- Thousands of Dollars -
	(Except Per Share Amounts)
Operating Revenues
Electric Retail Sales	$	1,051,002		$	1,047,619		$	988,612
Provision for Rate Refunds — CTC Revenue		—			—			(58,092	)
Net Electric Retail Sales		1,051,002			1,047,619			930,520
Electric Wholesale Sales		151,673			130,904			248,855
California Power Exchange (CPX) Provision for Wholesale Refunds		(2,970	)		(4,172	)		—
Gas Revenue		141,036			144,609			163,977
Other Revenues		112,936			77,741			66,714
Total Operating Revenues		1,453,677			1,396,701			1,410,066
Operating Expenses
Fuel		296,980			298,655			299,987
Purchased Energy		307,288			296,861			454,765
Transmission		10,945			10,181			19,214
Decrease to Reflect PPFAC/PGA Recovery Treatment		(31,105	)		(17,091	)		(10,975	)
Total Fuel and Purchased Energy		584,108			588,606			762,991
Other Operations and Maintenance		370,067			333,887			295,658
Depreciation		128,215			144,960			132,366
Amortization		28,094			31,058			15,324
Amortization of Transition Recovery Asset		—			—			23,945
Taxes Other Than Income Taxes		46,241			45,857			39,339
Total Operating Expenses		1,156,725			1,144,368			1,269,623
Operating Income		296,952			252,333			140,443
Other Income (Deductions)
Interest Income		7,779			12,072			11,011
Other Income		11,038			18,063			7,838
Other Expense		(15,202	)		(5,292	)		(9,286	)
Total Other Income (Deductions)		3,615			24,843			9,563
Interest Expense
Long-Term Debt		65,020			58,134			70,227
Capital Leases		46,740			49,270			52,511
Other Interest Expense		1,651			3,468			1,837
Interest Capitalized		(2,587	)		(2,302	)		(5,565	)
Total Interest Expense		110,824			108,570			119,010
Income Before Income Taxes		189,743			168,606			30,996
Income Tax Expense		78,266			64,348			16,975
Net Income	$	111,477		$	104,258		$	14,021
Weighted-Average Shares of Common Stock Outstanding (000)		36,415			35,858			35,632
Basic Earnings per Share	$	3.06		$	2.91		$	0.39
Diluted Earnings per Share	$	2.82		$	2.69		$	0.39
Dividends Declared per Share	$	1.56		$	1.16		$	0.96

See Notes to Consolidated Financial Statements.

K-86

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2010			2009			2008
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,142,364		$	1,145,051		$	1,079,964
Cash Receipts from Electric Wholesale Sales		194,580			175,679			353,618
Cash Receipts from Gas Sales		157,819			163,441			182,271
Cash Receipts from Operating Springerville Unit 3 & 4		102,563			68,951			57,657
Interest Received		10,026			13,470			17,246
Performance Deposits Received		18,470			34,630			34,404
Income Tax Refunds Received		341			20,242			22,355
Other Cash Receipts		24,642			15,465			16,631
Refund of Disputed Transmission Costs		—			—			10,665
Purchased Energy Costs Paid		(357,751	)		(334,481	)		(577,588	)
Fuel Costs Paid		(247,484	)		(300,810	)		(292,646	)
Payment of Other Operations and Maintenance Costs		(255,329	)		(236,184	)		(196,860	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(163,037	)		(161,574	)		(154,548	)
Wages Paid, Net of Amounts Capitalized		(125,893	)		(122,245	)		(108,504	)
Interest Paid, Net of Amounts Capitalized		(59,749	)		(54,641	)		(58,774	)
Performance Deposits Paid		(19,220	)		(22,260	)		(48,520	)
Capital Lease Interest Paid		(38,646	)		(38,598	)		(43,828	)
Income Taxes Paid		(22,797	)		(9,050	)		(9,900	)
Allowance for Equity Funds Used During Construction		(4,232	)		(4,113	)		(3,244	)
Excess Tax Benefit from Stock Options Exercised		(3,338	)		(3,256	)		(633	)
Other Cash Payments		(10,970	)		(6,520	)		(5,999	)
Net Cash Flows — Operating Activities		342,359			343,197			273,767
Cash Flows from Investing Activities
Capital Expenditures		(265,141	)		(282,991	)		(354,080	)
Purchase of Sundt Unit 4 Lease Asset		(51,389	)		—			—
Purchase of Springerville Lease Debt		—			(31,375	)		—
Purchase of Renewable Energy Credits		(7,185	)		—			—
Prepayment Deposits on UED Debt		(3,188	)		(3,625	)		—
Deposit — Collateral Trust Bond Trustee		—			—			(133,111	)
Return of Investments in Springerville Lease Debt		25,615			12,736			24,918
Customer Advance Reimbursement from Citizens		1,254			—			—
Other Cash Receipts		373			331			5,137
Return of Investment from Millennium Energy Businesses		423			8,333			839
Insurance Proceeds for Replacement Assets		1,041			4,928			8,035
Investment in and Loans to Equity Investees		(401	)		(207	)		(600	)
Other Cash Payments		(1,901	)		(661	)		(711	)
Net Cash Flows — Investing Activities		(300,499	)		(292,531	)		(449,573	)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities		239,000			203,000			242,000
Proceeds from Issuance of Long-Term Debt		127,815			—			320,745
Proceeds from Issuance of Short-Term Debt		—			30,000			—
Proceeds from Stock Options Exercised		13,391			3,441			1,969
Excess Tax Benefit from Stock Options Exercised		3,338			3,256			633
Other Cash Receipts		9,068			5,681			6,028
Repayments of Borrowings Under Revolving Credit Facilities		(268,500	)		(198,000	)		(237,000	)
Common Stock Dividends Paid		(56,590	)		(41,429	)		(34,043	)
Payments of Capital Lease Obligations		(55,997	)		(24,192	)		(74,316	)
Repayments of Long-Term Debt		(51,592	)		(6,000	)		(76,000	)
Payments of Debt Issue/Retirement Costs		(8,341	)		(2,268	)		(3,739	)
Other Cash Payments		(2,775	)		(2,405	)		(5,672	)
Net Cash Flows — Financing Activities		(51,183	)		(28,916	)		140,605
Net Increase (Decrease) in Cash and Cash Equivalents		(9,323	)		21,750			(35,201	)
Cash and Cash Equivalents, Beginning of Year		76,922			55,172			90,373
Cash and Cash Equivalents, End of Year	$	67,599		$	76,922		$	55,172
Non-Cash Financing Activity
Repayment of UED Short-Term Debt	$	(3,188	)	$	(3,625	)	$	—
Repayment of Collateral Trust Bonds	$	—		$	—		$	(128,300	)

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-87

UNISOURCE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,452,928		$	4,147,268
Utility Plant Under Capital Leases		583,374			720,628
Construction Work in Progress		210,971			144,551
Total Utility Plant		5,247,273			5,012,447
Less Accumulated Depreciation and Amortization		(1,824,843	)		(1,652,296	)
Less Accumulated Amortization of Capital Lease Assets		(460,932	)		(574,437	)
Total Utility Plant — Net		2,961,498			2,785,714
Investments and Other Property
Investments in Lease Debt and Equity		103,844			132,168
Other		61,676			60,239
Total Investments and Other Property		165,520			192,407
Current Assets
Cash and Cash Equivalents		67,599			76,922
Accounts Receivable — Customer		84,048			80,191
Unbilled Accounts Receivable		53,084			53,361
Allowance for Doubtful Accounts		(6,125	)		(5,977	)
Fuel Inventory		29,216			48,159
Materials and Supplies		65,832			68,633
Derivative Instruments		5,214			2,653
Regulatory Assets — Current		56,962			41,772
Deferred Income Taxes — Current		35,028			52,355
Investments in Lease Debt		1,433			—
Other		28,659			28,236
Total Current Assets		420,950			446,305
Regulatory and Other Assets
Regulatory Assets — Noncurrent		191,124			147,325
Derivative Instruments		9,806			4,498
Other Assets		30,425			24,993
Total Regulatory and Other Assets		231,355			176,816
Total Assets	$	3,779,323		$	3,601,242

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-88

UNISOURCE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS

	December 31,
	2010		2009
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	820,786	$	750,865
Capital Lease Obligations		429,074		488,349
Long-Term Debt		1,352,977		1,307,795
Total Capitalization		2,602,837		2,547,009
Current Liabilities
Current Obligations Under Capital Leases		60,347		40,441
Borrowing Under Revolving Credit Facility		—		35,000
Current Maturities of Long-Term Debt		57,000		12,195
Accounts Payable — Trade		109,318		98,990
Interest Accrued		39,120		41,396
Accrued Taxes Other than Income Taxes		39,140		36,698
Accrued Employee Expenses		26,969		27,545
Customer Deposits		29,795		25,978
Regulatory Liabilities — Current		69,483		42,229
Derivative Instruments		30,574		21,186
Other		1,678		4,038
Total Current Liabilities		463,424		385,696
Deferred Credits and Other Liabilities
Deferred Income Taxes — Noncurrent		244,148		227,199
Regulatory Liabilities — Noncurrent		201,329		211,903
Derivative Instruments		22,969		19,489
Pension and Other Postretirement Benefits		127,343		123,476
Other		117,273		86,470
Total Deferred Credits and Other Liabilities		713,062		668,537
Commitments and Contingencies (Note 4)
Total Capitalization and Other Liabilities	$	3,779,323	$	3,601,242

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-89

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31,
					2010			2009
					- Thousands of Dollars -
COMMON STOCK EQUITY
Common Stock-No Par Value					$	715,688		$	696,206
		2010		2009
Shares Authorized		75,000,000		75,000,000
Shares Outstanding		36,541,954		35,851,185
Accumulated Earnings						114,867			60,461
Accumulated Other Comprehensive Loss						(9,769	)		(5,802	)
Total Common Stock Equity						820,786			750,865
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding						—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1						302,229			320,843
Springerville Coal Handling Facilities						76,583			85,224
Springerville Common Facilities						110,571			109,499
Sundt Unit 4						—			13,077
Other						38			147
Total Capital Lease Obligations						489,421			528,790
Less Current Maturities						(60,347	)		(40,441	)
Total Long-Term Capital Lease Obligations						429,074	��		488,349
LONG-TERM DEBT
Issue	Maturity		Interest Rate
UniSource Energy:
Convertible Senior Notes		2035		4.50%		150,000			150,000
Credit Agreement		2014		Variable		27,000			40,000
Tucson Electric Power Company:
Variable Rate IDBs		2014		Variable		365,300			458,600
Unsecured IDBs		2020 – 2040		4.95% to 6.375%		638,315			445,015
UNS Gas and UNS Electric:
Senior Unsecured Notes		2011 – 2023		6.23% to 7.1%		200,000			200,000
UED:
Secured Term Loan		2012		Variable		29,362			26,375
Total Stated Principal Amount						1,409,977			1,319,990
Less Current Maturities						(57,000	)		(12,195	)
Total Long-Term Debt						1,352,977			1,307,795
Total Capitalization					$	2,602,837		$	2,547,009

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, 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 for Stock Options		120		1,969									1,969
Shares Issued Under Share-Based Compensation Plans		23		—									—
Tax Benefit Realized from Share-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 for Stock Options		282		4,077									4,077
Shares Issued Under Share-Based Compensation Plans		101		—									—
Tax Benefit Realized from Share-Based Compensation Plans				3,256									3,256
Other Share-Based Compensation				1,234									1,234
Balances at December 31, 2009		35,851		696,206			60,461			(5,802	)		750,865
Comprehensive Income:
2010 Net Income							111,477						111,477
Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes)										(6,431	)		(6,431	)
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $2,140 income taxes)										3,264			3,264
Employee Benefit Obligations
Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $523 income taxes)										(800	)		(800	)
Total Comprehensive Income													107,510
Dividends							(57,071	)					(57,071	)
Shares Issued under Deferred Compensation Plans		16		519									519
Shares Issued for Stock Options		660		12,756									12,756
Shares Issued Under Share-Based Compensation Plans		15		—									—
Tax Benefit Realized from Share-Based Compensation Plans				3,338									3,338
Other Share-Based Compensation				2,869									2,869
Balances at December 31, 2010		36,542	$	715,688		$	114,867		$	(9,769	)	$	820,786

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

We describe limitations on our ability to pay dividends in Note 7.

See Notes to Consolidated Financial Statements.

K-91

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2010			2009			2008
	- Thousands of Dollars -
Operating Revenues
Electric Retail Sales	$	868,188		$	867,516		$	805,528
Provision for Rate Refunds — CTC Revenue		—			—			(58,092	)
Net Electric Retail Sales		868,188			867,516			747,436
Electric Wholesale Sales		140,815			152,955			272,411
California Power Exchange (CPX) Provision for Wholesale Refunds		(2,970	)		(4,172	)		—
Other Revenues		118,946			82,688			71,962
Total Operating Revenues		1,124,979			1,098,987			1,091,809
Operating Expenses
Fuel		286,071			281,710			289,985
Purchased Power		118,716			144,528			250,580
Transmission		3,254			3,066			10,515
Decrease to Reflect PPFAC Recovery Treatment		(23,025	)		(20,724	)		—
Total Fuel and Purchased Energy		385,016			408,580			551,080
Other Operations and Maintenance		323,537			289,765			256,584
Depreciation		99,510			116,970			105,859
Amortization		32,196			35,931			20,181
Amortization of Transition Recovery Asset		—			—			23,945
Taxes Other Than Income Taxes		37,953			37,618			31,650
Total Operating Expenses		878,212			888,864			989,299
Operating Income		246,767			210,123			102,510
Other Income (Deductions)
Interest Income		6,707			11,471			9,900
Other Income		6,615			10,991			5,708
Other Expense		(4,389	)		(2,904	)		(6,249	)
Total Other Income (Deductions)		8,933			19,558			9,359
Interest Expense
Long-Term Debt		42,378			36,226			47,456
Capital Leases		46,734			49,258			52,491
Other Interest Expense		433			1,571			1,367
Interest Capitalized		(1,880	)		(1,752	)		(4,675	)
Total Interest Expense		87,665			85,303			96,639
Income Before Income Taxes		168,035			144,378			15,230
Income Tax Expense		61,057			55,130			10,867
Net Income	$	106,978		$	89,248		$	4,363

See Notes to Consolidated Financial Statements.

K-92

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2010			2009			2008
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	947,498		$	944,873		$	883,423
Cash Receipts from Electric Wholesale Sales		190,779			199,918			377,579
Cash Receipts from Operating Springerville Unit 3 & 4		102,563			68,951			57,657
Reimbursement of Affiliate Charges		18,356			19,998			16,534
Interest Received		8,998			12,768			15,849
Income Tax Refunds Received		3,369			14,462			20,902
Performance Deposits Received		5,040			14,000			10,150
Refund of Disputed Transmission Costs		—			—			10,665
Other Cash Receipts		11,252			10,125			9,268
Fuel Costs Paid		(236,436	)		(282,653	)		(284,830	)
Purchased Power Costs Paid		(169,658	)		(185,129	)		(364,356	)
Payment of Other Operations and Maintenance Costs		(239,074	)		(223,760	)		(185,206	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(134,540	)		(124,053	)		(117,611	)
Wages Paid, Net of Amounts Capitalized		(101,815	)		(97,289	)		(84,857	)
Capital Lease Interest Paid		(38,640	)		(38,586	)		(43,807	)
Interest Paid, Net of Amounts Capitalized		(38,232	)		(33,128	)		(38,467	)
Income Taxes Paid		(19,663	)		(14,606	)		—
Performance Deposits Paid		(5,040	)		(14,000	)		(10,150	)
Allowance for Equity Funds Used During Construction		(3,567	)		(3,516	)		(2,950	)
Other Cash Payments		(3,435	)		(3,827	)		(4,037	)
Net Cash Flows — Operating Activities		297,755			264,548			265,756
Cash Flows from Investing Activities
Capital Expenditures		(215,697	)		(231,969	)		(291,990	)
Purchase of Sundt Unit 4 Lease Asset		(51,389	)		—			—
Purchase of Springerville Lease Debt		—			(31,375	)		—
Purchase of Renewable Energy Credits		(6,742	)		—			—
Deposit — Collateral Trust Bond Trustee		—			—			(133,111	)
Other Cash Payments		(1,483	)		(411	)		(711	)
Return of Investments in Springerville Lease Debt		25,615			12,736			24,918
Insurance Proceeds for Replacement Assets		1,041			4,928			8,035
Other Cash Receipts		347			6			5,055
Net Cash Flows — Investing Activities		(248,308	)		(246,085	)		(387,804	)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility		177,000			171,000			170,000
Proceeds from Issuance of Long-Term Debt		118,245			—			220,745
Equity Investment from UniSource Energy		15,000			30,000			—
Other Cash Receipts		3,241			2,447			1,237
Repayments of Borrowings Under Revolving Credit Facility		(212,000	)		(146,000	)		(170,000	)
Dividends Paid to UniSource Energy		(60,000	)		(60,000	)		(2,500	)
Payments of Capital Lease Obligations		(55,889	)		(24,091	)		(74,228	)
Repayments of Long-Term Debt		(30,000	)		—			(10,000	)
Payments of Debt Issue/Retirement Costs		(5,988	)		(1,329	)		(3,120	)
Other Cash Payments		(1,491	)		(1,347	)		(3,421	)
Net Cash Flows — Financing Activities		(51,882	)		(29,320	)		128,713
Net Increase (Decrease) in Cash and Cash Equivalents		(2,435	)		(10,857	)		6,665
Cash and Cash Equivalents, Beginning of Year		22,418			33,275			26,610
Cash and Cash Equivalents, End of Year	$	19,983		$	22,418		$	33,275
Non-Cash Financing Activity — Repayment of Collateral Trust Bonds	$	—		$	—		$	(128,300	)

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-93

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	3,863,431		$	3,584,308
Utility Plant Under Capital Leases		582,669			719,922
Construction Work in Progress		153,981			113,390
Total Utility Plant		4,600,081			4,417,620
Less Accumulated Depreciation and Amortization		(1,729,747	)		(1,582,442	)
Less Accumulated Amortization of Capital Lease Assets		(460,257	)		(573,853	)
Total Utility Plant — Net		2,410,077			2,261,325
Investments and Other Property
Investments in Lease Debt and Equity		103,844			132,168
Other		43,588			31,813
Total Investments and Other Property		147,432			163,981
Current Assets
Cash and Cash Equivalents		19,983			22,418
Accounts Receivable — Customer		63,916			62,508
Unbilled Accounts Receivable		32,217			32,368
Allowance for Doubtful Accounts		(4,106	)		(3,806	)
Accounts Receivable — Due from Affiliates		5,442			5,218
Fuel Inventory		29,209			48,149
Materials and Supplies		54,732			56,712
Derivative Instruments		1,318			5,043
Regulatory Assets — Current		34,023			27,026
Deferred Income Taxes — Current		36,283			50,789
Investments in Lease Debt		1,433			—
Other		25,034			24,362
Total Current Assets		299,484			330,787
Regulatory and Other Assets
Regulatory Assets — Noncurrent		182,514			137,147
Derivative Instruments		1,834			1,075
Other Assets		24,767			19,984
Total Regulatory and Other Assets		209,115			158,206
Total Assets	$	3,066,108		$	2,914,299

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-94

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS

	December 31,
	2010		2009
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	701,155	$	643,144
Capital Lease Obligations		429,074		488,311
Long-Term Debt		1,003,615		903,615
Total Capitalization		2,133,844		2,035,070
Current Liabilities
Current Obligations Under Capital Leases		60,309		40,332
Borrowing Under Revolving Credit Facility		—		35,000
Accounts Payable — Trade		77,389		71,328
Accounts Payable — Due to Affiliates		3,989		3,695
Interest Accrued		31,771		33,970
Accrued Taxes Other than Income Taxes		29,873		28,404
Accrued Employee Expenses		23,710		24,409
Customer Deposits		21,191		18,125
Derivative Instruments		7,288		9,434
Regulatory Liabilities — Current		58,936		26,639
Other		3,379		1,444
Total Current Liabilities		317,835		292,780
Deferred Credits and Other Liabilities
Deferred Income Taxes — Noncurrent		226,107		217,316
Regulatory Liabilities — Noncurrent		170,223		179,478
Derivative Instruments		11,650		11,195
Pension and Other Postretirement Benefits		120,590		116,991
Other		85,859		61,469
Total Deferred Credits and Other Liabilities		614,429		586,449
Commitments and Contingencies (Note 4)
Total Capitalization and Other Liabilities	$	3,066,108	$	2,914,299

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-95

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31,
					2010			2009
					- Thousands of Dollars -
COMMON STOCK EQUITY
Common Stock-No Par Value					$	858,971		$	843,971
		2010		2009
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						(141,690	)		(188,668	)
Accumulated Other Comprehensive Loss						(9,769	)		(5,802	)
Total Common Stock Equity						701,155			643,144
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding						—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1						302,229			320,843
Springerville Coal Handling Facilities						76,583			85,224
Springerville Common Facilities						110,571			109,499
Sundt Unit 4						—			13,077
Total Capital Lease Obligations						489,383			528,643
Less Current Maturities						(60,309	)		(40,332	)
Total Long-Term Capital Lease Obligations						429,074			488,311
LONG-TERM DEBT
Issue	Maturity		Interest Rate
Variable Rate IDBs		2014		Variable		365,300			458,600
Unsecured IDBs		2020 - 2040		4.95% to 6.375%		638,315			445,015
Total Long-Term Debt						1,003,615			903,615
Total Capitalization					$	2,133,844		$	2,035,070

See Notes to Consolidated Financial Statements.

K-96

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS 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, 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
Comprehensive Income:
2010 Net Income								106,978						106,978
Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes)											(6,431	)		(6,431	)
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $2,140 income taxes)											3,264			3,264
Employee Benefit Obligations
Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $523 income taxes)											(800	)		(800	)
Total Comprehensive Income														103,011
Capital Contribution from UniSource Energy		15,000												15,000
Dividends Paid								(60,000	)					(60,000	)
Balances at December 31, 2010	$	858,971	$	(6,357	)		$	(141,690	)	$	(9,769	)	$	701,155

We describe limitations on our ability to pay dividends in Note 7.

See Notes to Consolidated Financial Statements.

K-97

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NATURE OF OPERATIONS

UniSource Energy Corporation (UniSource Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. 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 is a regulated public utility and UniSource Energy’s largest operating subsidiary, representing approximately 81% of UniSource Energy’s total assets as of December 31, 2010. TEP generates, transmits and distributes electricity to approximately 403,000 retail electric customers in a 1,155 square mile area in southeastern 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 147,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as Santa Cruz County in southern Arizona. UNS Electric is an electric transmission and distribution company with approximately 91,000 retail customers in Mohave and Santa Cruz counties. UED owns Black Mountain Generating Station (BMGS), a natural gas-fired combustion turbine in northwestern Arizona, that, through a power purchase agreement, provides electricity to UNS Electric.

Millennium has existing investments in unregulated businesses that represented less than 1% of UniSource Energy’s assets as of December 31, 2010. Millennium is in the process of exiting its investments, except for Southwest Energy Solutions (SES), which may yield gains or losses. See Note 13. SES, a wholly-owned subsidiary of Millennium, provides supplemental labor and meter reading services to TEP, UNS Gas and UNS Electric.

Our business is comprised of four reporting segments — TEP, UNS Gas, UNS Electric, and Millennium.

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

BASIS OF PRESENTATION

We account for our investments in subsidiaries or other companies using one of three methods, consolidation, equity or cost. We consolidate when we hold a majority of the voting stock and we can exercise control over the operations and policies of the company. Consolidation means accounts of the parent and subsidiary 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 partnerships and affiliated companies 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 as investments on the balance sheet and net income (loss) from the entity is reflected in Other Income on the income statements. We evaluate our equity method investments for “other than temporary” decline in value at least quarterly. If the decline in value is other than temporary, we recognize the adjustment in earnings.

K-98

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

We use the cost method if we do not exercise significant influence in an investment and record income only to the extent we receive dividends or distributions. We evaluate our cost method investments for potential decline in value at least quarterly. If we determine the decline in value is other than temporary we recognize the adjustment in earnings.

USE OF ACCOUNTING ESTIMATES

Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles (GAAP) in the U.S. These estimates and assumptions affect:

• Assets and liabilities in our balance sheets at the dates of the financial statements;

• Our disclosures about contingent assets and liabilities at the dates of the financial statements; and

• Our revenues and expenses in our income statements during the periods presented.

Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, 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 that rate-regulated companies 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 at a designated time in the future. In this situation, TEP, UNS Gas or UNS Electric defer these items as regulatory assets on the balance sheet and then reflect the costs as expenses when they are allowed to recover them from ratepayers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until rates to customers are reduced. TEP, UNS Gas and UNS Electric evaluate 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. TEP Transmission and Distribution Operations, UNS Gas and UNS Electric apply regulatory accounting.

A rate-regulated company can apply regulatory accounting policies and practices only under the following conditions:

• An independent regulator sets rates;

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

• Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.

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.

UTILITY PLANT

Utility Plant is a term we use to describe the business property and equipment that supports electric and gas services, consisting primarily of generation, transmission and distribution facilities. TEP, UNS Gas and UNS Electric report utility plant at original cost. Original costs included in utility plant are materials and labor, contractor services, construction overhead (where applicable), and an Allowance for Funds Used During Construction (AFUDC).

K-99

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Costs to replace major units of property are included in utility plant. The cost of repairs and maintenance, including planned major overhauls at TEP’s generation plants, are recorded to Other Operations and Maintenance Expense on the income statement as the costs are incurred.

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.

AFUDC and Capitalized Interest

AFUDC reflects the cost of debt or equity funds used to finance construction and 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 for equity funds is recorded as Other Income.

Average AFUDC Rate on Regulated Construction Expenditures	2010			2009			2008
TEP(1)		6.65	%		6.40	%		7.50	%
UNS Gas		8.19	%		7.05	%		8.37	%
UNS Electric		8.22	%		7.62	%		8.84	%

⁽¹⁾ Prior to December 2008, TEP also had an average capitalized interest rate on generation-related construction expenditures of 5.02%.

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. Further detail regarding types of assets and the period over which they are depreciated can be found in 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. Below are the summarized average annual depreciation rates for all utility plants.

	TEP			UNS Gas			UNS Electric			UED
2010		3.14	%		2.83	%		4.35	%		2.57	%
2009		3.64	%		2.76	%		4.33	%		2.57	%
2008		3.33	%		2.77	%		4.47	%		2.57	%

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 Utility Plant under Capital Leases

TEP financed the following generation assets with capital leases: Springerville Common Facilities, Springerville Unit 1 and the Springerville Coal Handling Facilities. The amount of lease expense incurred for TEP’s generation-related capital leases consists of amortization expense as described in Note 5 and Interest Expense on Capital Leases as reflected on the Consolidated Statements of Income. The lease terms are described in TEP Capital Lease Obligations in Note 6.

K-100

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP holds investments in lease debt in two of TEP’s capital leases: Springerville Unit 1 and Springerville Coal Handling Facilities. These holdings are considered to be held-to-maturity investments because TEP has the ability and intent to hold them until maturity. TEP records these investments at amortized cost and recognizes interest income. See Note 11 for information on financial instruments not carried at fair value. 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. In January 2011, TEP received the final maturity payment of $1 million on the investment in Springerville Coal Handling Facilities debt.

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

JOINTLY-OWNED FACILITIES

TEP has investments in several plants and transmission facilities jointly-owned with other companies. These projects are accounted for on a proportionate consolidation basis. Further discussion on jointly-owned facilities can be found in 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.

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

We evaluate long-lived assets for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If undiscounted expected future cash flows are less than the carrying value of the asset, an impairment loss is recognized and the asset is written down to the fair value of the asset.

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

K-101

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

DEFERRED FINANCING COSTS

The costs related to the issuance of debt are deferred and amortized 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, regulatory fees and printing costs.

TEP, UNS Gas and UNS Electric defer and amortize the gains and losses on reacquired debt associated with 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 or commodities are delivered to customers. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period.

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, customer rates and changes in the composition of customer classes.

Effective in January 2009, as a result of the 2008 TEP Rate Order, TEP was authorized a rate-adjustment mechanism that provides for the recovery of actual fuel and purchased energy cost, similar to mechanisms already in place at UNS Gas and UNS Electric. The revenue surcharge or surcredit adjusts the customers’ rate for delivered electricity or gas to collect or return under- or over- recovered energy 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 net settled and 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. The allowance is determined based on historical bad debt patterns, retail sales and economic conditions. TEP, UNS Gas and UNS Electric refer accounts to external collection agencies after a period of 90 days.

TEP recognizes revenue from operating Springerville Unit 3 and Unit 4 on behalf of Tri-State and SRP as Other Revenues. Effective with commercial operation of Springerville Unit 3 in July 2006 and Springerville Unit 4 in December 2009, Tri-State and SRP reimburse 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 as Other Revenues. Expenses are recorded in the respective line item of the income statement based on the nature of service or materials provided.

K-102

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

INVENTORY

Materials and supplies consist of transmission, distribution and generating construction and repair materials. TEP, UNS Gas and UNS Electric record fuel, materials and supply inventories at the lower of cost or market prices with cost being determined on a weighted average basis. TEP, UNS Gas and UNS Electric use 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 TEP’s fuel purchase contracts.

RECOVERY OF 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 fuel and purchased energy costs incurred and the recovery of such costs in rates effective January 1, 2009. UNS Electric also defers differences between purchased energy costs incurred and the recovery of such costs in rates. Fuel and purchased energy cost over-recoveries (the excess of fuel costs recovered in base rates over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel costs recovered in base rates) are deferred as regulatory assets. See Note 2.

UNS Gas Purchased Gas Adjustor (PGA)

UNS Gas defers the difference between gas costs incurred and the recovery of such costs in base rates under a Purchased Gas Adjustor (PGA) mechanism. Gas cost over-recoveries (the excess of gas costs recovered in base rates over gas costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of gas costs incurred over gas costs recovered in base rates) are deferred as regulatory assets. See Note 2.

RENEWABLE ENERGY STANDARDS (RES) AND RENEWABLE ENERGY CREDITS (RECs)

Arizona adopted a mandatory Renewable Energy Standard (RES) that requires TEP and UNS Electric to increase their use of renewable energy and allows recovery of RES compliance costs through a surcharge to customers. TEP and UNS Electric defer the difference between RES qualified costs when incurred and the recovery of such costs through the RES surcharge. When RES qualified costs incurred exceed the amount recovered through the RES surcharge, the deferred costs are reflected as a regulatory asset. When RES qualified costs incurred are less than the amount recovered through the RES surcharge, the deferred revenue is reflected as a regulatory liability.

The ACC uses Renewable Energy Credits (RECs) to measure compliance with the RES requirements. A REC equals one kWh generated from renewable resources. The cost of REC purchases are qualified renewable expenditures recoverable through the RES surcharge. When TEP or UNS Electric purchase renewable energy, the premium paid above conventional power is the REC cost, a qualified cost recoverable through the RES surcharge, and the remaining cost is recoverable through the PPFAC.

Also, when the RECs are purchased, TEP and UNS Electric record the cost of the RECs as an intangible asset, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. RECs are expensed to the income statement when the RECs are reported to the ACC for compliance with the RES requirements.

INCOME TAXES

Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We record a valuation allowance to reduce deferred tax assets when we believe it is more likely than not that the deferred asset will not be realized.

K-103

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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, assuming full knowledge of the position and all relevant facts. Interest Expense includes interest accrued by UniSource Energy and TEP on tax positions taken on tax returns which have not been reflected in the financial statements.

Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets — Noncurrent includes Income Taxes Recoverable Through Future Rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 2.

We account for Federal Energy Credits using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. This benefit is offset by the tax expense attributable to the reduction in tax basis required to be recognized. All other 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 taxes, 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.

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. TEP, UNS Gas and UNS Electric 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; ensuring the companies can meet their load and reserve requirements; and reducing 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.

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.

K-104

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Cash Flow Hedges

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the Springerville Common Facilities Lease and variable rate industrial development bonds. In addition, TEP hedges the cash flow risk associated with a six-year power supply agreement using a six-year power purchase swap agreement. 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 Accumulated Other Comprehensive Income (AOCI) and the ineffective portion, if any, is recognized in earnings; and

• 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 either cash flow hedge accounting treatment or 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, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC under terms of the 2008 TEP Rate Order.
	In 2008, TEP entered into energy-related derivatives for trading purposes. However, the net trading activities represented less than 1% of TEP’s revenue from wholesale sales in 2008. In 2009 and 2010, TEP had no trading activity.
•	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 cost of hedging contracts.
•	UNS Electric
	UNS Electric hedges a portion of its purchased power exposure to fixed price and natural gas-indexed contracts with forward power purchases, financial gas swaps, and call and put options. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the UNS Electric PPFAC mechanism allows recovery of the prudent costs of contracts for hedging fuel and purchased power costs.

K-105

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Normal Purchase and Normal Sale

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

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’s 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.

PENSION AND OTHER POSTRETIREMENT BENEFITS

TEP, UNS Gas and UNS Electric sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on employees’ years of service and average compensation. TEP, UNS Gas and UNS Electric also maintain a Supplemental Executive Retirement Plan for upper management. TEP also provides limited health care and life insurance benefits for retirees.

Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 9 for additional information on pension and other postretirement benefits.

SHARE-BASED COMPENSATION

UniSource Energy has a share-based long-term incentive plan. UniSource Energy grants awards to officers and directors on the grant-date at fair value of the award (with some limited exceptions). Generally, compensation costs are recognized over the service period (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 10.

RECLASSIFICATIONS

In an effort to more closely match GAAP taxonomies in extensible business reporting language, more commonly known as XBRL, UniSource Energy and TEP made the following balance sheet presentation changes from previously issued financial statements to conform to the current presentation:

• Accounts Receivable — Retail and Other, and Accounts Receivable Wholesale are no longer shown separately; instead they are reported as Accounts Receivable — Customer, or Accounts Receivable — Non-customers reported in Other Assets;

• Fuel Inventory is reported separately; previously, it was combined with Materials Inventory;

• Rather than being shown separately, all regulatory balances are reported in either Regulatory Assets — Current, Regulatory Assets — Noncurrent, Regulatory Liabilities - Current, or Regulatory Liabilities — Noncurrent;

• Accounts Payable and Accounts Payable — Purchased Power are reported in the aggregate as Accounts Payable — Trade; and

• Customer Advances for Construction are no longer shown separately; instead, they are reported as Other within Deferred Credits and Other Liabilities.

K-106

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

To be comparable with the 2010 presentation, UniSource Energy’s 2009 balance sheet incorporated immaterial reclassifications that mainly impacted Other Current Assets, Other Current Liabilities, Other Long-Term Liabilities and Regulatory Liabilities — Noncurrent. On the cash flow statement UniSource Energy and TEP now classify the Equity portion of AFUDC as an Operating cash outflow, and a gross reduction of Capital Expenditures. UniSource Energy also had immaterial reclassifications impacting Electric Wholesale Sales and Purchased Energy on its 2009 and 2008 income statements.

NOTE 2. REGULATORY MATTERS

ACCOUNTING FOR RATE REGULATION

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) regulate portions of TEP, UNS Gas, and UNS Electric utility accounting practices. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. The FERC regulates the terms and prices of transmission services and wholesale electricity sales, wholesale transport and purchases of natural gas.

TEP RATES AND REGULATION

1999 Settlement Agreement

We believe that the 1999 Settlement Agreement that established the rates TEP charged before the 2008 TEP Rate Order contemplated the use of market-based retail rates for generation service that would have been market-based beginning January 1, 2009. As part of the 2008 TEP Rate Order, TEP and other parties to the order relinquished all claims related to 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 Competition Transition Charge (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 that were amortized as an off-balance sheet regulatory asset through 2003. In 2008, TEP fully amortized the remaining $24 million Transition Recovery Asset balance, to the income statement as costs were fully recovered through rates.

By 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, provided 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.

K-107

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

On December 1, 2008, TEP implemented new depreciation rates that included a component for net negative salvage value for all generation assets except Luna and new depreciation rates for distribution and general plant assets that extended the depreciable lives of these assets.

Rates for generation service are based on a cost-of-service methodology. All generation assets acquired by TEP between December 31, 2006 and December 31, 2012 — from the end of test year used in TEP’s latest rate case filing through the end of the base rate freeze established by the 2008 TEP Rate Order — 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 Energy Facility is included in TEP’s original cost rate base at its net book value of $48 million as of December 31, 2006.

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

Impact of Reapplying Regulatory Accounting to TEP’s Generation Operations

As a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations in December 2008, producing the following adjustments:

	Income Statement
	(Gain)/Loss
	-Millions of Dollars-
Recorded in Fuel:
San Juan Coal Contract Amendment	$	(9	)
Retiree Health Care and Final Mine Reclamation Costs		(15	)
Unrealized Losses on Derivative Contracts (PPFAC)		(8	)
Deregulation Costs Recorded in O&M		(1	)
Property Taxes		(7	)
Pre-Tax Impact of Reapplying Regulatory Accounting	$	(40	)

K-108

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Income Statement Impact of Applying Regulatory Accounting

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

	Years Ended December 31,
	2010			2009			2008
	-Millions of Dollars-
Operating Revenues
Amortization of the Fixed CTC Revenue to be Refunded	$	(10	)	$	(12	)	$	—
Operating Expenses
Depreciation (related to Net Cost of Removal for Interim Retirements)		30			41			10
Deferral of PPFAC Costs		(23	)		(21	)		—
Amortization of 1999 Transition Recovery Asset		—			—			24
Other		4			13			—
Non-Operating Income/Expenses
Long-Term Debt (Amortization of Loss on Reacquired Debt Costs)		(1	)		—			1
AFUDC — Equity		(4	)		(4	)		(3	)
Income Taxes — Deferral		—			—			4
Offset by the Tax Effect of the Above Adjustments		2			(7	)		(14	)
Net (Decrease)/Increase to Net Income	$	(2	)	$	10		$	22

K-109

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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

	December 31,
	2010			2009
	-Millions of Dollars-
Regulatory Assets — Current
Property Tax Deferrals(1)	$	16		$	16
Deregulation Costs(2)		4			4
Other Current Regulatory Assets(5)		14			7
Total Regulatory Assets — Current		34			27
Regulatory Assets — Noncurrent
Pension and Other Postretirement Benefits(4)		90			80
Income Taxes Recoverable through Future Revenues(3)		18			18
PPFAC		41			—
PPFAC — Final Mine Reclamation and Retiree Health Care Costs(6)		17			15
Deregulation Costs(2)		3			7
Other Regulatory Assets(5)		14			17
Total Regulatory Assets — Noncurrent		183			137
Regulatory Liabilities — Current
PPFAC — Fixed CTC Revenue to be Refunded		(36	)		(9	)
RES(7)		(22	)		(17	)
Other Current Regulatory Liabilities		(1	)		(1	)
Total Regulatory Liabilities — Current		(59	)		(27	)
Regulatory Liabilities — Noncurrent
Net Cost of Removal for Interim Retirements(8)		(169	)		(162	)
PPFAC		—			20
PPFAC — Fixed CTC Revenue to be Refunded		—			(37	)
Other Regulatory Liabilities		(1	)		—
Total Regulatory Liabilities — Noncurrent		(170	)		(179	)
Total Net Regulatory Liabilities	$	(12	)	$	(42	)

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, rather than as costs are accrued. While these assets do not earn a return, the costs are fully recovered in rates over an approximately six-month period.
(2)	Deregulation costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders, the recovery of which was authorized by the ACC in the 2008 TEP Rate Order. These assets are included in rate base and consequently earn a return. TEP is recovering these costs through rates over a four-year period, beginning in December 2008.
(3)	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.
(4)	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 over the estimated service lives of employees. TEP does not earn a return on these assets.
(5)	Other assets includes unamortized loss on reacquired debt (recovery over next 21 years); coal contract amendment (recovery over next 8 years); and other assets (recovery by 2014). TEP does not earn a return on these assets.
(6)	Final Mine Reclamation and Retiree Health Care Costs stem from 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. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. 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.

K-110

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Regulatory liabilities represent items that TEP either 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:

(7)

RES tariff proceeds in excess of authorized renewable expenditures.

(8)

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.

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, 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 of 0.18 cents per kWh became effective on April 1, 2009, and is 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 of 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.

The PPFAC mechanism provides for the annual adjustment of retail rates to reflect variations in retail fuel and purchased power costs from the base power supply rate currently included in base rates. The current PPFAC rate of 0.09 cents per kWh, effective April 2010, includes a forward component credit of (0.08) cents and a true-up component of 0.17 cents.

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 to customers until the Fixed CTC revenue to be refunded is fully credited, which is expected to occur by the end of 2011.

The following table shows the changes in PPFAC related accounts and the impacts on revenue and expense for the year ended December 31, 2010:

	Assets (Liability) at						Year Ended
	December 31,						December 31, 2010
									Reduction to Fuel
							Impact on		and Purchased
	2010			2009			Revenue		Power Expense
	-Millions of Dollars-
PPFAC — Fixed CTC Revenue to be Refunded(current and noncurrent)	$	(36	)	$	(46	)	$	10
PPFAC(current and noncurrent)	$	58		$	35				$	23

K-111

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

UNS GAS RATES AND REGULATION

2010 UNS Gas Rate Order

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. Effective April 2010, the ACC approved a rate increase of 2% ($3 million), including an 8% return on original cost rate base.

UNS Gas has the following Regulatory Assets and Liabilities:

	December 31,			December 31,
	2010			2009
	-Millions of Dollars-
Current Assets
Derivative Instruments(1)	$	8		$	5
Other Regulatory Assets
Pension Assets(2)		2			2
Derivative Instruments(1)		2			3
Other Regulatory Assets(3)		1			1
Regulatory Liabilities
PGA — Over-Recovered Purchased Energy Costs		(10	)		(10	)
Net Cost of Removal for Interim Retirements(4)		(22	)		(21	)
Total Net Regulatory Assets (Liabilities)	$	(19	)	$	(20	)

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

(1)	Derivative instruments represent the unrealized gains or losses on hedge contracts that are expected to be recovered through the PGA. UNS Gas does not earn a return on these costs.
(2)	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 and expects to recover them in rates over the estimated service lives of its employees.
(3)	Other Regulatory Assets consist of UNS Gas’ 2007 and 2008 rate case costs, which are recoverable over 3 years and the costs of its low income assistance program. UNS Gas does not earn a return on these costs.

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

⁽⁴⁾ 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.

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Purchase Gas Adjustor (PGA) Mechanism

UNS Gas’ retail rates include a PGA mechanism that mitigates the volatility of natural gas prices while allowing UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor on a per-therm basis. The PGA mechanism includes the following two components:

(1) The PGA Factor reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceeding 12 months. The PGA Factor automatically adjusts monthly, but it is restricted from rising or falling more than $0.15 per therm in a twelve-month period. The cumulative difference between UNS Gas’ actual gas costs and those recovered through the PGA Factor are tracked through the PGA Bank, a balancing account.

(2) A PGA Surcharge or Surcredit can, upon approval by the ACC, be used to reduce the over- or under-collected balance in the PGA Bank over a certain period. UNS Gas is required to request such a credit if its PGA Bank balance reflects an overcollection of $10 million or more on a billed basis.

A PGA Surcredit of $0.04 cents per therm was applied to UNS Gas’ bills from October 2007 through April 2008. From May 2008 through October 2009, there was no surcharge or surcredit in effect. An $0.08 cent per therm PGA Surcredit was in place from November 2009 through October 2010. Since then, UNS Gas has not employed a PGA Surcharge or Surcredit. See table above for the total balance of Over-Recovered Purchased Energy Costs.

Income Statement Impact of Applying Regulatory Accounting

If UNS Gas had not applied regulatory accounting its net income would have been $1 million lower in 2010, and $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 as a reduction to its regulatory liability. Net income would have been $6 million higher in 2009 as UNS Gas could have recognized 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 recording them as a regulatory liability.

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.

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2010 UNS Electric Rate Order

In April 2009, UNS Electric filed a general rate case with the ACC (on a cost of service basis) requesting a rate increase of 7% to cover a revenue deficiency of $14 million. In September 2010, the ACC approved a rate increase of 4% ($7 million), including an 8% return on original cost rate base, effective October 1, 2010. The ACC approved new depreciation rates effective October 1, 2010, resulting in an expected $1 million annual reduction of depreciation expense.

The ACC rate order also authorized the purchase by UNS Electric of BMGS from UED at its net book value of approximately $62 million. Upon purchase of this facility, subject to FERC approval and other conditions BMGS will be placed into rate base through a revenue-neutral rate reclassification of approximately 0.7 cents per kWh from base power supply rate to the non-fuel base rate.

Regulatory Assets and Liabilities

UNS Electric’s regulatory assets and liabilities were as follows:

	December 31,			December 31,
	2010			2009
	-Millions of Dollars-
Current Regulatory Assets
Derivative Instruments(1)	$	12		$	9
PPFAC — Under-Recovered Purchased Power Costs(5)		2			—
Other Regulatory Assets
Derivative Instruments(1)		2			2
Pension Assets(2)		2			2
Other(3)		—			1
Current Regulatory Liabilities
PPFAC — Over-Recovered Purchased Power Costs(5)		—			(5	)
RES(4)		(1	)		—
Other Regulatory Liabilities
Net Cost of Removal for Interim Retirements(6)		(9	)		(12	)
Total Net Regulatory Assets (Liabilities)	$	8		$	(3	)

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

(1)	Derivative instruments represent the unrealized gains or losses on hedge contracts that are expected to be recovered through the PPFAC. UNS Electric does not earn a return on these costs.
(2)	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.
(3)	Other Regulatory Assets are not included in rate base and do not earn a return. The recovery period is 3 years.

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

⁽⁴⁾ RES tariff proceeds in excess of authorized renewable expenditures. The ACC approved a RES tariff for UNS Electric, effective June 1, 2008, to allow UNS Electric to recover the cost of authorized 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 authorized renewable expenditures will be reflected in the financial statements as a current regulatory liability. Conversely, authorized renewable expenditures in excess of the RES collected will be reflected as a current regulatory asset. The amount of the surcharge is reset annually and incorporates an adjustor mechanism that, upon approval of the ACC, allows UNS Electric to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s RES tariff.

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(5)	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 incorporates 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.
(6)	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.

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. The PPFAC passes along fuel and purchased power costs incurred to provide service to retail customers, including demand charges and prudent hedging costs.

The PPFAC mechanism has a forward component and a true-up component. The forward component reflects 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 to allow recovery of any difference in the subsequent PPFAC year. The PPFAC rate is updated on June 1 of each year, beginning June 1, 2009.

The chart below summarizes the PPFAC rates in cents per kWh for the prior three years:

	October 2010		June 2010 to			June 2009			June 2008		Prior to June
	to May 2011		September 2010			to May 2010			to May 2009		2008
Charge (Credit)		0.08		(0.28	)		(1.06	)		1.50		1.80
Base Rate		6.77		7.10			7.10			7.10		5.20

Income Statement Impact of Applying Regulatory Accounting

If UNS Electric had not applied regulatory accounting, net income would have been $7 million lower in 2010 and $16 million lower in 2008, as UNS Electric would have recognized higher purchased energy and unrealized losses on its commodity derivative instruments as an expense to its income statement, rather than as either regulatory assets or a reduction to its regulatory liabilities. If UNS Electric had not applied regulatory accounting, net income would have been $7 million higher in 2009 as UNS Electric would have recognized lower purchased power costs and unrealized gains on its commodity derivative instruments as a reduction to expense rather than recording an increase to regulatory liabilities.

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TEP, UNS Gas and UNS Electric RES and Energy Efficiency Standards (EE Standards)

The ACC has adopted a mandatory Renewable Energy Standard (RES) that requires TEP and UNS Electric to expand their use of renewable energy through efforts funded by customer surcharges. TEP and UNS Electric are required to file five-year implementation plans with the ACC and annually seek approval for the upcoming year’s RES funding amount. Similarly, TEP, UNS Gas and UNS Electric recover the cost of ACC-approved energy efficiency programs through Demand Side Management (DSM) surcharges established by the ACC.

The following table shows RES and DSM tariffs collected:

			UNS Electric				UNS Gas		UNS Electric
	TEP RES		RES		TEP DSM		DSM		DSM
	-Millions of Dollars-
2010	$	32	$	7	$	10	$	1	$	2
2009		29		5		7		1		1
2008		9		2		—		—		1

In May 2010, the ACC approved a funding mechanism for approximately $14 million of TEP-owned renewable energy projects. The mechanism allows TEP to use RES funds to recover operating costs, depreciation, property taxes and a return on its investment until the projects can be incorporated in TEP’s base rates. These projects were completed in 2010 and TEP began recovering their costs through the RES tariff in January 2011.

In August 2010, the ACC approved new Electric EE Standards designed to require TEP, UNS Electric and other affected electric utilities to implement cost effective DSM programs. In 2011, the EE Standards target total retail kWh savings equal to 1.25% of 2010 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail kWh sales of 22% by 2020. The EE Standards provide for the recovery of costs to implement the DSM programs.

In August 2010, the ACC approved new Gas EE Standards designed to require UNS Gas and other affected gas utilities to implement cost effective DSM programs. In 2011, the Gas EE Standards target total retail therm savings equal to 0.5% of 2010 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.

In September 2010, the ACC approved a proposal for UNS Electric to invest approximately $5 million in UNS Electric owned solar projects per year between 2011 and 2014. The plan allows UNS Electric to use RES funds to recover operating costs, depreciation, property taxes and provides UNS Electric with a return on its investment until these costs can be incorporated in UNS Electric’s base rates.

In December 2010, the ACC approved TEP’s 2011 RES implementation plan with the ACC. The plan includes a proposal for TEP to invest $28 million in TEP owned solar projects in 2011. The plan allows TEP to use RES funds to recover operating costs, depreciation, property taxes and provides TEP with a return on its investment until these costs can be incorporated in TEP’s base rates.

In December 2010, the ACC approved a policy statement regarding the need to adopt rate decoupling or another mechanism to make Arizona’s EE Standards viable.

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Future Implications of Discontinuing Application of Regulatory Accounting

TEP, UNS Gas and UNS Electric regularly assess whether they can continue to apply regulatory accounting to regulated operations, and concluded regulatory accounting is applicable. If TEP, UNS Gas and UNS Electric stopped applying regulatory accounting to their regulated operations the following would occur:

• Regulatory pension assets would be reflected in AOCI;

• We would write-off remaining regulatory assets as an expense and regulatory liabilities as income on the income statement;

• At December 31, 2010, based on the regulatory assets balances, net of regulatory liabilities,

o TEP would have recorded an extraordinary after-tax gain of $62 million and an after-tax loss in AOCI of $54 million;

o UNS Gas would have recorded an extraordinary after-tax gain of $13 million and an after-tax loss in AOCI of $1 million; and

o UNS Electric would have recorded an extraordinary after-tax loss of $4 million and an after-tax loss in AOCI of $1 million.

• While future regulatory orders and market conditions may affect cash flows, TEP, UNS Gas and UNS Electric’s cash flows would not be affected.

Renewable Energy Purchase Power Agreements

In 2010, UniSource Energy and TEP purchased $8 million and $7 million of RECs bundled with renewable energy and expensed $5 million and $5 million to purchased power, respectively. The cost of REC purchases are qualified renewable expenditures and are offset by customer collections through the RES tariff. At December 31, 2010, TEP had $2 million in RECs recorded as Other Assets on the balance sheet.

In 2009, TEP entered into three 20-year long-term purchase power agreements with companies developing renewable energy generation facilities. The ACC approved the agreements in April 2010. The facilities are expected to begin commercial operation during the next few years. Expected capacities range from 1.4 MW to 25 MW.

In 2010, TEP entered into similar long-term renewable energy contracts for approximately 96 MW of solar energy, 50 MW of wind energy and 2.2 MW of landfill gas. The ACC approved these agreements in August 2010. These facilities are also expected to begin commercial operation during the next few years.

In 2009, UNS Electric entered into a 20-year long-term purchase power agreement with a company developing a wind farm and solar generation facility near Kingman, Arizona. The ACC approved the agreement in April 2010. The facility is expected to begin commercial operation in 2011. UNS Electric is required to purchase the full output of the facility for 20 years.

TEP and UNS Electric are required to purchase the full output of each facility for 20 years. Both utilities are authorized to recover a portion of the cost of renewable energy through the PPFAC, with the balance of costs recoverable through the RES tariff.

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NOTE 3. SEGMENT AND RELATED INFORMATION

We have four 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; and

(4) Millennium has investments in unregulated businesses.

The UniSource Energy and UES holding companies and UED are included in Other.

Reconciling adjustments consist of the elimination of intersegment revenue resulting from the following transactions and they are eliminated in consolidation:

	Reportable Segments
			UNS
Intersegment Revenue	TEP		Gas		UNS Electric		Millennium		Other
	-Millions of Dollars-
2010:
Wholesale Sales — TEP to UNS Electric(4)	$	18	$	—	$	—	$	—	$	—
Wholesale Sales — UNS Electric to TEP(4)		—		—		2		—		—
Wholesale Sales — UED to UNS Electric		—		—		—		—		11
Wholesale Sales — UNS Gas to TEP(5)		—		1		—		—		—
Gas Revenue — UNS Gas to UNS Electric		—		5		—		—		—
Other Revenue — TEP to Affiliates(1)		8		—		—		—		—
Other Revenue — Millennium to TEP, UNS Electric, & UNS Gas(2)		—		—		—		17		—
Other Revenue — TEP to UNS Electric(3)		3		—		—		—		—
Total Intersegment Revenue	$	29	$	6	$	2	$	17	$	11
2009:
Wholesale Sales — TEP to UNS Electric(4)	$	23	$	—	$	—	$	—	$	—
Wholesale Sales — UNS Electric to TEP(4)		—		—		4		—		—
Wholesale Sales — UED to UNS Electric		—		—		—		—		12
Gas Revenue — UNS Gas to UNS Electric		—		5		—		—		—
Other Revenue — TEP to Affiliates(1)		8		—		—		—		—
Other Revenue — Millennium to TEP, UNS Electric, & UNS Gas(2)		—		—		—		16		—
Other Revenue — TEP to UNS Electric(3)		3		—		—		—		—
Total Intersegment Revenue	$	34	$	5	$	4	$	16	$	12
2008:
Wholesale Sales — TEP to UNS Electric(4)	$	24	$	—	$	—	$	—	$	—
Wholesale Sales — UNS Electric to TEP(4)		—		—		9		—		—
Wholesale Sales — UED to UNS Electric		—		—		—		—		7
Gas Revenue — UNS Gas to UNS Electric		—		8		—		—		—
Other Revenue — TEP to Affiliates(1)		8		—		—		—		—
Other Revenue — Millennium to TEP, UNS Electric & UNS Gas(2)		—		—		—		16		—
Other Revenue — TEP to UNS Electric(3)		2		—		—		—		—
Total Intersegment Revenue	$	34	$	8	$	9	$	16	$	7

(1)	Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
(2)	Millennium provides a supplemental workforce and meter reading services to TEP, UNS Gas and UNS Electric. Amounts are based on costs of services performed, and management believes that the charges for services are reasonable. Millennium charged TEP $16 million in 2010, $15 million in 2009 and $15 million in 2008 for these services.

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(3)	TEP charged UNS Electric for control area services based on a FERC approved tariff.
(4)	TEP and UNS Electric began selling power to each other in 2008 at prices based on the Dow Jones Four Corners Daily Index.
(5)	Starting in 2010, UNS Gas provided gas to TEP for generation of power based on third-party market quotes.

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. Direct costs charged by TEP to affiliates were $10 million in 2010, 2009 and 2008.

UniSource Energy incurs corporate costs that are allocated to TEP and its other subsidiaries. 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 would have incurred as a standalone entity. Charges allocated to TEP were $3 million in 2010, $2 million in 2009, and $4 million in 2008.

Other

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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

	Reportable Segments
				UNS			UNS									Reconciling			UniSource
	TEP			Gas			Electric			Millennium			Other			Adjustments			Energy
	-Millions of Dollars-
2010
Income Statement
Operating Revenues — External	$	1,096		$	144		$	214		$	1		$	—		$	(1	)	$	1,454
Operating Revenues — Intersegment		29			6			2			17			11			(65	)		—
Depreciation and Amortization		132			8			15			—			1			—			156
Interest Income		7			—			—			1			—			—			8
Net Loss from Equity Method Investments		—			—			—			(6	)		—			—			(6	)
Interest Expense		88			7			7			—			9			—			111
Income Tax Expense (Benefit)		61			6			7			6			(2	)		—			78
Net Income (Loss)		107			9			10			(13	)		(2	)		—			111
Cash Flow Statement
Capital Expenditures		(216	)		(10	)		(22	)		—			(17	)		—			(265	)
Balance Sheet
Total Assets		3,066			310			291			46			1,096			(1,030	)		3,779
2009
Income Statement
Operating Revenues — External	$	1,065		$	148		$	183		$	1		$	—		$	—		$	1,397
Operating Revenues — Intersegment		34			5			4			16			12			(71	)		—
Depreciation and Amortization		153			7			14			—			2			—			176
Interest Income		11			—			—			—			1			—			12
Net Gain from Equity Method Investments		—			—			—			5			—			—			5
Interest Expense		85			6			7			—			11			—			109
Income Tax Expense (Benefit)		55			5			4			2			(1	)		(1	)		64
Net Income (Loss)		89			7			6			2			—			—			104
Cash Flow Statement
Capital Expenditures		(232	)		(13	)		(28	)		—			(10	)		—			(283	)
Balance Sheet
Total Assets		2,914			307			273			62			1,045			(1,000	)		3,601
Equity Method Investments		—			—			—			7			—			—			7
2008
Income Statement
Operating Revenues — External	$	1,058		$	166		$	186		$	1		$	—		$	(1	)	$	1,410
Operating Revenues — Intersegment		34			8			9			16			7			(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 Investments		—			—			—			(2	)		—			—			(2	)
Interest Expense		97			7			7			—			10			(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		(292	)		(16	)		(30	)		—			(16	)		—			(354	)
Balance Sheet
Total Assets		2,842			294			285			62			999			(972	)		3,510
Equity Method Investments		—			—			—			25			—			—			25

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

NOTE 4. COMMITMENTS AND CONTINGENCIES

TEP COMMITMENTS

Firm Purchase Commitments

At December 31, 2010, TEP had various firm non-cancelable purchase commitments and operating leases as described in the table below:

	Purchase Commitments
	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Fuel (including Transportation)	$	52	$	42	$	36	$	35	$	35	$	104	$	304
Purchased Power		26		15		8		4		—		—		53
Transmission		2		2		2		2		2		10		20
Total Unrecognized Firm Commitments	$	80	$	59	$	46	$	41	$	37	$	114	$	377

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 2012 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. 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 2011 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, 2010.

Starting January 1, 2009, fuel, purchased power and transmission costs are recoverable from customers through a PPFAC.

Renewable Energy Purchase Power Agreements and Projects

TEP entered into various forward power purchase agreements with developing renewable energy generation facilities to meet compliance requirements under the RES tariff. The facilities are expected to begin commercial operation in the next few years. Additionally, TEP entered into contracts to develop TEP owned renewable energy projects for $14 million of which $1 million remained an outstanding commitment at December 31, 2010. See Note 2 for additional information on RES related contracts.

Take-Or-Pay Accrual for Coal Transportation Agreement

TEP is obligated under a coal transportation agreement to transport 75,000 tons of coal to Tucson from specified sources or pay approximately $1 million per year through December 2015. In 2010, TEP satisfied the contract terms for the period. However, due to a mine closure and the inability to obtain suitable coal from alternative transportation points during the remaining term of the transportation agreement, TEP recognized a liability of $4 million in December 2010 for the minimum take-or-pay obligation to be paid in the future. TEP expects to recover the take-or-pay charges through the PPFAC as annual payments are made. Therefore, TEP recorded the $4 million as a regulatory asset. See Note 2.

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Operating Leases

TEP’s aggregate existing operating lease expense is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates. This expense totaled $1 million in each of 2010, 2009 and 2008. TEP’s estimated future minimum payments under existing non-cancelable operating leases are less than $1 million per year for 2011 and thereafter.

UNS GAS and UNS ELECTRIC COMMITMENTS

At December 31, 2010, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in the table below:

	Purchase Commitments
	2011	2012	2013	2014	2015	Thereafter	Total
	-Millions of Dollars-
Total Unrecognized Firm Commitments — Fuel	$25	$10	$5	$4	$3	$19	$66

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 market prices of fuel) is mitigated through the use of the PGA, which provides for the pass-through of actual commodity costs to customers. UNS Gas’ forward gas purchase agreements expire through 2015. Certain of these contracts are at a fixed price per mmbtu 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, 2010. 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, 2010, UNS Electric had various firm non-cancelable purchase commitments as described in the table below:

	Purchase Commitments
	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Purchased Power	$	47	$	33	$	35	$	—	$	—	$	—	$	115
Transmission		2		2		2		2		2		—		10
Total Unrecognized Firm Commitments	$	49	$	35	$	37	$	2	$	2	$	—	$	125

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, 2010. UNS Electric also entered into a forward power purchase agreement with the developer of renewable energy generation facilities to meet compliance requirements under the RES program. The facilities are expected to begin commercial operation in 2011. See Note 2 for additional information on RES related contracts.

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.

Additionally, UNS Gas’ and UNS Electric’s combined operating lease expense primarily for office facilities and computer equipment, with varying terms, and expiration dates was $1 million in each of the years 2010, 2009, and 2008. UNS Gas’ and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are approximately $1 million per year for 2011 and $2 million thereafter.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

UNISOURCE ENERGY COMMITMENTS

In 2009, UniSource Energy purchased land to construct a new headquarters building in downtown Tucson. In April 2010, UniSource Energy signed a design-build contract committing to a payment of $54 million for the first and second phases of the construction project; $32 million of that commitment remained outstanding at December 31, 2010. UniSource Energy expects the building to be completed in November 2011.

ENVIRONMENTAL REGULATION

TEP’s generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $18 million in 2010, $24 million in 2009 and $73 million in 2008 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan Generating Station (San Juan) described below. TEP expects to capitalize environmental compliance costs of $38 million in 2011 and $87 million in 2012. In addition, TEP recorded operating expenses of $14 million in 2010, $13 million in 2009 and $14 million in 2008 related to environmental compliance. TEP expects environmental expenses to be $10 million in 2011.

As a result of a 2005 settlement agreement among 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. The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan. In 2008, TEP’s share of stipulated penalties at San Juan was $1 million. TEP cannot deduct these penalties for income tax purposes. TEP did not incur any stipulated penalties at San Juan in 2009 or 2010. 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 for San Juan Unit 2.

TEP has sufficient emission allowances to comply with the Acid Rain 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.

TEP CONTINGENCIES

El Paso Electric Transmission

In 2006, El Paso filed a complaint with 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. In November 2008, the FERC issued an order supporting TEP’s position.

In December 2008, pending resolution, El Paso refunded to TEP $10 million paid for transmission service from Luna to TEP’s system during the period 2006 to 2008 plus interest of $1 million. TEP is not currently paying or accruing for transmission service under El Paso’s OATT.

In July 2010, the FERC issued an order denying El Paso’s request for rehearing of FERC’s November 2008 order. Also in July 2010, El Paso filed an appeal in the United States Court of Appeals for the District of Columbia Circuit. TEP intervened in the appeal proceeding. TEP has not recognized income as a result of the July 2010 FERC decision. In January 2011, in response to a joint motion filed by El Paso and the FERC, the Court ordered the appeal proceeding to be held in abeyance to allow TEP and El Paso time to continue settlement negotiations in this matter.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

If El Paso were to prevail in its appeal, TEP would be required to pay for transmission service under El Paso’s OATT from October 2008 through the date of the decision. For the period October 2008 to December 31, 2010, this additional transmission expense would approximate $10 million. However, under the PPFAC mechanism, TEP would be allowed to recover $8 million of this additional transmission expense from its retail customers.

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 Public Service Company of New Mexico (PNM) for transmission service in an attempt to mitigate TEP’s damages before FERC issued its decision in November 2008. In September 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 matters.

Claims Related to Navajo Generating Station

In June 1999, the Navajo Nation filed suit against SRP; several Peabody Coal Company entities including Peabody Western Coal Company (Peabody), the coal supplier to Navajo Generating Station (Navajo); Southern California Edison Company; and other defendants in the U.S. District Court for the District of Columbia (D.C. Lawsuit). Although TEP is not a named defendant in the D.C. Lawsuit, TEP owns 7.5% of Navajo Units 1, 2 and 3. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate on 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, 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 District Court dismissed all claims against SRP. In March 2008, the District Court lifted a stay that had been in place since October 2004 and referred pending discovery related motions to a magistrate judge. In January 2010, the District Court extended the discovery deadline and set other procedural deadlines at various dates between March 2010 and February 2011. In April 2010, the Navajo Nation filed a Second Amended Complaint. In September 2010, the case was referred to the District Court’s mediation program to assist with settlement negotiations.

In 2004, Peabody filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP, for reimbursement of royalties and other costs 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 Generating Station

In April 2010, the Sierra Club filed a citizens suit under the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA) in the U.S. District Court for the District of New Mexico against PNM, as operator of San Juan; PNM’s parent PNM Resources, Inc. (PNMR); San Juan Coal Company (SJCC), which operates the San Juan mine that supplies coal to San Juan; and SJCC’s parent BHP Minerals International Inc. (BHP). The Sierra Club alleges in the suit that certain activities at San Juan and the San Juan mine associated with the treatment, storage and disposal of coal and coal combustion residuals (CCRs), primarily coal ash, are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCRs at the mine constitute “open dumping” in violation of RCRA. The RCRA claims are asserted against PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA which are directed only against SJCC and BHP. The suit seeks the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCRs at the mine or to cease placement of CCRs at the mine; the imposition of civil penalties; and, attorney’s fees and costs. With the agreement of the parties, the court entered a stay of the action in August 2010 to allow the parties to try to address Sierra Club’s concerns. If the parties are unable to settle the matter, PNM has indicated that it plans an aggressive defense of the RCRA claims in the suit. TEP cannot predict the outcome of this matter at this time.

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SJCC, 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 that supplies coal to San Juan. 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 SJCC’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. SJCC 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 plugging and abandoning 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.

TEP owns 50% of San Juan Units 1 and 2, which represents approximately 20% of the total generation capacity of the entire San Juan Generation Station, and is liable for its share of any resulting liabilities.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP currently pays ongoing reclamation costs related to the coal mines that supply the generating stations in which TEP has an ownership interest but does not operate. It is probable that TEP will have to pay a portion of final reclamation costs upon closure of these mines. TEP’s share of the reclamation costs at the expiration dates of the coal supply agreements in 2016 through 2019 is approximately $26 million. TEP recognizes this liability over the remaining terms of the coal supply agreements and had recorded liabilities of $11 million at December 31, 2010 and $10 million at December 31, 2009.

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’s PPFAC allows TEP to pass-through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset. TEP will increase the regulatory asset and the reclamation 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

California Energy Market Issues

In December 2009, based on renewed settlement discussions with parties involved in various legal proceedings related to the California energy crisis, TEP wrote off its remaining accounts receivable balance of $2 million and accrued an additional liability of $2 million.

In March 2010, TEP and the California Attorney General, California Public Utilities Commission and various private entities (collectively California Parties) reached a settlement in principal of all remaining claims against TEP related to TEP’s transactions in the Western energy markets including the California Power Exchange and the California Independent System Operator during the California energy crisis of 2000 and 2001. As a result of this settlement, TEP recognized an additional liability of $4 million in March 2010, bringing TEP’s gross liability related to these claims to $6 million.

In April 2010, TEP and the California Parties entered into a written settlement agreement that FERC approved in June 2010 TEP paid the resulting liability in July 2010. Also, in association with the California Parties settlement, TEP recorded a receivable from SRP in March 2010 for approximately $1 million, that has since been settled, related to a long-term power sale agreement between TEP and SRP. The net $3 million is shown as California Power Exchange (CPX) Provision for Wholesale Refunds on TEP’s income statement. In addition, in March 2010, UNS Electric reached a related settlement with Arizona Public Service Company (APS) and recorded Other Income of $3 million that has since been received in cash. The settlements described above offset and had no net impact on UniSource Energy’s consolidated results of operations in 2010.

Regional Haze Rules

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 rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA.

San Juan

In December 2010, the EPA proposed a federal implementation plan under the Clean Air Act, addressing, among other things, regional haze requirements for San Juan. The EPA plan proposes that the BART for nitrogen oxides at San Juan is a technology known as “selective catalytic reduction” (SCR). EPA’s proposal would give the San Juan participants three years from the date of the final rule to achieve compliance. A final federal implementation plan is expected in 2011.

In June 2010, the New Mexico Environment Department (NMED) filed its proposed implementation plan for regional haze with the New Mexico Environmental Improvement Board. That plan also identified SCRs as the BART for nitrogen oxides at San Juan. However, the NMED’s plan also required a technology known as sorbent injection, and it gave the San Juan participants five years to achieve compliance. The NMED withdrew its proposed implementation plan after the EPA filed its proposal.

PNM, the operator at San Juan, has concluded that SCR is not the BART and has indicated it intends to vigorously challenge the EPA’s proposal.

TEP’s share of capital expenditures related to the installation of SCRs is estimated to be $202 million. This estimate is based on a 2010 cost analysis of the installation of SCR technology over five years. The three-year installation proposed by the EPA could increase the cost of compliance. Adding this technology to San Juan would also increase operating costs at the generating station.

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Four Corners

In October 2010, EPA issued a proposed federal implementation plan (FIP) for BART at the Four Corners, which was supplemented in February 2011. The revised FIP, if approved, would require the installation of SCRs on units 4 and 5. TEP’s estimated share of capital expenditures related to the installation of SCRs for units 4 and 5 is approximately $35 million. Once the EPA finalizes the BART rule for Four Corners, the Four Corners participants would have until 2018 to achieve compliance.

Navajo

SRP, on behalf of the owners, is currently participating in an EPA sanctioned stakeholder process designed to determine BART for Navajo. If SCR is determined by the EPA to be the BART at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCRs at Navajo could result in an increase in the level of particulate emissions from the plant requiring the installation of baghouses. TEP’s estimated share of capital expenditures related to the installation of baghouses at Navajo is $43 million. The exact level and cost of necessary pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes the BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.

The San Juan, 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 facilities.

TEP cannot predict the ultimate outcome of these matters.

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 the reliability of electric service in Nogales. That order was issued before UniSource Energy purchased the electric system in Nogales and surrounding Santa Cruz County from Citizens Utilities in August 2003.

In 2002, the ACC approved the location and construction of the proposed 345-kV line along a route identified as the Western Corridor subject to a number of conditions, including the issuance of all required permits from state and federal agencies. The U.S. Forest Service subsequently expressed its preference for a different route in its final Environmental Impact Statement for the project. TEP and UNS Electric are 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 U.S. Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and Water Commission. As of December 31, 2010 and December 31, 2009, TEP had capitalized $11 million related to the project, including $2 million to secure 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.

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 standalone basis. The most significant of these guarantees are:

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

• UES’ guarantee of the $100 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 $30 million of outstanding loans under the UED Secured Term Loan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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

In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4. TEP indemnified the seller of Sundt Unit 4 from any sales or use taxes, transfer fees or other such costs relating to the purchase. The terms of the indemnification do not include a limit on potential future payments; however, TEP believes that the parties to the agreement have abided by all tax laws and that TEP does not have any additional tax obligations. TEP has not made any payments under the terms of this indemnification to date.

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, 2010
	- Millions of Dollars -
					UNS				UniSource
	TEP		UNS Gas		Electric		UED		Energy
Plant in Service:
Electric Generation Plant	$	1,709	$	—	$	18	$	60	$	1,787
Electric Transmission Plant		705		—		31		5		741
Electric Distribution Plant		1,168		—		200		—		1,368
Gas Distribution Plant		—		224		—		—		224
Gas Transmission Plant		—		18		—		—		18
General Plant		187		16		12		—		215
Intangible Plant		90		1		4		—		95
Electric Plant Held for Future Use		4		—		1		—		5
Total Plant in Service	$	3,863	$	259	$	266	$	65	$	4,453
Utility Plant under Capital Leases	$	582	$	—	$	1	$	—	$	583

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

	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
Intangible Plant		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

TEP’s unamortized computer software costs included in Intangible Plant above were $33 million as of December 31, 2010 and $31 million as of December 31, 2009. UNS Gas and UNS Electric had unamortized computer software costs of less than $1 million at both December 31, 2010 and December 31, 2009.

UniSource Energy’s total plant includes $65 million of non-regulated plant in service for 2010 and 2009, with $4 million of accumulated depreciation in 2010 and $3 million in 2009. Rates for utility operations appearing in this table, excluding those owned by UED, are set by the ACC or FERC on a cost-of-service basis, and they are accounted for under the provisions of regulatory accounting for all periods.

TEP Utility Plant under Capital Leases

All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term as described in Note 6. In April 2010 TEP terminated the capital lease of Sundt Unit 4 and purchased the related leased assets. At December 31, 2010, the utility plant under capital leases includes Springerville Common Facilities, Springerville Unit 1, and Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases.

	Years Ended December 31,
	2010		2009		2008
	-Millions of Dollars-
Lease Expense:
Interest Expense — Included in:
Capital Leases	$	47	$	49	$	52
Operating Expenses — Fuel		4		4		5
Other Expense		2		1		—
Amortization of Capital Lease Assets — Included in:
Operating Expenses — Fuel		3		2		4
Operating Expenses — Depreciation and Amortization		14		26		21
Total Lease Expense	$	70	$	82	$	82

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The depreciable lives as of December 31, 2010 were as follows:

			UNS Gas,
			UNS Electric
Major Class of Utility Plant in Service	TEP		& UED
Electric Generation Plant	6-59 years		38-49 years
Electric Transmission Plant	20-60 years		20-50 years
Electric Distribution Plant	28-60 years		23-50 years
Gas Distribution Plant		n/a	30-55 years
Gas Transmission Plant		n/a	30-65 years
General Plant	5-31 years		5-40 years
Intangible Plant	3-18 years		5-32 years

SeeTEP Utility Plantin Note 1 andTEP Capital Lease Obligationsin Note 6.

JOINTLY-OWNED FACILITIES

At December 31, 2010, 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	%	$	419	$	8	$	219
Navajo Station Units 1, 2 and 3		7.5			121		6		84
Four Corners Units 4 and 5		7.0			95		1		69
Transmission Facilities		7.5 to 95.0			280		12		178
Luna Energy Facility		33.3			51		1		1
Total				$	966	$	28	$	551

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’s 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 in 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 28.1 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $35.59 per share of our Common Stock, subject to adjustment in certain circumstances.

Beginning on March 5, 2010, UniSource Energy has 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 of 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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TEP DEBT

Variable Rate Tax-Exempt Bonds (IDBs)

At December 31, 2010, TEP had $365 million in tax-exempt variable rate debt outstanding; at December 31, 2009, it had $459 million of such debt outstanding. Each series of bonds is supported by a letter of credit issued under the TEP Credit Agreement or separate TEP Letter of Credit or Reimbursement Agreements. The letters of credit are secured by mortgage bonds issued under TEP’s 1992 Mortgage.

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 2010 Coconino A Bonds and 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 0.26% in 2010 and 0.41% in 2009. The average weekly interest rate ranged from 0.17% to 0.39% in 2010 and 0.25% to 0.79% during 2009. In addition to the variable interest rate, TEP pays a letter of credit fee, a letter of credit fronting fee to the issuing bank and a remarketing fee on each series of bonds. As of December 31, 2010, the letter of credit fees payable ranged from 1.50% to 1.875%, the LOC fronting fees ranged from 0.20% to 0.25% and the remarketing fees averaged 7 basis points.

In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate IDBs to a fixed rate of 2.4% from September 2009 to September 2014.

2010 Coconino Series A Bonds

In December 2010, the Coconino County, Arizona Pollution Control Corporation (Coconino PCC) issued $37 million of tax-exempt pollution control revenue bonds (2010 Coconino A Bonds) for TEP’s benefit. The 2010 Coconino A Bonds are supported by a letter of credit (LOC) issued under the TEP Reimbursement Agreement. The LOC is secured by $37 million of 1992 Mortgage Bonds and expires December 14, 2014. The bonds accrue interest at a variable weekly rate and are due October 2032. These bonds are multi-modal bonds that are callable at any time, at par plus accrued interest, to change the interest feature of the bonds. Additionally, the bonds are subject to mandatory redemption under certain circumstances if the LOC is not extended. The average interest rate on TEP’s 2010 Coconino A Bonds was 0.38% in 2010. The proceeds were deposited with a trustee and were used on December 30, 2010 to redeem a corresponding principal amount of bonds previously issued by PCC for TEP’s benefit.

TEP capitalized less than $1 million in costs related to the issuance of these bonds and will amortize the costs through October 2032, the term of the bonds.

2010 Pima Series A Bonds Issuance

In October 2010, the Industrial Development Authority of Pima County (Pima Authority) issued $100 million of its 2010 Series A tax-exempt IDBs for TEP’s benefit. The 2010 Pima Series A IDBs are unsecured, bear interest at a rate of 5.25%, mature in October 2040, and are callable at par on or after October 1, 2020. Net of an underwriting discount, $99 million of proceeds were deposited in a construction fund with the bond trustee. The proceeds were applied to the construction of certain of TEP’s transmission and distribution facilities used to provide electric service in Pima County. TEP drew down $88 million of the proceeds from the construction fund by December 31, 2010, with the remaining $11 million expected to be drawn down by the end of the first quarter of 2011.

TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs through October 2040, the term of the bonds.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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 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 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. 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. 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.

In January 2010, TEP converted the interest on the $130 million of 2008 Pima B Bonds from a variable rate to a fixed rate. The Pima B Bonds were reoffered in January 2010, with a term rate of 5.75% through maturity in September 2029. Interest is payable semi-annually beginning June 1, 2010. The bonds are callable at par beginning January 2015. Accordingly, the associated letter of credit which supported the 2008 variable rate Pima B Bonds was terminated in January 2010, and the TEP mortgage bonds which collateralized the letter of credit were cancelled.

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 September 2029.

TEP Term Loan Borrowing

In March 2010, TEP entered into an 18-month, $30 million term loan facility. In October 2010, TEP repaid the term loan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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, 2010.

TEP CAPITAL LEASE OBLIGATIONS

Sundt Unit 4

In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4 from the owner participants for $52 million. In April 2010, TEP paid the final outstanding Sundt Unit 4 lease obligation of $5 million to terminate the lease and reclassified the capital lease asset and the related leasehold improvements to plant in service. TEP is depreciating the asset over its best estimate of remaining plant life at the time of purchase which is 25 years.

Springerville Leases

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.

TEP agreed with the owners of Springerville Units 3 and 4 that, prior to expiration of the Springerville Coal Handling Facilities and Common Leases, TEP will either renew these leases or 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 at 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 2011, through scheduled lease payments, TEP reduced its capital lease obligations by $63 million.

Investments in Springerville Lease Debt and Equity

In March 2009, TEP purchased $31 million of Springerville Unit 1 lease debt. That price 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 $67 million at December 31, 2010 and $88 million at December 31, 2009. TEP also held an undivided equity ownership interest in the Springerville Unit 1 lease totaling $37 million at both of December 31, 2010 and December 31, 2009. TEP held an investment in Springerville Coal Handling Facilities lease debt totaling $1 million at December 31, 2010 and $7 million at December 31, 2009. In January 2011, TEP received the final maturity payment of $1 million on the investment in Springerville Coal Handling Facilities debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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% at each of December 31, 2010 and December 31, 2009. The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

				LIBOR
Outstanding at December 31, 2010	Fixed Ratio			Spread
$35 million		5.77	%		1.625	%
$22 million		3.18	%		1.625	%
$7 million		3.32	%		1.625	%

These interest rate swaps have been recorded by TEP as a cash flow hedge for financial reporting purposes. See Note 16.

UNS ELECTRIC SENIOR UNSECURED 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. 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.

UNS Electric’s long-term debt contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments and incurrence of indebtedness.

UNS GAS SENIOR UNSECURED NOTES

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’ long-term debt contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments and incurrence of indebtedness.

UNISOURCE ENERGY CREDIT AGREEMENT

In November 2010, UniSource Energy amended and restated its existing credit agreement. The UniSource Energy Credit Agreement previously included a $30 million term loan facility and a $70 million revolving credit facility. As amended, the UniSource Energy Credit Agreement consists of a $125 million revolving credit facility and revolving letter of credit facility that expire in November 2014. UniSource Energy’s obligations under the UniSource Energy Credit Agreement are secured by a pledge of the capital stock of Millennium, UES and UED. UniSource Energy capitalized $1 million of costs related to the credit agreement amendment and will amortize these costs over the term of the agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

At December 31, 2010 the following balances were outstanding:

	Current		Long-Term					Current		Long-
	Liabilities		Debt		Total			Liabilities		Term Debt		Total
	- Millions of Dollars-
	December 31, 2010							December 31, 2009
Revolver	$	—	$	27	$	27		$	—	$	31	$	31
Term Loan	$	—	$	—	$	—		$	6	$	3	$	9
Weighted Average Interest Rate on the Revolver and Term Loan		—		—		3.26	%		—		—		1.48	%

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 15, 2011, outstanding borrowings under the UniSource Energy Credit Agreement were $31 million.

Interest rates and fees under the UniSource Credit Agreement are based on a pricing grid tied to UniSource Energy’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 3.0% for Eurodollar loans or Alternate Base Rate plus 2.0% for Alternate Base Rate loans.

The UniSource Credit Agreement contains a number of covenants which restrict UniSource Energy and its subsidiaries, including restrictions on additional indebtedness, liens, mergers and sales of assets. The UniSource Credit Agreement also requires UniSource Energy to meet a minimum cash flow to interest coverage ratio determined on a UniSource Energy standalone basis and not to exceed a maximum leverage ratio determined on a consolidated basis. Under terms of the UniSource Credit Agreement, UniSource Energy may pay dividends so long as it maintains compliance with the agreement.

TEP CREDIT AGREEMENT

In November 2010, TEP amended and restated its existing credit agreement. The TEP Credit Agreement had previously included a $150 million revolving credit facility and a $341 million letter of credit facility to support $329 million aggregate principal amount of tax-exempt variable rate bonds. As amended, the TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $341 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2014 and is secured by $541 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. TEP capitalized $4 million of costs related to the credit agreement amendment and will amortize these costs through the term of the agreement.

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.875% for Eurodollar loans or Alternate Base Rate plus 0.875% for Alternate Base Rate loans. The margin rate currently in effect on the $341 million letter of credit facility is 1.875%.

The TEP Credit Agreement contains a number of covenants which restrict TEP and its subsidiaries, including restrictions on liens, mergers and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. Under the terms of the TEP Credit Agreement, TEP may pay dividends to UniSource Energy so long as it maintains compliance with the agreement.

As of December 31, 2010, TEP had $1 million outstanding in letters of credit under its revolving credit facility. As of December 31, 2009, TEP had $35 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility. The revolving loan balance was 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 15, 2011, TEP had $35 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)

TEP REIMBURSEMENT AGREEMENT

In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million letter of credit was issued pursuant to the 2010 TEP Reimbursement Agreement. The letter of credit supports $37 million aggregate principal amount of variable rate tax-exempt IDBs that were issued on behalf of TEP in December 2010 (See 2010 Coconino Series A Bonds above).

The 2010 TEP Reimbursement Agreement is secured by $37 million of mortgage bonds issued under TEP’s 1992 Mortgage. Fees are payable on the aggregate outstanding amount of the letter of credit at a rate of 1.50% per annum.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above.

UNS GAS/UNS ELECTRIC CREDIT AGREEMENT

In November 2010, UNS Gas and UNS Electric amended and restated their existing unsecured credit agreement. The UNS Gas/UNS Electric Credit Agreement had previously consisted of a $60 million revolving credit facility. As amended, the UNS Gas/UNS Electric Credit Agreement consists of a $100 million revolving credit and revolving letter of credit facility, and expires November 2014. The maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. UNS Gas and UNS Electric are each liable for only their own individual 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 capitalized $1 million of costs related to the credit agreement amendment and will amortize these costs through the term of the agreement.

Interest rates and fees under the UNS Electric/UNS Gas Credit Agreement are based on a pricing grid tied to the Borrower’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 2.5% for Eurodollar loans or Alternate Base Rate plus 1.5% for Alternate Base Rate loans.

The UNS Electric/UNS Gas Credit Agreement contains a number of covenants which restrict the Borrowers and UES, including restrictions on additional indebtedness, liens and mergers. The UNS Electric/UNS Gas Credit Agreement also requires each Borrower not to exceed a maximum leverage ratio. Under the terms of the UNS Electric/UNS Gas Credit Agreement, the Borrowers may pay dividends so long as they maintain compliance with the agreement.

UNS Electric had $13 million and $11 million in outstanding letters of credit under the UNS Gas/UNS Electric Revolver as of December 31, 2010 and December 31, 2009, respectively, which are not shown on the balance sheet.

UED SECURED TERM LOAN

In March 2009, UED entered into a 364-day, $30 million variable rate senior secured term loan facility. UED paid $1 million in debt issuance costs which were amortized to interest expense over the one year term of the loan. In February 2010, UED amended its senior secured term loan facility to extend the termination date by two years to March 2012, and to increase borrowings by $9 million bringing the outstanding balance to $35 million. UED capitalized less than $1 million in costs related to the transaction. The loan is guaranteed by UniSource Energy and is secured by a lien on substantially all the assets of UED, including the BMGS and an assignment of UED’s PPA with UNS Electric.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Other

As of December 31, 2010, UniSource Energy and its subsidiaries were in compliance with the terms of their respective loan, note purchase and credit agreements.

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(1)		Retirements		Obligations			Total			Gas		Electric		UED)		Total
	- Millions of Dollars -
2011	$	—	$	—	$	107		$	107		$	50	$	—	$	7	$	164
2012		—		—		118			118			—		—		23		141
2013		—		—		122			122			—		—		—		122
2014		365		—		195			560			—		—		27		587
2015		—		—		24			24			50		50		—		124
Total 2011 — 2015		365		—		566			931			100		50		57		1,138
Thereafter		—		638		79			717			—		50		150		917
Less: Imputed Interest		—		—		(156	)		(156	)		—		—		—		(156	)
Total	$	365	$	638	$	489		$	1,492		$	100	$	100	$	207	$	1,899

⁽¹⁾ TEP’s Variable Rate IDBs are backed by a $341 million LOC issued pursuant to TEP’s Credit Agreement which expires in November 2014 and TEP’s $37 million Reimbursement Agreement which expires December 2014. Although the Variable Rate IDBs mature between 2018 and 2032, the above table reflects a redemption or repurchase of such bonds in 2014 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.

NOTE 7. 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. Because UNS and each of its subsidiaries were in compliance with debt covenants at December 31, 2010, there were no dividend restrictions from the debt covenants.

In February 2011, UniSource Energy declared a first quarter dividend to shareholders of $0.42 per share of UniSource Energy Common Stock. The dividend, totaling approximately $15 million, will be paid on March 23, 2011 to common shareholders of record as of March 11, 2011. In 2010, UniSource Energy paid quarterly dividends to the shareholders of $0.39 per share, for a total of $1.56 per share, or $57 million for the year. 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.

In 2008, UniSource Energy’s $34 million dividend to shareholders 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.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

TEP

TEP paid dividends to UniSource Energy of $60 million in both 2010 and 2009, and $3 million in 2008. 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. The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP’s 2010, 2009, and 2008 dividends were paid from current year earnings.

UniSource Energy contributed capital to TEP of $15 million in 2010 and $30 million in 2009.

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. In April 2010, UNS Gas paid dividends of $10 million to UES, UES then paid dividends of $10 million to UniSource Energy. UES did not pay any dividends to UniSource Energy in 2009 or 2008.

UES made capital contributions to UNS Electric of less than $0.5 million in 2008.

Millennium and UED

Millennium paid dividends of $8 million to UniSource Energy in 2010, $3 million in 2009, and $25 million in 2008, 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 a return of capital distribution; and $0.5 million in 2008. Millennium and UED have no dividend restrictions.

In December 2008, UniSource Energy contributed $59 million in capital to UED by canceling an intercompany promissory note in the amount of $59 million.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

NOTE 8. INCOME TAXES

A reconciliation of the federal statutory income tax rate to each company’s effective income tax rate follows:

	UniSource Energy									TEP
	Years Ended December 31,
	2010			2009			2008			2010			2009			2008
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	66		$	59		$	11		$	58		$	51		$	5
State Income Tax Expense, Net of Federal Benefit		9			7			1			8			6			1
Deferred Tax Asset Valuation Allowance		8			—			—			—			—			—
Deferred Tax Asset Write-Off Related to Unregulated Investment		3			—			—			—			—			—
Depreciation Differences (Flow Through Basis)		—			1			2			—			1			2
San Juan Generating Station Environmental Penalties		—			—			3			—			—			3
Domestic Production Deduction		(3	)		(1	)		—			(3	)		(1	)		—
Federal/State Tax Credits		(2	)		(1	)		(3	)		(2	)		(1	)		(3	)
Other		(3	)		(1	)		3			—			(1	)		3
Total Federal and State Income Tax Expense	$	78		$	64		$	17		$	61		$	55		$	11
Effective Tax Rate		41	%		38	%		55	%		36	%		38	%		71	%

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.

In 2010, UniSource Energy recorded a $3 million out-of-period income tax expense. The out-of-period expense related to the write-off of a previously recorded deferred tax asset associated with the excess of tax over book basis difference in a consolidated unregulated investment. Management concluded that this out-of-period adjustment was not material to the current and prior period financial statements.

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

	UniSource Energy								TEP
	Years Ended December 31,
	2010			2009		2008			2010			2009		2008
	-Millions of Dollars-
Current Tax Expense (Benefit)
Federal	$	34		$	5	$	(17	)	$	28		$	7	$	(12	)
State		7			—		(2	)		7			1		(1	)
Total		41			5		(19	)		35			8		(13	)
Deferred Tax Expense (Benefit)
Federal		33			48		34			24			38		23
Federal Investment Tax Credits		(1	)		—		—			(1	)		—		—
State		5			11		2			3			9		1
Total		37			59		36			26			47		24
Total Federal and State Income Tax Expense	$	78		$	64	$	17		$	61		$	55	$	11

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The significant components of deferred income tax assets and liabilities consist of the following:

	UniSource Energy						TEP
	December 31,						December 31,
	2010			2009			2010			2009
	-Millions of Dollars-
Gross Deferred Income Tax Assets
Capital Lease Obligations	$	192		$	208		$	192		$	208
Customer Advances and Contributions in Aid of Construction		43			43			27			26
Alternative Minimum Tax Credit		34			43			16			28
Accrued Postretirement Benefits		24			24			24			24
Renewable Energy Credit Up-Front Incentive Payments		14			—			11			—
Emission Allowance Inventory		11			13			11			12
Unregulated Investment Losses		9			8			—			—
Other		29			27			26			25
Gross Deferred Income Tax Assets		356			366			307			323
Deferred Tax Assets Valuation Allowance		(8	)		—			—			—
Gross Deferred Income Tax Liabilities
Plant — Net		(463	)		(442	)		(411	)		(397	)
Capital Lease Assets — Net		(48	)		(58	)		(48	)		(58	)
Regulatory Asset — Income Taxes Recoverable Through Future Revenues		(7	)		(7	)		(7	)		(7	)
Pensions		(12	)		(10	)		(13	)		(11	)
Deferred Lease Payment		(5	)		(5	)		(5	)		(5	)
Other		(22	)		(19	)		(13	)		(11	)
Gross Deferred Income Tax Liabilities		(557	)		(541	)		(497	)		(489	)
Net Deferred Income Tax Liabilities	$	(209	)	$	(175	)	$	(190	)	$	(166	)

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The balance sheets display the net deferred income tax liability as follows:

	UniSource Energy						TEP
	December 31,						December 31,
	2010			2009			2010			2009
	-Millions of Dollars-
Deferred Income Taxes — Current Assets	$	35		$	52		$	36		$	51
Deferred Income Taxes — Noncurrent Liabilities		(244	)		(227	)		(226	)		(217	)
Net Deferred Income Tax Liability	$	(209	)	$	(175	)	$	(190	)	$	(166	)

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 income tax asset will not be realized. The $9 million unregulated investment loss deferred tax asset includes $8 million of capital loss, which can only be used if the company has capital gains to offset the losses. Management believes that it is more likely than not that the company will not be able to generate future capital gains. As a result, UniSource Energy recorded an $8 million valuation allowance against the deferred tax asset as of December 31, 2010. Management believes that based on its historical pattern of taxable income, UniSource Energy will produce sufficient income in the future to realize all other deferred income tax assets.

Uncertain Tax Positions

Accounting guidance requires us to determine whether it is “more likely than not” that we will sustain an income tax position under examination. Each income tax position is measured to determine the amount of benefit to recognize in the financial statements. The following table shows the changes in unrecognized tax benefits of UniSource Energy and TEP:

	UniSource Energy						TEP
	December 31,						December 31,
	2010			2009			2010			2009
	-Millions of Dollars-
Unrecognized Tax Benefits, beginning of year	$	19		$	20		$	19		$	20
Additions based on tax positions taken in the current year		11			1			8			1
Reductions based on settlements with tax authorities		—			(1	)		—			(1	)
Additions based on tax positions taken in the prior year		16			—			13			—
Reductions based on tax positions taken in the prior year		(4	)		(1	)		(4	)		(1	)
Reductions based on expiration of the statute of limitations		(1	)		—			(1	)		—
Unrecognized Tax Benefits, end of year	$	41		$	19		$	35		$	19

Unrecognized tax benefits which, if recognized, would reduce the effective tax rate totaled $1 million at December 31, 2010 and 2009 for both UniSource Energy and TEP. As a result of a change in accounting method filed with the IRS in February 2011 the balance of unrecognized tax benefits will decrease in 2011 by $13 million for UniSource Energy and $10 million for TEP. The remaining balance in unrecognized tax benefits could change in the next twelve months as a result of the ongoing IRS audits, but the amount of the change cannot be determined.

UniSource Energy and TEP recognize interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements. In 2010, UniSource Energy and TEP recorded no interest expense; in 2009, $1 million of interest expense was recognized. The balance of interest payable at December 31, 2010 and December 31, 2009 for UniSource Energy and TEP was $2 million. Penalties accrued are immaterial.

UniSource Energy and TEP have been audited by the IRS through tax year 2006 and are currently under audit by the IRS for 2008. Tax year 2007 has not yet been selected for audit. 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.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

NOTE 9. 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. Benefits are based on years of service and the employee’s average compensation. TEP, UNS Gas and UNS Electric fund the pension 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 balance sheets. The underfunded status is measured as the difference between the fair value of the pension 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.

Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by Internal Revenue Service benefit or compensation limitations. Changes in Supplemental Executive Retirement Plan (SERP) benefit obligations are recognized as a component of accumulated other comprehensive income (AOCI).

Pension Contributions

The Pension Protection Act of 2006 (The Pension Act) established 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, benefit payment options are limited for plans that do not meet the targets and a funding deficiency notice must be sent to all plan participants. TEP, UNS Gas and UNS Electric plans are in compliance with The Pension Act.

In 2010, UniSource Energy made pension plan contributions of $22 million, including $20 million in contributions by TEP. In 2009, UniSource Energy’s plan contributions were $25 million, including $23 million contributed by TEP.

In 2011, UniSource Energy expects to contribute $23 million to the pension plans, including $20 million in contributions by TEP.

TEP Salaried Employees Pension Plan (Salaried 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 pension plan assets and liabilities were remeasured as of August 31, 2009. In performing the remeasurement, management reviewed the key assumptions used to measure the pension 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 2009 annual expense for the Salaried Plan from $9 million to $8 million.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

TEP Union Pension Plan Amendment

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 applied in December 2009, there was no additional remeasurement.

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. UNS Gas and UNS Electric active employees do not participate in the postretirement medical plan.

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,
	2010			2009			2010			2009
	-Millions of Dollars-
Regulatory Pension Asset included in Other Regulatory Assets	$	86		$	75		$	8		$	9
Accrued Benefit Liability included in Accrued Employee Expenses		—			—			(4	)		(4	)
Accrued Benefit Liability included in Pension and Other Postretirement Benefits		(63	)		(58	)		(65	)		(65	)
Accumulated Other Comprehensive Loss		4			3			—			—
Net Amount Recognized	$	27		$	20		$	(61	)	$	(60	)

The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $6 million and $5 million, at December 31, 2010 and 2009, 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 $4 million relates to the TEP SERP.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

OBLIGATIONS AND FUNDED STATUS

We measured the actuarial present values of all pension benefit obligations and other postretirement benefit plans at December 31, 2010 and 2009. The tables below include TEP, UNS Gas and UNS Electric’s 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,
	2010			2009			2010			2009
	-Millions of Dollars-
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	242		$	230		$	71		$	67
Actuarial (Gain) Loss		28			—			(1	)		1
Interest Cost		15			14			4			4
Service Cost		8			7			3			2
Amendments		—			(1	)		—			—
Other		1			—			—			—
Benefits Paid		(11	)		(8	)		(4	)		(3	)
Projected Benefit Obligation at End of Year		283			242			73			71
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		184			135			2			—
Actual (Loss) Return on Plan Assets		25			32			—			—
Benefits Paid		(11	)		(8	)		(4	)		(3	)
Employer Contributions		22			25			6			5
Fair Value of Plan Assets at End of Year		220			184			4			2
Funded Status at End of Year	$	(63	)	$	(58	)	$	(69	)	$	(69	)

In March 2010 the Patient Protection and Affordable Care Act (PPACA) was signed into law. One provision of PPACA imposes a 40% excise tax on plans in which the aggregate value of employer-sponsored health insurance exceeds a threshold amount (so-called “Cadillac Plans”) starting in 2018. There are currently many uncertainties surrounding implementation and calculation of the excise tax. Our best estimate of the potential impact resulted in an increase in the postretirement benefit obligation of $2.4 million at December 31, 2010. It is currently unclear whether the excise tax will be deductible for income tax purposes. Our calculation assumes the excise tax will be deductible. An assumption of non-deductibility would increase the postretirement benefit obligation and the corresponding regulatory asset by approximately $1 million.

The table above includes pension benefit obligations for UNS Gas and UNS Electric of approximately $6 million and $5 million, at December 31, 2010 and 2009, respectively, plan assets of $9 million and $6 million at December 31, 2010 and 2009, respectively, and a postretirement benefit liability of less than $1 million, for UNS Gas and UNS Electric, for each period presented.

K-144

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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, 2010 and 2009:

					Other Postretirement
	Pension Benefits				Benefits
	Years Ended December 31,
	2010		2009		2010			2009
	-Millions of Dollars-
Net Loss	$	89	$	77	$	11		$	13
Prior Service Cost (Benefit)		1		1		(3	)		(4	)

Information for pension plans with Accumulated Benefit Obligations in excess of pension plan assets follows:

	December 31,
	2010		2009
	-Millions of Dollars-
Projected Benefit Obligation at End of Year	$	283	$	242
Accumulated Benefit Obligation at End of Year		243		210
Fair Value of Plan Assets at End of Year		220		184

At December 31, 2010, and December 31, 2009, all UniSource Energy defined benefit pension plans had accumulated benefit obligations in excess of pension plan assets.

The components of net periodic benefit costs are as follows:

										Other Postretirement
	Pension Benefits									Benefits
	Years Ended December 31,
	2010			2009			2008			2010			2009			2008
	-Millions of Dollars-
Service Cost	$	8		$	7		$	7		$	3		$	2		$	2
Interest Cost		15			14			14			4			4			4
Expected Return on Plan Assets		(14	)		(11	)		(16	)		—			—			—
Prior Service Cost Amortization		—			1			2			(2	)		(2	)		(2	)
Recognized Actuarial Loss		5			7			—			—			1			1
Net Periodic Benefit Cost	$	14		$	18		$	7		$	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 Operations and Maintenance expense.

K-145

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS �� (continued)

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:

	Pension Benefits
	2010					2009					2008
	Regulatory					Regulatory					Regulatory
	Asset			AOCI		Asset			AOCI		Asset			AOCI
	-Millions of Dollars-
Current Year Actuarial (Gain) Loss	$	16		$	1	$	(21	)	$	—	$	85		$	1
Amortization of Actuarial Gain (Loss)		(5	)		—		(7	)		—		—			—
Prior Service (Cost) Amortization		—			—		—			—		(2	)		—
Plan Amendments		—			—		(1	)		—		(2	)		—
Reclassification from AOCI to Regulatory Asset		—			—		—			—		8			(8	)
Total Recognized	$	11		$	1	$	(29	)	$	—	$	89		$	(7	)

	Other Postretirement Benefits
	2010			2009			2008
	Regulatory			Regulatory			Regulatory			2008
	Asset			Asset			Asset			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			—
Reclassification from AOCI to Regulatory Asset		—			—			6			(6	)
Total Recognized	$	—		$	2		$	7		$	(6	)

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 $6 million estimated net loss and less than $1 million prior service cost from other regulatory assets or AOCI into net periodic benefit cost in 2011. 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 2011 are less than $1 million and $1 million, respectively.

							Other Postretirement
Weighted-Average Assumptions Used to Determine	Pension Benefits						Benefits
Benefit Obligations as of the Measurement Date	2010			2009			2010			2009
Discount Rate		5.5 – 5.6	%		6.3	%		5.2	%		6.0	%
Rate of Compensation Increase		3.0 – 5.0	%		3.0 – 5.0	%		N/A			N/A

Weighted-Average Assumptions Used										Other Postretirement
to Determine Net Periodic Benefit Cost	Pension Benefits									Benefits
for Years Ended December 31	2010			2009			2008			2010			2008 & 2009
Discount Rate		6.3	%		6.3	%		6.6 – 6.8	%		6.0	%		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		7.5	%		8.0	%		7.75 – 8.3	%		5.6	%		N/A

K-146

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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,
	2010			2009
Assumed Health Care Cost Trend Rates
Health Care Cost Trend Rate Assumed for Next Year		7.9	%		7.9	%
Ultimate Health Care Cost Trend Rate Assumed		4.5	%		4.5	%
Year that the Rate Reaches the Ultimate Trend Rate		2027			2027

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, 2010 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		(5	)

PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS

Pension Assets

TEP, UNS Gas and UNS Electric calculate the fair value of plan assets on December 31, the measurement date. 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,
	2010			2009			2010			2009
Asset Category
Equity Securities		57	%		57	%		57	%		56	%
Fixed Income Securities		34			34			32			33
Real Estate		7			7			11			11
Other		2			2			—			—
Total		100	%		100	%		100	%		100	%

K-147

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The following tables set forth the fair value measurements of pension plan assets, by level within the fair value hierarchy, as of December 31, 2010 and 2009:

	Fair Value Measurements of Pension Assets
	December 31, 2010
	- Millions of Dollars -
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable
	Markets		Inputs		Inputs
Asset Category	(Level 1)		(Level 2)		(Level 3)		Total
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
U.S. Large Cap		—		63		—		63
U.S. Small Cap		—		12		—		12
Non-U.S.		—		51		—		51
Fixed Income		—		75		—		75
Real Estate		—		6		10		16
Private Equity		—		—		2		2
Total	$	1	$	207	$	12	$	220

	Fair Value Measurements of Pension Assets
	December 31, 2009
	- Millions of Dollars -
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable
	Markets		Inputs		Inputs
Asset Category	(Level 1)		(Level 2)		(Level 3)		Total
Cash Equivalents	$	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 commingled 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 at December 31, 2010 and 2009, using a real estate index value. The real estate index value was developed based on appraisals comprising 94% and 82% of real estate assets tracked by the index in 2010 and 2009, respectively.

Level 3 hedge and private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.

K-148

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UES pension plan of $9 million and $6 million at December 31, 2010 and 2009, respectively.

The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.

	Year Ended
	December 31, 2010
	- Millions of Dollars -
	Private Equity		Real Estate		Hedge Fund			Total
Beginning Balances at January 1, 2010	$	1	$	8	$	1		$	10
Actual Return on Plan Assets:
Relating to Assets still held at Reporting Date		—		1		—			1
Relating to Assets sold during the Period		—		—		(1	)		(1	)
Purchases, Sales, and Settlements		1		1		—			2
Ending Balance at December 31, 2010	$	2	$	10	$	—		$	12

	Year Ended
	December 31, 2009
	- Millions of Dollars -
	Private Equity		Real Estate			Hedge Fund			Total
Beginning Balances at January 1, 2009	$	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	)
Ending Balance at December 31, 2009	$	1	$	8		$	1		$	10

Pension Plan Investments

Investment Goals

Strategic asset allocation is the principal method for achieving each pension 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 pension 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 pension 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 pension plans seek to provide returns in excess of a portfolio benchmark.

K-149

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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 pension 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 pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges also have been used for defensive purposes.

Relationship between Plan Assets and Benefit Obligations

The overall health of each 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 of plan assets follow. Each Plan allows a variance of +/-2% from these targets before funds are automatically rebalanced. The hedge fund is being closed, and is currently in the redemption/liquidation process.

	TEP Plan %			UES Plan %			VEBA Trust %
Fixed Income		34	%		33	%		63	%
U.S. Large Cap		28	%		28	%		28	%
Non-US Developed		18	%		17	%		2	%
Real Estate		7	%		11	%		—
U.S. Small Cap		6	%		6	%		2	%
Non-US Emerging		6	%		5	%		—
Private Equity		1	%		—			—
Cash / Treasury Bills		—			—			5	%
Total		100.0	%		100.0	%		100.0	%
							��

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.

Other Postretirement Benefit Assets

As of December 31, 2010, the fair value of VEBA trust assets was $4 million, including $2 million of fixed income investments and approximately $2 million of equity and money market funds. 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.

K-150

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

ESTIMATED FUTURE BENEFIT PAYMENTS

TEP expects the following benefit payments to be made by the defined benefit pension plans and postretirement plan, which reflect future service, as appropriate.

			Other
	Pension		Postretirement
TEP	Benefits		Benefits
	-Millions of Dollars-
2011	$	11	$	4
2012		12		5
2013		13		5
2014		14		5
2015		16		6
Years 2016-2020		94		32

UNS Gas and UNS Electric expect annual pension and postretirement benefit payments of approximately $5 million in 2011 through 2015 and $8 million in 2016 through 2020 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 2010, 2009, and 2008. UNS Gas and UNS Electric made matching contributions of less than $1 million in each of 2010, 2009, and 2008.

NOTE 10. SHARE-BASED COMPENSATION PLAN

Under the 2006 Omnibus Stock and Incentive Plan (Share-based Compensation Plan), the Compensation Committee of the UniSource Energy Board of Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted shares/units, and performance shares. The total number of shares awarded under the Share-based Compensation Plan cannot exceed 2.25 million shares. At December 31, 2010, the total number of shares awarded under the Share-based Compensation Plan was 1 million shares.

STOCK OPTIONS

No stock options were granted by the Compensation Committee during 2010. In February 2009, the Compensation Committee granted 248,760 stock options to officers with an exercise price of $26.11. In 2008, the Compensation Committee granted 303,550 stock options to officers with an exercise price of $26.18.

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. The 2002 stock option award accrues dividend equivalents that are paid in cash on the earlier of the date of separation of service or the date the option expires. Dividend equivalents are recorded as dividends when paid.

K-151

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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 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
Expected Term (years)		7			6
Risk-free Rate		3.4	%		3.1	%
Expected Volatility		25.0	%		18.8	%
Expected Dividend Yield		3.2	%		2.8	%
Weighted-Average Grant-Date Fair Value of Options Granted During the Period	$	5.53		$	4.23

A summary of the stock option activity follows:

(Shares in Thousands)	2010					2009					2008
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
Stock Options	Shares			Price		Shares			Price		Shares			Price
Outstanding, Beginning of Year		1,598		$	24.50		1,635		$	22.50		1,451		$	21.21
Granted		—			—		249		$	26.11		304		$	26.18
Exercised or Vested		(660	)	$	19.33		(282	)	$	14.46		(120	)	$	16.34
Forfeited/Expired		(17	)	$	37.88		(4	)	$	12.28		—			—
Outstanding, End of Year		921		$	27.96		1,598		$	24.50		1,635		$	22.50
Exercisable, End of Year		654		$	28.70		1,085		$	23.06		1,153		$	19.50
Aggregate Intrinsic Value of Options Exercised ($000s)	$	9,124				$	4,177				$	1,680

	At December 31, 2010($000s)
Aggregate Intrinsic Value for Options Outstanding	$	7,606
Aggregate Intrinsic Value for Options Exercisable	$	5,015
Weighted Average Remaining Contractual Life of Outstanding Options		5.3 years
Weighted Average Remaining Contractual Life of Exercisable Options		4.5 years

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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
$17.44 – $18.74		117	1.2 years	$	18.05		117	$	18.05
$26.11 – $37.88		804	5.9 years	$	29.39		537	$	31.01

We summarize the status of non-vested stock options as of December 31, 2010, and changes during 2010 below:

	Number of Shares			Weighted-Average
Non-vested Shares	(000s)			Grant-Date Fair Value
Non-vested at January 1, 2010		513		$	5.33
Granted		—			—
Vested		(229	)		5.46
Forfeited		(17	)		8.13
Non-vested at December 31, 2010		267		$	5.04

RESTRICTED STOCK UNITS/AWARDS AND PERFORMANCE SHARES

Restricted Stock Units

Restricted stock and stock units are generally granted under the Share-based Compensation 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 is 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.

Common Stock shares totaling 14,866, 101,765 and 22,686 were issued in 2010, 2009 and 2008, respectively, with no additional increase in equity as the expense was previously recognized over the vesting period.

The Compensation Committee granted the following stock units to non-employee directors:

• May 2010 — 15,620 stock units at a weighted average fair value of $31.69 per share,

• May 2009 — 21,886 stock units at a weighted average fair value of $26.73 per share,

• August 2008 — 1,400 stock units at a weighted average fair value of $32.15 per share.

• May 2008 — 18,448 stock units at a weighted average fair value of $31.71 per share, and

• February 2008 — 3,130 stock units at a weighted average fair value of $28.75 per share,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Performance Share Awards

In February 2010, the Compensation Committee granted 93,720 performance share awards to officers. 50% of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $31.26 per share. Those awards will be paid out in shares of UniSource Energy common stock based on a comparison of UniSource Energy’s cumulative Total Shareholder Return to that of an industry peer group during the performance period of January 1, 2010 through December 31, 2012. The remaining 50% had a grant date fair value of $30.52 per share and 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.

In February 2009, the Compensation Committee granted 62,190 performance share awards to Officers at a grant date fair value, based on a Monte Carlo simulation, of $21.62 per share. Those awards will be paid out in shares of UniSource Energy common stock based on a comparison of UniSource Energy’s cumulative Total Shareholder Return to that of an industry peer group during the performance period of January 1, 2009 through December 31, 2011. The performance shares vest based on the achievement of goals by the end 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 February 2008, the Compensation Committee granted 49,140 performance share awards to Officers at a grant date fair value, based on a Monte Carlo simulation, of $17.10 per share. At December 31, 2010, upon completion of the 3-year performance period, 56,232 shares vested based on goal attainment at 150% of 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; 11,652 shares were unearned and forfeited. Compensation expense equal to the fair value on the grant date was recognized over the vesting period for the requisite service period.

	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, 2010		100		$	19.92		22		$	26.73
Granted		94			30.89		16			31.69
Vested		(38	)		17.10		(22	)		26.73
Forfeited		—			—		—			—
Non-vested at December 31, 2010		156		$	27.19		16		$	31.69

SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units)

Annually during 2008 through 2010, UniSource Energy recorded share-based compensation expense of $3 million and TEP recorded share-based compensation expense of $2 million. The actual tax deduction realized from the exercise of share-based payment arrangements totaled $3 million for 2010, $3 million for 2009, and $1 million in 2008. In 2010, 2009, and 2008, we capitalized approximately 36%, 30% and 28%, respectively, of share-based compensation costs as a cost of construction.

At December 31, 2010, the total unrecognized compensation cost related to non-vested share-based compensation was $3 million, which will be recorded as compensation expense over the remaining vesting periods through December 2012. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plan at December 31, 2010, was 1 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

NOTE 11. FAIR VALUE MEASUREMENTS

Fair Value of Financial Instruments Carried at Fair Value

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, 2010 and December 31, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. There were no transfers among Levels 1, 2 or 3 for either reporting period.

	UniSource Energy
	Quoted Prices		Significant
	in Active		Other			Significant
	Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2010
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	38	$	—		$	—		$	38
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		16			—			16
Collateral Posted(4)		—		3			—			3
Energy Contracts(5)		—		—			15			15
Total Assets		38		19			15			72
Liabilities
Energy Contracts(5)		—		(19	)		(25	)		(44	)
Interest Rate Swaps(6)		—		(10	)		—			(10	)
Total Liabilities		—		(29	)		(25	)		(54	)
Net Total Assets and (Liabilities)	$	38	$	(10	)	$	(10	)	$	18

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

	UniSource Energy
	Quoted Prices		Significant
	in Active		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)	$	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

	TEP
	Quoted Prices		Significant
	in Active		Other			Significant
	Markets for		Observable			Unobservable
	Identical Assets		Inputs			Inputs
	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2010
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	21	$	—		$	—		$	21
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		16			—			16
Energy Contracts(5)		—		—			3			3
Total Assets		21		16			3			40
Liabilities
Energy Contracts(5)		—		(7	)		(2	)		(9	)
Interest Rate Swaps(6)		—		(10	)		—			(10	)
Total Liabilities		—		(17	)		(2	)		(19	)
Net Total Assets and (Liabilities)	$	21	$	(1	)	$	1		$	21

K-156

UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

	TEP
	Quoted Prices
	in Active		Significant
	Markets for		Other			Significant
	Identical		Observable			Unobservable
	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

(1)	Cash Equivalents are based on observable market prices and include the fair value of commercial paper, money market funds and certificates of deposit. These amounts are included in Cash and Cash Equivalents and Investments and Other Property — Other in the UniSource Energy and TEP balance sheets.
(2)	Rabbi Trust Investments include amounts held in mutual and money market funds related to deferred compensation and 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 include Millennium’s equity investments in unregulated businesses. In the absence of readily ascertainable market values their value is based on the investment partner’s valuations. 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. Collateral posted is included in Current Assets — Other in the UniSource Energy balance sheet.
(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 reduce exposure to energy price risk. These contracts are included in Derivative Instruments in the UniSource Energy and TEP balance sheets. The valuation techniques are described below. See Note 16.
(6)	Interest Rate Swaps are valued based on the 6-month LIBOR index or the Securities Industry and Financial Markets Association (SIFMA) Municipal Swap index. These interest rate swaps are included in Derivative Instruments in the UniSource Energy and TEP balance sheets.

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 term of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange (NYMEX) pricing, adjusted for basis differences, the instrument is categorized in Level 2.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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 and rely on their own price experience from active transactions in the market. We 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, certain management assumptions are applied to value such contracts. These assumptions include the use of percentage multipliers to value non-standard time blocks, the application of historical price curve relationships to calendar year quotes, and the inclusion of 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 market credit default swap data. These assumptions are reviewed on a quarterly basis.

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. 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.

The following tables set forth a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	Year Ended
	December 31, 2010
	- Millions of Dollars -
	UniSource Energy									TEP
	Energy			Equity						Energy
	Contracts			Investments			Total			Contracts
Balance as of January 1, 2010	$	(13	)	$	6		$	(7	)	$	(4	)
Gains and (Losses) (Realized/Unrealized) Recorded to:
Net Regulatory Assets — Derivative Instruments		4			—			4			6
Other Comprehensive Income		(1	)		—			(1	)		(1	)
Other Expense		—			(6	)		(6	)		—
Balance as of December 31, 2010	$	(10	)	$	—		$	(10	)	$	1
Total gains (losses) attributable to the change in unrealized gains or losses relating to assets/liabilities still held at the end of the period	$	(4	)	$	—		$	(4	)	$	5

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

	Year Ended
	December 31, 2009
	- Millions of Dollars -
	UniSource Energy									TEP
	Energy			Equity						Energy
	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	)
Other Comprehensive Income		(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	)
Total gains (losses) attributable to the change in unrealized gains or losses relating to assets/liabilities held at the end of the period	$	(6	)	$	(2	)	$	(8	)	$	(3	)

Gains and losses on energy contracts include the reclassification of realized gains and losses on the settlement of derivative contracts.

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, and amounts outstanding under our credit agreements, approximate their fair value due to the short-term nature of these instruments; with the exception of $50 million of UNS Gas Senior Unsecured Notes with a make-whole provision on a call premium that have a fair value of $51 million. These items have been excluded from the table below.

• Investments in Lease Debt and Equity: TEP calculated the present value of remaining cash flows at the balance sheet date using current market rates for instruments 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.

• 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. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of their fair value. We also incorporate the impact of our own credit risk using a credit default swap rate when determining the fair value of long-term debt.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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,
	2010				2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	-Millions of Dollars-
Assets:
TEP Investment in Lease Debt and Equity	$	105	$	112	$	132	$	140
Millennium Note Receivable		15		15		15		15
Liabilities:
Long-Term Debt
TEP		1,004		866		904		778
UniSource Energy		1,304		1,194		1,254		1,145

See Note 6 for a description of TEP’s investment in Springerville Lease Debt and Equity. TEP intends to hold the $68 million investment in Springerville Lease Debt Securities to maturity. 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 12. 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.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

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

	Years Ended December 31,
	2010		2009		2008
	-In Thousands-
Numerator:
Net Income	$	111,477	$	104,258	$	14,021
Income from Assumed Conversion of Convertible Senior Notes		4,390		4,390		—
Adjusted Numerator	$	115,867	$	108,648	$	14,021
Denominator:
Weighted-average Shares of Common Stock Outstanding Common Shares Issued		36,200		35,653		35,415
Fully Vested Deferred Stock Units		123		105		217
Participating Securities		92		100		—
Total Weighted-average Shares of Common Stock Outstanding and Participating Securities — Basic		36,415		35,858		35,632
Effect of Diluted Securities
Convertible Senior Notes		4,178		4,093		—
Options and Stock Issuable under Employee Benefit Plans and the Directors’ Plan		447		499		537
Total Shares		41,040		40,450		36,169

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 doing so would be anti-dilutive.

Stock options to purchase an average of 212,000, 395,000 and 312,000 shares of Common Stock were outstanding during 2010, 2009 and 2008, 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 13. MILLENNIUM INVESTMENTS

In 2010, Millennium recorded impairment losses of $10 million related to its investments, reducing to zero the book value of its unconsolidated equity method investments. Millennium received notification of valuation changes and ownership percentage reductions as projects lost viability and funding failed. In addition, Millennium sold a wholly-owned subsidiary, and recorded a gain of less than $1 million. Gains and losses were included in Other Income or Other Expense on UniSource Energy’s income statement. Millennium also wrote off $3 million of Deferred Tax Assets related to its investments.

In 2009, Millennium finalized the sale of an equity investment. Millennium received an upfront payment of $5 million in January 2009 and a $15 million, three-year, 6%, secured note receivable. 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 gain on the sale which is included in Other Income on UniSource Energy’s income statement.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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

• The Financial Accounting Standards Board 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. After adopting this guidance on January 1, 2011, TEP and UNS Electric will continue to assign costs to both renewable energy credits and energy when purchased through a renewable purchased power agreement.

• The Financial Accounting Standards Board issued amendments that require some new disclosures and clarify some existing disclosure requirements about fair value measurements. Disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements are effective for interim and annual reporting periods beginning January 1, 2011. We will incorporate these new disclosures in our first quarter 2011 financial statements.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

NOTE 15. SUPPLEMENTAL CASH FLOW INFORMATION

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

	UniSource Energy
	Years Ended December 31,
	2010			2009			2008
	-Thousands of Dollars-
Net Income	$	111,477		$	104,258		$	14,021
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense		128,215			144,960			132,366
Amortization Expense		28,094			31,058			15,324
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		5,432			4,929			6,467
Amortization of Deferred Debt-Related Costs included in Interest Expense		3,753			4,171			3,891
Provision for Bad Debts		3,724			3,583			5,007
Use of Renewable Energy Credits for Compliance		4,745			—			—
Deferred Income Taxes		29,486			58,692			35,739
Deferred Tax Valuation Allowance		7,510			—			—
California Power Exchange Provision for Wholesale Revenue Refunds		—			4,172			—
Pension and Postretirement Expense		19,688			23,594			11,991
Pension and Postretirement Funding		(27,742	)		(30,078	)		(13,928	)
Stock Based Compensation Expense		2,751			2,779			2,901
Excess Tax Benefit from Stock Options Exercised		(3,338	)		(3,256	)		(633	)
Allowance for Equity Funds used During Construction		(4,232	)		(4,113	)		(3,244	)
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
CTC Revenue Refunded		(10,095	)		(12,141	)		58,092
Decrease to Reflect PPFAC/PGA Recovery		(31,105	)		(17,091	)		(10,975	)
Loss/(Gain) on Millennium’s Investments		9,936			(4,730	)		2,469
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(7,156	)		17,696			432
Materials and Fuel Inventory		21,744			(24,621	)		(10,176	)
Accounts Payable		2,612			(8,196	)		8,164
Income Taxes		24,456			14,267			(5,201	)
Interest Accrued		14,354			15,956			16,772
Other Regulatory Liabilities		2,788			10,009			7,501
Taxes Other Than Income Taxes		2,442			(48	)		(29	)
Other		2,820			7,347			2,817
Net Cash Flows — Operating Activities	$	342,359		$	343,197		$	273,767

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

	TEP
	Years Ended December 31,
	2010			2009			2008
	-Thousands of Dollars-
Net Income	$	106,978		$	89,248		$	4,363
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense		99,510			116,970			105,859
Amortization Expense		32,196			35,931			20,181
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		3,855			3,439			5,039
Amortization of Deferred Debt-Related Costs included in Interest Expense		2,146			2,364			2,826
Provision for Bad Debts		2,506			2,342			2,957
Use of Renewable Energy Credits for Compliance		4,245			—			—
California Power Exchange Provision for Wholesale Revenue Refunds		—			4,172			—
Deferred Income Taxes		26,017			46,721			24,410
Pension and Postretirement Expense		17,454			21,294			10,402
Pension and Postretirement Funding		(25,672	)		(28,330	)		(12,439	)
Stock Based Compensation Expense		2,131			2,121			2,239
Allowance for Equity Funds used During Construction		(3,567	)		(3,516	)		(2,950	)
CTC Revenue Refunded		(10,095	)		(12,141	)		58,092
Decrease to Reflect PPFAC Recovery		(23,025	)		(20,724	)		—
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
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		(3,463	)		9,488			131
Materials and Fuel Inventory		20,920			(23,794	)		(8,774	)
Accounts Payable		(496	)		(10,410	)		14,812
Income Taxes		16,012			(2,714	)		17,646
Interest Accrued		14,431			16,142			15,857
Taxes Other Than Income Taxes		1,469			725			(1,011	)
Other Regulatory Liabilities		2,500			10,555			6,449
Other		11,703			4,665			5,668
Net Cash Flows — Operating Activities	$	297,755		$	264,548		$	265,756

Proceeds from the issuance of the 2010 Coconino A Bonds were deposited with a trustee and were used on December 30, 2010, to redeem $37 million of 1997 Coconino A Bonds. TEP had no cash receipts or payments as a result of this transaction.

Proceeds from the issuance of the 2010 Pima A Bonds were deposited in a construction fund with a trustee. TEP drew down funds as qualified expenditures were incurred. The $11 million remaining in the construction fund at December 31, 2010 affected recognized assets and liabilities but did not result in cash receipts or payments.

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.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

In 2008, TEP applied the proceeds of the 2008 Pima B bonds to redeem previously issued Pima bonds that TEP had repurchased in 2005. TEP deposited these redemption proceeds with a trustee which was subsequently applied to the payment of $128 million of principal plus $5 million of accrued interest upon maturity of the 7.5% collateral trust 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.

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,
	2010		2009		2008
	-Thousands of Dollars-
(Decrease)/Increase to Utility Plant Accruals(1)	$	8,514	$	1,082	$	(25,450	)
Net Cost of Removal of Interim Retirements(2)		4,592		43,381		45,100
Capital Lease Obligations(3)		16,630		17,984		16,612
UED Secured Term Loan Prepayments(4)		3,188		3,625		—

(1)	The non-cash additions to Utility Plant represent accruals for capital expenditures.
(2)	The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.
(3)	The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.
(4)	The non-cash UED Secured Term Loan prepayment represents deposits applied to $30 million principal.

NOTE 16. ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES

See Note 1 for description of our related accounting policies.

FINANCIAL IMPACT OF DERIVATIVES

Cash Flow Hedges

At December 31, 2010 and December 31, 2009, UniSource Energy and TEP had liabilities related to their cash flow hedges of $12 million and $7 million, respectively. UniSource Energy and TEP had net after-tax unrealized losses on derivative activities reported in AOCI of $6 million and $5 million in 2010 and 2008, respectively. In 2009, UniSource Energy and TEP had net after-tax unrealized gains on derivative activities reported in AOCI of less than $1 million.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Regulatory Treatment of Commodity Derivatives

The following table discloses 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							TEP
	Years Ended December 31,
	2010		2009			2008		2010			2009			2008
	-Millions of Dollars-
Increase (Decrease) to Regulatory Assets	$	—	$	(29	)	$	65	$	(4	)	$	(11	)	$	19

The fair value of derivative assets and liabilities were as follows:

	UniSource Energy						TEP
	December 31,			December 31,			December 31,			December 31,
	2010			2009			2010			2009
	-Millions of Dollars-
Assets	$	15		$	7		$	3		$	1
Liabilities		(42	)		(34	)		(7	)		(9	)
Net Assets (Liabilities)	$	(27	)	$	(27	)	$	(4	)		(8	)

Realized gains and losses on settled gas swaps are fully recovered through the PPFAC or PGA. In 2010, 2009, and 2008, UniSource Energy realized losses of $23 million, $51 million and $9 million, respectively. TEP realized losses of $9 million, $29 million and $4 million in 2010, 2009, and 2008, respectively.

At December 31, 2010, TEP had contracts that will settle through the third quarter of 2015; UNS Electric had contracts that will settle through the first quarter of 2014; and UNS Gas had contracts that will settle through the fourth quarter of 2013.

Other Commodity Derivatives

UniSource Energy and TEP record realized and unrealized gains and losses on other energy contracts on a net basis in Wholesale Sales. In 2010, 2009, and 2008, net realized and unrealized gains and losses were less than $1 million. At December 31, 2010, UniSource Energy and TEP had no other energy contracts outstanding. At December 31, 2009, TEP had assets of $4 million and liabilities of $4 million related to other energy contracts. TEP’s other energy contracts were with an affiliated counterparty; therefore, related assets and liabilities were eliminated in the UniSource Energy financial statements.

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:

	2010			2009			2008
	-Millions of Dollars-
Recorded in Wholesale Sales:
Forward Power Sales	$	27		$	20		$	17
Forward Power Purchases		(34	)		(18	)		(17	)
Total Sales and Purchases Not Resulting in Physical Delivery	$	(7	)	$	2		$	—

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

DERIVATIVE VOLUMES

At December 31, 2010, UniSource Energy and TEP had gas swaps totaling 14,973 Billion British thermal units (GBtu) and 6,424 GBtu, respectively, and power contracts totaling 4,807 Gigawatt-hours (GWh) and 1,144 GWh, respectively, which were accounted for as derivatives. At December 31, 2009, UniSource Energy and TEP had gas swaps totaling 13,321 GBtu and 5,658 GBtu, respectively, and power contracts totaling 3,859 GWh and 1,247 GWh, respectively, which were accounted for as derivatives.

CREDIT RISK ADJUSTMENT

When the fair value of our derivative contracts is 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 bonds, we consider the impact of counterparty creditworthiness 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, 2010, and at December 31, 2009, the impact of counterparty credit risk on the fair value of derivative asset contracts was less than $1 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, 2010, and at December 31, 2009, the impact of our own credit risk was less than $1 million.

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 non-performance 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 requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Gas or UNS Electric; 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.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The following table shows the sum of the fair value of all derivative instruments under contracts with credit-risk related contingent features that are in a net liability position at December 31, 2010. 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, 2010
	-Millions of Dollars-
Net Liability Position	$	15	$	25	$	21	$	61
Cash Collateral Posted		—		3		—		3
Letters of Credit		1		—		13		14
Additional Collateral to Post if Contingent Features Triggered		15		23		10		48

As of December 31, 2010, TEP had $20 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities and UNS Electric had $3 million of such exposure related to its supply and hedging contracts. TEP had five counterparties which individually comprise greater than 10% of the total credit exposure and UNS Electric had one. At December 31, 2010, UNS Gas had $1 million exposure to other counterparties’ creditworthiness.

NOTE 17. 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 while UNS Gas’ sales generally peak during the winter. 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)
2010
Operating Revenue	$	318,821	$	339,036	$	438,767	$	357,053
Operating Income		52,917		72,294		123,482		48,259
Net Income		19,972		25,540		54,883		11,082
Basic EPS		0.55		0.70		1.50		0.30
Diluted EPS		0.52		0.65		1.36		0.29
2009
Operating Revenue	$	312,226	$	338,158	$	415,138	$	331,179
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

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (concluded)

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-
2010
Operating Revenue	$	231,054		$	274,617	$	354,576	$	264,732
Operating Income		36,504			62,315		114,373		33,575
Net Income		10,349			27,636		58,993		10,000
2009
Operating Revenue	$	213,644		$	271,918	$	358,088	$	255,337
Operating Income		18,572			51,594		108,055		31,902
Net Income (Loss)		(553	)		26,507		55,277		8,017

The principal unusual items for TEP and UniSource Energy include:

UniSource Energy

• Millennium recorded impairment losses in investments of $10 million ($8 million after-tax). $5 million in losses occurred in the fourth quarter of 2010, and $5 million occurred in the second quarter of 2010. In the third quarter of 2010, Millennium wrote off $3 million of Deferred Tax Assets related to its investments.

• In the second quarter of 2009, Millennium recorded a $6 million ($3.6 million after-tax) gain, on the sale of an investment.

UniSource Energy and TEP

• In the fourth quarter of 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 million after-tax) reduction in net income.

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Schedule

Valuation and Qualifying Accounts

Schedule II — Valuation and Qualifying Accounts — UniSource Energy

			Additions-
Description	Beginning		Charged to				Ending
Year Ended December 31,	Balance		Income		Deductions		Balance
	-Millions of Dollars-
Allowance for Doubtful Accounts(1)
2010	$	6	$	4	$	4	$	6
2009		20		4		18		6
2008(2)		18		5		3		20
Deferred Tax Assets Valuation Allowance(3)
2010	$	—	$	8	$	—	$	8

(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.
(3)	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 income tax asset will not be realized. Management believes that it is more likely than not that we will not be able to generate future capital gains to offset the capital losses related to an unregulated investment loss deferred tax asset. As a result, an $8 million valuation allowance was recorded against the deferred tax asset as of December 31, 2010.

Valuation and Qualifying Accounts

Schedule II — Valuation and Qualifying Accounts — TEP

			Additions-
Description	Beginning		Charged to				Ending
Year Ended December 31,	Balance		Income		Deductions		Balance
	-Millions of Dollars-
Allowance for Doubtful Accounts(1)
2010	$	4	$	3	$	3	$	4
2009		17		2		15		4
2008(2)		17		3		3		17

(1)	TEP records 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 13(a) — 15(e) or Rule 15(d) — 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of December 31, 2010. 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 2010, 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 2010 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		59	None			2009
Lawrence J. Aldrich		58		2,3,5		2000
Barbara M. Baumann		55		1,2,4		2005
Larry W. Bickle		65		3,4,5		1998
Harold W. Burlingame		70		2,3,5		1998
Robert A. Elliott		55		1,2,3,4,5		2003
Daniel W.L. Fessler		69		1,3,5		2005
Louise L. Francesconi		58		1,2,4		2008
Warren Y. Jobe		70		1,2,4		2001
Ramiro G. Peru		55		1,2,4		2008
Gregory A. Pivirotto		58		1,3,4		2008
Joaquin Ruiz		58		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 from 2009-2010. President of Aldrich Capital Company since January 2007; Chief Operating Officer of The Critical Path Institute from 2005-2007; 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 SM Energy Company since 2002; member of the Board of Trustees of the Putnam Mutual Funds since 2010.
Larry W. Bickle	Director of SM Energy Company since 1994; Retired private equity investor; Managing Director of Haddington Ventures, LLC from 1997 to 2007. Non-executive Chairman of Quantum Natural Gas Strategies, LLC since 2008.
Harold W. Burlingame	Executive Vice President of AT&T from 1986-2001; Senior Executive Advisor for ATT Wireless from 2001-2005; Chairman of ORC Worldwide from 2004-2010; President of IRC Foundation since December 2010; Director of Cornerstone On Demand since 2006.
Robert A. Elliott	President and owner of The Elliott Accounting Group since 1983; Director and Corporate Secretary of Southern Arizona Community Bank from 1998-2010; Television Analyst/Pre-game Show Co-host for Fox Sports Arizona from 1998-2009; Chairman of the Board of Tucson Metropolitan Chamber of Commerce 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; Director of AAA since 2007; Director of the NBA Retired Players Association since 2010; and Director of the University of Arizona Foundation.

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Daniel W.L. Fessler	President of the California Public Utility Commission from 1991-1996; Professor Emeritus of the University of California since 1994; Of counsel for the law firm of Holland & Knight from 2003-2007; 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 President of Raytheon Missile Systems; Director of Stryker Corporation since July 2006; Chairman of the Board of Trustees for TMC Healthcare; Director of Global Solar Energy, Inc. since 2008.
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 2003 to December 2004; Director of WellPoint, Inc. since December 2004; Trustee of RidgeWorth Funds since 2004. Director of Home Banc Corp. from 2005-2009.
Ramiro G. Peru	Executive Vice President and Chief Financial Officer of Phelps Dodge Corporation from October 2004 to March 2007; Senior Vice President and Chief Financial Officer of Phelps Dodge Corporation from May 1999 to September 2004; Director of WellPoint Health Networks, Inc. from 2003 to December 2004; Director of WellPoint, Inc. since December 2004; Director of Southern Peru Copper Corporation from 2002 to 2004.
Gregory A. Pivirotto	President and Chief Executive Officer and Director of University Medical Center Corporation from 1994-2010; Certified Public Accountant since 1978; Director of Arizona Hospital & Healthcare Association from 1997 to 2005. Director of Tucson Airport Authority since 2008; Member of the Advisory Board of Harris Bank since 2010.
Joaquin Ruiz	Professor of Geosciences, University of Arizona since 1983; Dean, College of Science, University of Arizona since 2000; Executive Dean of the University of Arizona College of Letters, Arts and Science since 2009.

Directors — TEP

			Director
Name	Age		Since
Paul J. Bonavia		59		2009
Michael J. DeConcini		46		2009
Raymond S. Heyman		55		2009
Kevin P. Larson		54		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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, 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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, which information is incorporated herein by reference.

ITEM 12. — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

General

At February 15, 2011, UniSource Energy had outstanding 36.6 million shares of Common Stock. As of February 15, 2010, the number of shares of Common Stock beneficially owned by all directors and officers of UniSource Energy as a group amounted to approximately 3% of the outstanding Common Stock.

At February 15, 2011, 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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, 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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, 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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, 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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, 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 2011 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010, which information is incorporated herein by reference.

PART IV

ITEM 15. — EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

	Page
(a) 1. Consolidated Financial Statements as of December 31, 2010 and 2009 and for Each of the Three Years in the Period Ended December 31, 2010
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		98
2. Financial Statement Schedules
Schedule II
Valuation and Qualifying Accounts		170
3. Exhibits

Reference is made to the Exhibit Index commencing on page 179.

K-175

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	UNISOURCE ENERGY CORPORATION
Date: March 1, 2011	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Principal Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 1, 2011	/s/ Paul J. Bonavia*
	Paul J. Bonavia
	Chairman of the Board, President and Principal Executive Officer
Date: March 1, 2011	/s/ Kevin P. Larson
	Kevin P. Larson
	Principal Financial Officer
Date: March 1, 2011	/s/ Karen G. Kissinger*
	Karen G. Kissinger
	Principal Accounting Officer
Date: March 1, 2011	/s/ Lawrence J. Aldrich*
	Lawrence J. Aldrich
	Director
Date: March 1, 2011	/s/ Barbara M. Baumann*
	Barbara M. Baumann
	Director
Date: March 1, 2011	/s/ Larry W. Bickle*
	Larry W. Bickle
	Director
Date: March 1, 2011	/s/ Harold W. Burlingame*
	Harold W. Burlingame
	Director
Date: March 1, 2011	/s/ Robert A. Elliott*
	Robert A. Elliott
	Director
Date: March 1, 2011	/s/ Daniel W.L. Fessler*
	Daniel W.L. Fessler

K-176

Date: March 1, 2011	/s/ Louise L. Francesconi*
	Louise L. Francesconi
	Director
Date: March 1, 2011	/s/ Warren Y. Jobe*
	Warren Y. Jobe
	Director
Date: March 1, 2011	/s/ Ramiro Peru*
	Ramiro Peru
	Director
Date: March 1, 2011	/s/ Gregory A. Pivirotto*
	Gregory Pivirotto
	Director
Date: March 1, 2011	/s/ Joaquin Ruiz*
	Joaquin Ruiz
	Director
Date: March 1, 2011	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

K-177

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TUCSON ELECTRIC POWER COMPANY
Date: March 1, 2011	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Principal Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 1, 2011	/s/ Paul J. Bonavia*
	Paul J. Bonavia
	Chairman of the Board, President and Principal Executive Officer
Date: March 1, 2011	/s/ Kevin P. Larson
	Kevin P. Larson
	Principal Financial Officer and Director
Date: March 1, 2011	/s/ Karen G. Kissinger*
	Karen G. Kissinger
	Principal Accounting Officer
Date: March 1, 2011	/s/ Michael J. DeConcini*
	Director
Date: March 1, 2011	/s/ Raymond S. Heyman*
	Director
Date: March 1, 2011	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

K-178

EXHIBIT INDEX

*2(a)	—	Agreement and Plan of Exchange, dated as of March 20, 1995, between TEP, UniSource Energy and NCR Holding, Inc. (Form 10-K for the year ended December 31,1997, File No. 13739 — Exhibit. 2(a)).
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 and as further amended by Articles of Amendment, filed with the ACC on September 3, 2009.
*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(a)	—	Reserved.
*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).)

K-179

*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).)

K-180

*4(e)(6)	—	Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(I)(6).)
*4(f)(1)	—	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924 — Exhibit 4(n)(1).)
*4(f)(2)	—	Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — Exhibit 4(n)(2).)
*4(f)(3)	—	First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 — Exhibit 4(m)(3).)
*4(f)(4)	—	First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 — Exhibit 4(m)(4).)
*4(f)(5)	—	Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(m)(5).)
*4(f)(6)	—	Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(m)(6).)
4(g)	—	Reserved
*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).)

K-181

*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 (Form 10-K for the year ended December 31, 2009, File No. 1-3739, Exhibit 4(i)(10)).
*4(i)(11)	—	Supplemental Indenture No. 10 creating a series of bonds designated as First Mortgage Bonds, Collateral Series H, dated as of March 1, 2010. (Form 8-K dated March 5, 2010, File No. 1-13739, Exhibit 4(b)).
*4(i)(12)	—	Supplemental Indenture No.11, dated as of November 1, 2010, between Tucson Electric Power Company and The Bank of New York Mellon, as trustee. (For 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.5).
*4(i)(13)	—	Supplemental Indenture No. 12, dated as of December 1, 2010, between TEP and the Bank of New York Mellon, creating a series of bonds designated First Mortgage Bonds, Collateral Series J. (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(b)).
*4(j)(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(j)(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 and 1-13739 — Exhibit 4(b).)
*4(k)(1)	—	Indenture of Trust, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(c)).
*4(k)(2)	—	Loan Agreement, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-13739, 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).)

K-182

*4(m)(1)	—	Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(a).)
*4(m)(2)	—	Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(b).)
*4(n)(1)	—	Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(c).)
*4(n)(2)	—	Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(d).)
*4(o)(1)	—	Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(e).)
*4(o)(2)	—	Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(f).)
4(p)	—	Reserved.
*4(q)(1)	—	Amendment No. 4 to Amended and Restated TEP Credit Agreement, dated as of June 24, 2010. (Form 10-Q for the quarter ended June 30, 2010, File No. 1-13739, Exhibit 4(a)).
*4(r)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among Tucson Electric Power Company, Union Bank, N.A., as Administrative Agent, and a group of lenders. (For 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.3).
*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 dated 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(v)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UniSource Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (For 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.1).
*4(w)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UNS Electric, Inc., UNS Gas, Inc., UniSource Energy Services, Inc., Union Bank, N.A., as Administrative Agent, and a group of lenders. (For 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.4).

K-183

*4(x)(1)	—	Reimbursement Agreement, dated as of December 14, 2010, among TEP, as Borrower, the financial institutions from time to time, parties thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank. (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(a)).
*4(y)(1)	—	Second Amended and Restated Pledge Agreement, dated as of November 9, 2010, among UniSource Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.2).
*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 and 1-13739 — Exhibit 4(b).)
*4(ab)(1)	—	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(ab)(2)	—	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(ab)(3)	—	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(ab)(4)	—	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)).
*4(ac)(1)	—	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(ac)(2)	—	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(ac)(3)	—	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. (Form 10-K for the year ended December 31, 2009, File No. 1-13739 Exhibit 4(aa)(9)).

K-184

*4(ad)(1)	—	Loan Agreement dated as of March 1, 2010, between Tucson Electric Power Company and JP Morgan Chase Bank, as Lender and Administrative Agent. (Form 8-K dated March 5, 2010, File No. 1-13739, Exhibit 4(a)).
*4(ad)(2)	—	Amendment No. 1, dated as of June 24, 2010, to TEP Loan Agreement dated as of March 1, 2010. (Form 10-Q for the quarter ended June 30, 2010, File No. 1-13739, Exhibit 4(b)).
*4(ae)(1)	—	Indenture of Trust, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-13739 Exhibit 4(a)).
*4(ae)(2)	—	Loan Agreement, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-13739 Exhibit 4(b)).
*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).)

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*10(a)(7)	—	Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(7).)
*10(a)(8)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(8).)
*10(a)(9)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(9).)
*10(a)(10)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(10).)
*10(a)(11)	—	Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney 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).)

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*10(a)(17)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(13).)
*10(a)(18)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(14).)
*10(a)(19)	—	Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(19).)
*10(a)(20)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 —Exhibit 10(f)(20).)
*10(a)(21)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(21).)
*10(a)(22)	—	Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(22).)
*10(a)(23)	—	Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(15).)
*10(a)(24)	—	Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(16).)
*10(a)(25)	—	Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(25).)

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*10(a)(26)	—	Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(26).)
*10(a)(27)	—	Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732 — Exhibit 10(f)(27).)
*10(b)(1)	—	Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(1).)
*10(b)(2)	—	Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(2).)
*10(b)(3)	—	Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(3).)
*10(b)(4)	—	Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(4).)
*10(b)(5)	—	Lease Supplement No.1, dated December 31, 1985, to Lease 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).)

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*10(b)(9)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(9).)
*10(b)(10)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(10).)
*10(b)(11)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(11).)
*10(b)(12)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(12).)
*10(b)(13)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(13).)
*10(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).)

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*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).)
*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(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.

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12(b)	—	Computation of Ratio of Earnings to Fixed Charges — UniSource Energy.
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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