Uns Energy (UNS) 10-K 2011 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

OR

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

For the transition period from             to            .

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification Number
1-13739	UNISOURCE ENERGY CORPORATION (An Arizona Corporation) 88 E. Broadway Boulevard Tucson, AZ 85701 (520) 571-4000	86-0786732
1-5924	TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) 88 E. Broadway Boulevard Tucson, AZ 85701 (520) 571-4000	86-0062700

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

Registrant	Title of Each Class	Name of Each Exchange 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:

Registrant	Title of Each Class	Name of Each Exchange on Which Registered
Tucson Electric Power Company	Common Stock, without par value	N/A

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	Yes  x	No  ¨
Tucson Electric Power Company	Yes  ¨	No  x

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	Yes  ¨	No  x
Tucson Electric Power Company	Yes  ¨	No  x

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	Yes  x	No  ¨
Tucson Electric Power Company	Yes  x	No  ¨

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	Yes  x	No  ¨
Tucson Electric Power Company	Yes  x	No  ¨

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

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

UniSource Energy Corporation	Large Accelerated Filer          x	Accelerated Filer  ¨	Non-accelerated filer  ¨
	Smaller Reporting Company  ¨
Tucson Electric Power Company	Large Accelerated Filer          ¨	Accelerated Filer  ¨	Non-accelerated filer  x
	Smaller Reporting Company  ¨

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

UniSource Energy Corporation	Yes  ¨	No  x
Tucson Electric Power Company	Yes  ¨	No  x

The aggregate market value of UniSource Energy Corporation voting Common Stock held by non-affiliates of the registrant was $1,361,485,759 based on the last reported sale price thereof on the consolidated tape on June 30, 2011.

At February 21, 2012, 37,956,169 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At February 21, 2012, 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 2012 Annual Meeting of Shareholders are incorporated by reference into Part III.

Table of Contents

Definitions	iv
— PART I —
Item 1. – Business	1
Overview of Consolidated Business	1
TEP	2
Service Area and Customers	2
Generating and Other Resources	4
Fuel Supply	7
Transmission Access	8
Rates and Regulation	9
TEP’s Utility Operating Statistics	11
Environmental Matters	12
UNS Gas	15
Service Territory and Customers	15
Gas Supply and Transmission	15
Rates and Regulation	15
Environmental Matters	17
UNS Electric	17
Service Territory and Customers	17
Power Supply and Transmission	17
Rates and Regulation	18
Environmental Matters	19
Other Non-Reportable Segments	19
Millennium	19
Employees	19
Executive Officers of the Registrants	20
SEC Reports Available on UniSource Energy’s Website	21
Item 1A. – Risk Factors	21
Item 1B. – Unresolved Staff Comments	27
Item 2. – Properties	27
TEP Properties	27
UES Properties	28
Item 3. – Legal Proceedings	28
Item 4. – Mine Safety Disclosures	29
— PART II —
Item  5. – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity	29
Item 6. – Selected Consolidated Financial Data	31
UniSource Energy	31
TEP	32
Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
UniSource Energy Consolidated	33
Outlook and Strategies	33
Results of Operations	34
Liquidity and Capital Resources	36
Tucson Electric Power Company	41
Results of Operations	41
Factors Affecting Results of Operations	48
Liquidity and Capital Resources	51

i

UNS Gas	56
Results of Operations	56
Factors Affecting Results of Operations	57
Liquidity and Capital Resources	58
UNS Electric	60
Results of Operations	60
Factors Affecting Results of Operations	62
Liquidity and Capital Resources	63
Other Non-Reportable Business Segments	65
Results of Operations	65
Factors Affecting Results of Operations	66
Critical Accounting Policies	66
Recently Issued Accounting Pronouncements	70
Safe Harbor for Forward-Looking Statements	71
Item 7A. – Quantitative and Qualitative Disclosures about Market Risk	71
Item 8. – Consolidated Financial Statements and Supplementary Data	77
Management’s Reports on Internal Controls Over Financial Reporting	77
Reports of Independent Registered Public Accounting Firm	78
UniSource Energy Corporation
Consolidated Statements of Income	80
Consolidated Statements of Cash Flows	81
Consolidated Balance Sheets	82
Consolidated Statements of Capitalization	84
Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income	85
Tucson Electric Power Company
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 Stockholder’s Equity and Comprehensive Income	91
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies	92
Note 2. Regulatory Matters	101
Note 3. Segment and Related Information	108
Note 4. Commitments, Contingencies, and Proposed Environmental Matters	111
Note 5. Utility Plant and Jointly-Owned Facilities	118
Note 6. Debt, Credit Facilities, and Capital Lease Obligations	119
Note 7. Stockholders’ Equity	125
Note 8. Income Taxes	126
Note 9. Employee Benefit Plans	129
Note 10. Share-Based Compensation Plan	137
Note 11. Fair Value Measurements	140
Note 12. UniSource Energy Earnings Per Share (EPS)	145
Note 13. Millennium Investments	146
Note 14. Recently Issued Accounting Pronouncements	146
Note 15. Supplemental Cash Flow Information	147
Note 16. Accounting for Derivative Instruments and Hedging Activities	149
Note 17. Quarterly Financial Data (Unaudited)	151
Schedule II – Valuation and Qualifying Accounts	153
Item 9. – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	154
Item 9A. – Controls and Procedures	154
Item 9B. – Other Information	154

ii

— PART III —
Item 10. – Directors, Executive Officers and Corporate Governance of the Registrants	155
Item 11. – Executive Compensation	157
Item 12. – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	157
Item 13. – Certain Relationships and Related Transactions and Director Independence	158
Item 14. – Principal Accountant Fees and Services	158
— PART IV —
Item 15. – Exhibits and Financial Statement Schedules	158
Signatures	159
Exhibit Index	162

iii

DEFINITIONS

The abbreviations and acronyms used in the 2011 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
Base O&M	A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business
Base Rates	The portion of TEP’s and UNS Electric’s Retail Rates attributed to generation, transmission, distribution costs and customer charge; and UNSGas’ delivery costs and customer charge
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 and Gas 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 nitrogenoxide; 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 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

iv

IDBs	Industrial development revenue or pollution control revenue bonds
IRS	Internal Revenue Service
kWh	Kilowatt-hour(s)
kV	Kilovolt(s)
LIBOR	London Interbank Offered Rate
Long-Term Wholesale Margin Revenues	A non-GAAP measure that demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts
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
NOx	Nitrogen oxide
NTUA	Navajo Tribal Utility Authority
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
Retail Margin Revenues	A non-GAAP financial measure that demonstrates the underlying revenue trend and performance of our core utility businesses.
Retail Rates	Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service
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, a wholly-owned subsidiary of Millennium
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

v

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 (as amended)
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 (as amended)
UniSource Energy	UniSource Energy Corporation
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES
UNS Electric Term Loan	Four-year $30 million term loan agreement dated as of August 10, 2011.
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 (as amended)
Valencia	Valencia power plant owned by UNS Electric
VEBA	Voluntary Employee Beneficiary Association
WAPA	Western Area Power Administration

vi

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 with no significant operations of its own. UniSource Energy’s operating subsidiaries are separate legal entities with their 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).

Our business includes three primary business segments: TEP; UNS Gas, Inc. (UNS Gas); and UNS Electric, Inc. (UNS Electric). TEP is an electric utility serving the community of Tucson, Arizona. UES provides gas and electric service to more than 30 communities in northern and southern Arizona through its two operating subsidiaries, UNS Gas and UNS Electric.

Other subsidiaries include UED, which developed the Black Mountain Generating Station (BMGS) in northwestern Arizona in 2008. The facility, which includes two natural gas-fired combustion turbines, initially provided energy to UNS Electric through a power sales agreement. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. This transaction did not impact UniSource Energy’s consolidated financial statements.

Millennium has existing investments in unregulated businesses that represented less than 1% of UniSource Energy’s total assets as of December 31, 2011. We have no new investments planned for Millennium. Southwest Energy Solutions (SES) is a subsidiary of Millennium that 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 three business segments.

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
TEP	$	85		$	108		$	91
UNS Gas		10			9			7
UNS Electric		18			15			11
Other(1)		(3	)		(19	)		(3	)
Consolidated Net Income	$	110		$	113		$	106

⁽¹⁾ Includes: UniSource Energy parent company expenses; interest expense (net of tax) on UniSource Energy Convertible Senior Notes and on the UniSource Credit Agreement; Millennium; 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 Retail Rates for retail electric and natural gas service are determined on a “cost of service” basis. Retail Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for our utility businesses 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 retirements of utility plant reduce rate base.

Retail Rates charged by TEP, UNS Gas and UNS Electric also include pass-through mechanisms that allow each utility to recover the actual costs of its fuel, transmission, and energy 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 2011, TEP’s electric utility operations contributed 77% of UniSource Energy’s operating revenues and comprised 82% of its assets.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to approximately 404,000 retail customers in southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately one 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, and opportunities for customers to generate their own electricity.

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.

		September 30,			September 30,			September 30,
	2011			2010			2009
Residential		42	%		42	%		42	%
Commercial		21	%		21	%		21	%
Non-mining Industrial		23	%		23	%		23	%
Mining		11	%		12	%		11	%
Public Authority		3	%		2	%		3	%

Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. In 2009, 2010 and 2011, TEP’s average number of retail customers increased by less than 1% per year.

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 Retail Rate paid by mining customers, and the mines’ potential development of their own electric generation resources. TEP’s kWh sales to mining customers increased by 0.3% in 2011 and 1.4% in 2010 as a result of increased production due to high copper prices.

We expect the number of TEP’s retail customers to increase at a rate of approximately 0.5% in 2012 and approximately 0.9% in 2013.

Sales Volumes

Weak economic conditions and the implementation of energy efficiency programs have had a negative impact on electricity sales. In 2009 and 2010, TEP’s retail kWh sales declined by 1.4% and 0.8%, respectively. In 2011, TEP’s retail kWh sales were 0.4% above 2010 due in part to a 0.3% increase in the average number of retail customers. In 2012, we expect kWh sales to TEP’s retail customers to be near the same level as 2011.

Energy Service Providers

Although the ACC’s Retail Electric Competition Rules contemplated that TEP’s retail customers may be eligible to choose an alternative energy service provider (ESP), portions of those Rules have been invalidated by the Arizona courts and there are no ESPs currently authorized to provide alternative retail electric service to TEP’s customers. 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.

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 energy:

• From January 1, 2012 through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the Palo Verde Market Index. Prior to June 1, 2011, TEP received an annual demand charge of approximately $22 million.

K-3

• Navajo Tribal Utility Authority (NTUA) expires in December 2015. TEP serves the portion of NTUA’s load that is not served by the authority’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh per year. Since 2010, the price of 50% of the MWh sales to NTUA from June to September has been based on the Palo Verde Market Index. In 2011, approximately 12% of the total energy sold to NTUA was priced based on the Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA.

• 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. 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.

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

GENERATING AND OTHER RESOURCES

At December 31, 2011, TEP owned or leased 2,262 MW of net generating capability, as set forth in the following table:

	September 30,	September 30,	September 30,	September 30,		September 30,		September 30,		September 30,		September 30,
					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		401		TEP		100.0		401
Springerville Station	2	Springerville, AZ	1990	Coal		403		TEP		100.0		403
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		555		PNM		33.3		185
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		75		TEP		100.0		75
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		7		TEP		100.0		7
Total TEP Capacity(2)												2,262

⁽¹⁾  Leased asset as of December 31, 2011.

⁽²⁾  Excludes 1,009 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2011, total owned capacity was 1,861 MW and leased capacity was 401 MW.

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Springerville Generating Station

Springerville Unit 1 is leased by TEP and Unit 2 is owned by San Carlos, a wholly-owned subsidiary of TEP. TEP’s other interests in the Springerville Generating Station include 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 the remaining 50% interest in the Springerville Common Facilities.

In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure to determine the fair market value purchase price. The formal appraisal process was completed in accordance with the Springerville Unit 1 lease agreements. The purchase price was determined to be $478 per kW of capacity. TEP has until September 2013 to give notice that it will exercise its purchase option, with the purchase occurring in January 2015. TEP can choose to exercise this option to purchase any or all of the lease interests not currently owned by TEP; TEP currently owns a 14% undivided interest in Springerville Unit 1. If TEP chooses to purchase all of the remaining interests in Springerville Unit 1 from the owner participants, the aggregate purchase price would be $159 million.

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. Since entering the lease, TEP purchased a 13% ownership interest in the Springerville Coal Handling Facilities. The terms of the Springerville Coal Handling Facilities Leases expire in 2015 but have optional fixed-rate renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million.

See Note 6 and Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for more information regarding the Springerville leases.

Sundt Generating Station

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

In 2010, TEP purchased 100% of the equity interest in the Sundt Unit 4 lease for approximately $51 million, redeemed the outstanding Sundt Unit 4 lease debt of $5 million, and terminated the lease agreement.

Renewable Energy Resources

Owned Resources

As of December 31, 2011, TEP’s owned photovoltaic (PV) solar generating capacity totaled 13 MW. The Springerville Generating Station solar system, which is located near TEP’s Springerville coal-fired facility in eastern Arizona, includes 43,380 PV modules, with a total capacity of 6 MW. TEP’s remaining 7 MW of PV solar generating capacity is located in the city of Tucson.

Power Purchase Agreements

In order to meet the ACC’s renewable energy requirements, 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. As of December 31, 2011, approximately 2 MW of contracted solar resources and 50 MW of contracted wind resources were operational. The remaining resources are expected to be developed over the next several years. The 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.

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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 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 periodically reviews its operating policies and procedures to ensure continued compliance with these standards.

Springerville Units 3 and 4

Springerville Units 3 and 4 are each approximately 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. 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.

Peak Demand and Resources

		September 30,			September 30,			September 30,			September 30,			September 30,
Peak Demand	2011			2010			2009			2008			2007
							-MW-
Retail Customers		2,334			2,333			2,354			2,376			2,386
Firm Sales to Other Utilities		322			340			385			394			369
Coincident Peak Demand (A)		2,656			2,673			2,739			2,770			2,755
Total Generating Resources		2,262			2,245			2,229			2,204			2,204
Other Resources(1)		1,009			799			781			966			785
Total TEP Resources (B)		3,271			3,044			3,010			3,170			2,989
Total Margin (B) – (A)		615			371			271			400			234
Reserve Margin (% of Coincident Peak Demand)		23	%		14	%		10	%		14	%		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 peak demand declined from 2008 to 2010 due primarily to weak economic conditions and the implementation of energy efficiency programs.

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

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the reserve margin is the ratio of margin to coincident peak demand. TEP’s reserve margin in 2011 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.

Forecasted retail peak demand for 2012 is 2,269 MW, compared with actual peak demand of 2,334 MW in 2011 when cooling degree days exceeded the ten-year average by 4%. TEP’s 2012 estimated retail peak demand is based on normal weather patterns. TEP believes existing generation capacity and power purchase agreements are sufficient to meet expected demand in 2012.

Future Generating Resources

TEP will add generating resources and/or import capability to meet forecasted retail and firm wholesale load. TEP anticipates that additional import capacity and/or additional local peaking resources of 75 to 150 MW may be required by 2018. TEP expects to add approximately 5 MW of new solar PV resources in 2012.

FUEL SUPPLY

Fuel Summary

Fuel cost and usage information is provided below:

		September 30,		September 30,		September 30,		September 30,			September 30,			September 30,
	Average Cost per MMBtu						Percentage of Total Btu
	Consumed						Consumed
	2011		2010		2009		2011			2010			2009
Coal	$	2.42	$	2.23	$	2.11		92	%		90	%		90	%
Gas	$	5.20	$	4.69	$	4.51		8	%		10	%		10	%
All Fuels	$	2.65	$	2.47	$	2.34		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 2011, 2010 and 2009 was $46.64, $41.99, and $39.81, respectively.

	September 30,		September 30,		September 30,		September 30,		September 30,
Station	Coal Supplier	2011 Coal Consumption (tons in 000’s)		Contract Expiration		Avg. Sulfur Content			Coal Obtained From (A)
Springerville	Peabody Coalsales		3,123		2020		0.9	%	Lee Ranch Coal Co.
Four Corners	BHP Billiton		387		2016		0.8	%	Navajo Indian Tribe
San Juan	San Juan Coal Co.		1,217		2017		0.8	%	Federal and State Agencies
Navajo	Peabody Coalsales		529		2019		0.4	%	Navajo and Hopi Indian Tribes
Sundt	Peabody Coalsales		265		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 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. Prior to 2010, Sundt Unit 4 was 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. Since 2010, TEP has fueled Sundt Unit 4 with both coal and natural gas depending on which resource is most economic. In 2012, TEP expects to fuel Sundt Unit 4 with natural gas. See Note 4 for more information.

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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.

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, a 75 MW internal combustion turbine. 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 also 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 effective through January 2017, with right-of-first-refusal for continuation thereafter. TEP purchases gas for its share of Luna from various suppliers in the Permian Basin region.

TRANSMISSIONACCESS

TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers. TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability, capacity 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. TEP received approval from the ACC for construction along a specific route in 2002. However, due to an impasse with the US Forest Service, UNS Electric has taken alternative steps towards improving service reliability in the area.

As of December 31, 2011, 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.

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RATES AND REGULATION

Purchased Power and Fuel Adjustment Clause

The PPFAC allows TEP to recover its fuel, transmission, and purchased power costs, including demand charges, 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 of the following year, less the base fuel, transmission, and purchased power costs 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.

• For the 12 month period ending March 31, 2012, the PPFAC rate of 0.5 cents per kWh includes a forward component charge of 0.1 cents per kWh and the true-up component charge of 0.4 cents per kWh.

As part of the reconciliation of fuel and purchased power costs and PPFAC revenues, TEP credits, among other things, 100% of short-term wholesale revenues against the recoverable costs.

As part of the 2008 Rate Order, TEP was required to credit $58 million of previously collected revenues to customers through the PPFAC. As a result, the PPFAC charge has been zero since it became effective in January 2009. As of November 2011, the $58 million was fully refunded to customers and TEP began deferring the PPFAC eligible costs until a new PPFAC rate is approved by the ACC.

In February 2012, TEP filed its annual PPFAC update report with the ACC. TEP is requesting an increase in the total PPFAC rate from approximately 0.5 cents per kWh to 0.8 cents per kWh. The proposed PPFAC rate includes a forward component charge of approximately 0.3 cents per kWh and a true-up component charge of approximately 0.5 cents per kWh. TEP’s proposed PPFAC rate, including the forward component, is expected to collect approximately $77 million of under-collected fuel and purchased power costs. If the ACC approves TEP’s PPFAC filing, it is anticipated that the new PPFAC rate would be implemented on April 1, 2012.

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 Base 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. The approved cost of carrying out those plans is recovered from retail customers through the RES surcharge. Any RES 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.

In 2011, TEP spent $34 million on its 2011 RES implementation and met the 2011 renewable energy target of 3%. TEP expects to collect $30 million in surcharges from retail customers in 2012 to implement its RES plan and expects to meet the 2012 renewable energy target of 3.5%.

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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 EE Standards designed to require TEP, UNS Electric and other affected electric utilities to implement cost-effective programs to reduce customers’ energy consumption. In 2011, TEP estimates its programs saved energy equal to 1.4% of its 2010 sales. In 2012, the EE Standards target total kWh savings of 3.0% of 2011 sales. The EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.

In January 2012, TEP filed a modification to its Energy Efficiency Implementation Plan with the ACC. The proposal includes a request for an increase in the performance incentive based on TEP’s ability to meet the EE targets for 2012 and for 2013. TEP’s proposed annual performance incentive for 2012 and 2013 ranges from $6 million to $8 million. TEP expects the ACC to issue a decision on this matter in the first quarter of 2012.

The EE Standards can be met by new and existing DSM programs, direct load control programs and energy efficient building codes. The EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s programs and rates charged to customers for such programs are subject to annual 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 Retail 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 Rules or authorizes alternative ESPs to provide retail electric service, 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. 

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TEP’S UTILITY OPERATING STATISTICS

		September 30,		September 30,			September 30,			September 30,			September 30,
	2011		2010			2009			2008			2007
Generation and Purchased Power – kWh (000)
Remote Generation		10,005,127		9,077,032			9,134,183			10,438,864			11,001,318
Local Tucson Generation (Oil, Gas & Coal)		906,496		1,492,885			1,131,399			1,016,254			1,065,778
Purchased Power		2,686,918		2,759,912			3,677,925			3,077,619			1,713,125
Total Generation and Purchased Power		13,598,541		13,329,829			13,943,507			14,532,737			13,780,221
Less Losses and Company Use		794,171		768,819			780,529			638,302			625,073
Total Energy Sold		12,804,370		12,561,010			13,162,978			13,894,435			13,155,148
Sales – kWh (000)
Residential		3,888,011		3,869,540			3,905,696			3,852,707			4,004,797
Commercial		1,972,526		1,963,469			1,988,356			2,034,453			2,057,982
Industrial		2,145,163		2,138,749			2,160,946			2,263,706			2,341,025
Mining		1,083,071		1,079,327			1,064,830			1,095,962			983,173
Public Authorities		243,336		240,703			250,915			255,817			247,430
Total – Electric Retail Sales		9,332,107		9,291,788			9,370,743			9,502,645			9,634,407
Electric Wholesale Sales		3,472,263		3,269,222			3,792,235			4,391,790			3,520,741
Total Electric Sales		12,804,370		12,561,010			13,162,978			13,894,435			13,155,148
Operating Revenues (000)
Residential	$	383,908	$	372,212		$	377,761		$	351,079		$	362,967
Commercial		223,621		217,032			219,694			211,639			213,364
Industrial		164,024		159,937			163,720			164,849			168,279
Mining		65,720		62,112			61,033			55,619			48,707
Public Authorities		20,024		19,128			19,865			19,146			18,332
RES and DSM		46,633		37,767			25,443			2,781			—
Other		—		—			—			415			4,822
Total – Electric Retail Sales		903,930		868,188			867,516			805,528			816,471
CTC To Be Refunded		—		—			—			(58,092	)		—
Wholesale Revenue- Long-Term		41,056		55,653			48,249			57,493			55,788
Wholesale Revenue- Short-Term		72,798		71,435			84,410			197,754			126,732
California Power Exchange Provision for Wholesale Refunds		—		(2,970	)		(4,172	)		—			—
Transmission		16,392		20,863			18,974			17,173			14,842
Other Revenues		122,210		112,098			84,361			72,292			56,956
Total Operating Revenues	$	1,156,386	$	1,125,267		$	1,099,338		$	1,092,148		$	1,070,789
Customers (End of Period)
Residential		367,396		366,217			365,157			363,861			361,945
Commercial		36,203		35,877			35,759			35,432			34,759
Industrial		636		635			629			633			641
Mining		2		2			2			2			2
Public Authorities		62		62			61			61			61
Total Retail Customers		404,299		402,793			401,608			399,989			397,408
Average Retail Revenue per kWh Sold (cents)
Residential		9.9		9.6			9.7			9.1			9.1
Commercial		11.3		11.1			11.0			10.4			10.4
Industrial and Mining		7.1		6.9			7.0			6.6			6.6
Average Retail Revenue per kWh Sold		9.7		9.3			9.3			8.5			8.5
Average Revenue per Residential Customer	$	1,047	$	1,018		$	1,036		$	968		$	1,009
Average kWh Sales per Residential Customer		10,606		10,579			10,708			10,621			11,129

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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 $8 million in 2011, $18 million in 2010 and $24 million in 2009 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 $7 million in 2012 and $25 million in 2013.

TEP recorded operating expenses of $12 million in 2011, $14 million in 2010 and $13 million in 2009 related to environmental compliance. TEP expects to record $14 million in operating expenses related to environmental compliance in 2012. 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 has sufficient Emission Allowances to comply with acid rain SO₂ regulations.

EPA Information Request

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

The EPA uses information obtained from such requests to determine if additional action is necessary. TEP can neither predict whether the EPA will take further action at Sundt nor 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 2009, the 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. The EPA issued the final rule in December 2011.

Navajo

Based on the EPA’s final standards, mercury and particulate emission control equipment may be required at Navajo by 2015. TEP’s share of the estimated capital cost of this equipment for Navajo is less than $1 million for mercury control and approximately $43 million if the installation of baghouses to control particulates is necessary.

Springerville

Based on the EPA’s final standards, mercury emission control equipment may be required at Springerville by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is approximately $5 million. The annual operating cost associated with the mercury emission control equipment is expected to be approximately $3 million.

San Juan

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s final standards.

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Sundt

TEP does not anticipate the final EPA rule will have a material impact on TEP’s capital expenditures related to Sundt Unit 4.

Four Corners

Based on the EPA’s final standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated capital cost of this equipment is less than $1 million. The annual operating cost associated with the mercury emission control equipment is expected to be less than $1 million.

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 2009, the 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 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.

While the debate over the direction of domestic climate policy continues on the national level, 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) which 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 2010, New Mexico adopted regulations limiting GHG emissions from power plants and providing for participation in the Western Climate Initiative. Several parties filed petitions to repeal those regulations and the New Mexico Environmental Improvement Board held hearings on the repeal petitions in November and December 2011. In February 2012, the New Mexico Environmental Improvement Board repealed some, but not all, of the GHG regulations and will deliberate on the repeal of the remaining regulations in March 2012. We cannot predict if, or when, the remaining 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 for approval. Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions. The EPA is the lead regulatory agency for these plants in terms of regional haze planning.

Compliance 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 the San Juan, Four Corners and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants. TEP cannot predict the ultimate outcome of these matters.

San Juan

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO₂ and sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (SCR) technology with sorbent injection on all four units within five years in order to reduce NOx and control sulfuric acid emissions. San Juan is able to meet the FIP’s SO₂ limit with current emissions control equipment. Based on two cost analyses commissioned by PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180 and $200 million.

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In September 2011, PNM filed a petition to review the Federal Implementation Plan with the 10th Circuit Court of Appeals challenging various aspects of that plan. In addition, PNM filed a request with the EPA to stay the five-year installation timeframe for environmental upgrades ordered by the Federal Implementation Plan until the 10th Circuit considers and rules on the petition to review.

In October 2011, PNM filed a Petition for Reconsideration of the Federal Implementation Plan. PNM also filed a Request to Stay the effective date of the final BART Federal Implementation Plan under the Clean Air Act with the EPA. In November 2011, PNM filed with the 10th Circuit a Motion to Stay the Federal Implementation Plan. WildEarth Guardians, Dine Citizens against Ruining our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance and Sierra Club were granted leave to intervene in PNM’s petition to review in the 10th Circuit. Neither the Petition in the 10th Circuit, nor the Petition for Reconsideration by the EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted leave to intervene in that appeal.

In October 2011, Governor Susana Martinez of New Mexico and the New Mexico Environment Department filed a Petition for Review of the EPA’s final Federal Implementation Plan determination in the 10th Circuit and a Petition for Reconsideration of the rule with the EPA. In November 2011, the New Mexico Governor and Environment Department filed a motion with the 10th Circuit to stay the rule. These appeals and motions are all currently pending.

Four Corners

In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that it had originally issued in 2010. If approved, the revised plan would require the installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the capital costs to install SCR is approximately $35 million.

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the National Renewable Energy Laboratory (NREL) in partnership with the Department of the Interior and the Department of Energy. The report addresses potential energy, environmental and economic issues related to compliance with the regional haze rule. The report was submitted to the EPA in January 2012. A final BART rule is expected later in 2012. If the EPA determines that SCR is required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital expenditure for the required baghouses would be approximately $43 million. The cost of required pollution controls 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 2010, the EPA published its proposed regulations governing the handling and disposal of coal ash and other coal combustion residuals (CCRs). The EPA has proposed regulating CCRs as either non-hazardous solid waste or hazardous waste. The hazardous waste alternative would require additional capital investments and operational costs associated with storage and handling at plants and transportation to the disposal locations. Both the hazardous waste and non-hazardous solid waste alternatives would require liners for new ash landfills or expansions to existing ash landfills. The rules will apply to CCRs produced by all of TEP’s coal-fired generating assets. San Juan may also be subject to separate regulations being drafted by the Office of Surface Mining Reclamation and Enforcement because it disposes of CCRs in surface mine pits.

The EPA has not yet indicated a preference for an alternative. Each option would allow CCRs to be beneficially reused or recycled as components of other products. The EPA has indicated that it will issue a final rule by the end of 2012. 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 September 2011, President Obama ordered the EPA to withdraw its reconsideration of the 2008 National Ambient Air Quality Standard for Ozone. The ozone standard is scheduled to be updated in 2013 as required by the Clean Air Act.

UNSGAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 148,000 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 60% of total revenues in 2011, while sales to other retail customer classes accounted for about 36% of total revenues.

UNS Gas’ annual retail customer growth rate was less than 1% from 2009 through 2011. In 2012, 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.

RATES AND REGULATION

2011 UNS Gas Rate Filing

Due to increases in capital and operating costs, UNS Gas filed a general rate case with the ACC in April 2011 requesting higher Base Rates. The proposed Retail Rates include a higher fixed service charge and a decoupling mechanism to assist in recovering the company’s authorized fixed costs under the EE Standards. The table below summarizes UNS Gas’ request.

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Test year – 12 months ended Dec. 31, 2010	Initial Request by UNS Gas
Original cost rate base	$184 million
Revenue deficiency	$5.6 million
Total rate increase (over test year revenues)	3.8%
Cost of equity	10.5%
Actual capital structure	51% equity / 49% debt
Weighted average cost of capital	8.7%

In January 2012, the ACC Staff filed testimony recommending a Base Rate increase of $2.7 million as well as a mechanism to enable UNS Gas to recover lost fixed-cost revenues as a result of implementing the ACC’s EE Standards. In February 2012, UNS Gas filed testimony indicating that management is willing to agree with ACC Staff’s recommendations in the context of this rate proceeding. Hearings before an ACC administrative law judge concluded in February 2012. UNS Gas expects the ACC to issue a final order in the second quarter of 2012. If the proposed Base Rate increase is approved, UNS Gas indicated that it would file a proposal with the ACC requesting to return the over-collected PGA bank balance to customers. SeePurchased Gas Adjustor (PGA),below, for more information.

2010 UNS Gas Rate Order

Effective April 2010, UNS Gas implemented a Base Rate increase of $3 million, or 2%.

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 surcredit. 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 12-month period. The annual cap on the maximum increase in the PGA factor is $0.15 per therm in a 12-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 with the ACC to determine how the over-collected balance should be returned to customers. On December 31, 2011, the PGA bank balance was over-collected by $8 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 targeted total retail therm savings equal to 0.5% of 2010 sales; UNS Gas estimates its total savings in 2011 were 0.25%. 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 Retail 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.

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ENVIRONMENTAL MATTERS

UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities. UNS Gas’ facilities are in substantial compliance with existing regulations. SeeItem. 1 – Business, TEP, Environmental Matters, for more information.

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is a vertically integrated electric utility company serving approximately 91,000 retail customers in Mohave and Santa Cruz counties. These counties have a combined population of approximately 240,000. The average number of retail customers grew by less than 1% in 2009, 2010 and 2011. We estimate that UNS Electric’s retail customer base will increase by less than 1% in 2012. UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers. Peak demand for 2011 was 438 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.

Generating Resources

UNS Electric owns and operates Black Mountain Generating Station (BMGS), a 90 MW gas-fired facility located near Kingman, Arizona. In July 2011, UNS Electric purchased BMGS from UED. UNS Gas purchases and transports natural gas to BMGS for UNS Electric under long-term natural gas transportation and sales agreements. SeeRates and Regulation, 2010 UNS Electric Rate Order, below for more information.

UNS Electric also 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 62 MW of peaking resources. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas.

Renewable Energy Resources

UNS Electric has agreed to purchase the output of a combined wind farm and solar generating facility located 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 Tariff below.

Future Generating Resources

UNS Electric invested $5 million in 2011 in company-owned solar PV capacity and expects to invest approximately $5 million annually from 2012 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 Tariff for more information.

Transmission

UNS Electric imports the power generated at BMGS 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 August 2016. 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 2016.

UNS Electric plans to upgrade the existing 115 kV transmission line serving Santa Cruz County to 138 kV by October 2014 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 Resources for more information.

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RATES AND REGULATION

2010 UNS Electric Rate Order

In 2010, the ACC authorized a Base Rate increase of $7.4 million, or 4%, effective October 1, 2010.

The 2010 UNS Electric Rate Order approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. FERC approved the purchase in June 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.

In compliance with the 2010 Rate Order, UNS Electric expects to file a rate case in the second half of 2012.

Purchased Power and Fuel Adjustment Clause

The PPFAC allows UNS Electric to recover its fuel, transmission, and purchased power costs, including demand charges, 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, transmission, and purchased power costs for the 12-month period from June 1 of the current year to May 31 of the following year, less the base fuel, transmission, and purchased power costs 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. The approved costs 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.

In 2011, UNS Electric spent $5 million on RES implementation and met the 2011 renewable energy target of 3%. UNS Electric expects to collect $8 million in surcharges from retail customers in 2012 to implement its RES plan and expects to meet the 2012 renewable energy target of 3.5%.

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.

Energy Efficiency Standards and Decoupling

In 2010, the ACC approved 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.

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ENVIRONMENTAL MATTERS

UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities. UNS Electric believes that 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.

OTHER NON-REPORTABLESEGMENTS

Millennium

As of December 31, 2011, Millennium had assets of $20 million including a $15 million note receivable (seeSabinasbelow), and cash and cash equivalents of $5 million. 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, Other Non-Reportable Business Segments,for more information.

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, which matures in June 2012.

SES

SES, a wholly owned subsidiary of Millennium, provides electrical contracting and meter reading services in Arizona, as well as other services at the Springerville Generating Station.

EMPLOYEES (Asof December 31, 2011)

TEP had 1,391 employees, of which approximately 51% 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 187 employees, of which 108 employees were represented by IBEW Local No. 1116 and 5 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 154 employees, of which 27 employees were represented by the IBEW Local No. 387 and 96 employees were represented by the IBEW Local No. 769. The existing agreements with the IBEW Local No. 387 and No. 769 expire in February 2014 and June 2013, respectively.

SES had 272 employees, of which approximately 96% are represented by unions. Of the employees represented by unions, 236 are represented by IBEW Local No. 1116 and 25 by IBEW Local No. 570; these agreements expire on December 31, 2012, and May 31, 2012, respectively.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers – UniSource Energy and 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:

	September 30,	September 30,	September 30,
Name	Age	Position(s) Held	Executive Officer Since
Paul J. Bonavia	60	Chairman and Chief Executive Officer	2009
David G. Hutchens	45	President	2007
Michael J. DeConcini	47	Senior Vice President, Operations	1999
Kevin P. Larson	55	Senior Vice President and Chief Financial Officer(1)	2000
Philip J. Dion III	43	Vice President, Public Policy	2008
Kentton C. Grant	53	Vice President, Finance and Rates(2)	2007
Todd C. Hixon	45	Vice President and General Counsel	2011
Arie Hoekstra	64	Vice President, Generation	2007
Karen G. Kissinger	57	Vice President, Controller and Chief Compliance Officer	1998
Thomas A. McKenna	63	Vice President, Engineering	2007
Catherine E. Ries	52	Vice President, Human Resources	2007
Herlinda H. Kennedy	50	Corporate Secretary	2006

(1) Mr. Larson is also Treasurer at UniSource Energy.

(2) Mr. Grant is also Treasurer at TEP.

Paul J. Bonavia	Mr. Bonavia has served as Chairman and Chief Executive Officer of UniSource Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. 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.
David G. Hutchens	Mr. Hutchens has served as President of UniSource Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UniSource Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UniSource Energy and TEP. Mr. Hutchens joined TEP in 1995.
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 from May 2009 to December 2011 when his title at TEP was changed to Senior Vice President, Operations. 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.
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.
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.

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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. Mr. Grant joined TEP in 1995.
Todd C. Hixon	Mr. Hixon has served as Vice President and General Counsel of UniSource Energy and TEP since May 2011. Mr. Hixon joined TEP’s legal department in 1998 and served in a variety of capacities, most recently serving as Associate General Counsel.
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.
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.
Thomas A. McKenna	Mr. McKenna has served as Vice President of Engineering of UniSource Energy and TEP since January 2007. 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 practical 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.

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.

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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. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 1% per year in 2008 through 2011 compared with average increases of approximately 2% per year from 2003 to 2007. In 2011, total retail kWh sales were 0.4% above 2010 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 2011 compared with average annual growth rates of 3% 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. New Base Rates would not be in effect until approval by the ACC, which is not anticipated to occur before the third quarter of 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 a 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, which are 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 reduce 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.

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.

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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.

Numerous federal, state and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste and management of coal combustion residuals.

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 new compliance standards related 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 may result in litigation, and the imposition of fines, penalties and a requirement for costly equipment upgrades 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 our facilities. 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 is 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.

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 2011, 73% 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.

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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 four 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 21, 2012, TEP had $215 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 $178 million of debt obligations and 10% on the remaining $37 million. The average weekly interest rate ranged from 0.05% to 0.34% in 2011. A 100 basis point increase in the average interest rates on this debt over a twelve-month period would increase TEP’s interest expense by approximately $2 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 2016.

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

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

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

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

The maximum amount TEP may use under its revolving credit facility is $200 million. As of February 21, 2012, TEP had $114 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

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both companies does not exceed $100 million. As of February 21, 2012, UNS Gas and UNS Electric had $64 million and $70 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, 2011, TEP and UNS Electric had posted $1 million, and $6 million, respectively, with counterparties in the form of cash or letters of credit.

UniSource Energy and its subsidiaries have 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, 2011, 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 67%. This 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:

	September 30,	September 30,
Leased Asset	Expiration	Purchase Option
Springerville Unit 1	2015	Fair market value purchase option of $159 million
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 for fair market value, with the fair market value purchase price having been determined in December 2011 through an appraisal process to be $159 million. 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 owner of Springerville Unit 3 has 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.

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 to affiliates 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; and

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• 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, TEP and UES 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 or UNS Electric’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 or UNS Electric’s generating stations operate below expectations, TEP or UNS Electric 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.

We may be subject to cyber attacks and information security risks.

As operators of critical energy infrastructure, we may face a heightened risk of cyber attack, and our corporate and informational technology systems may be vulnerable to disability or failures as a result of unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. In addition, our utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. If, despite our security measures, a significant or widely publicized breach occurred, we could have our operations disrupted, property damaged and customer information stolen; experience substantial loss of revenues, response costs and other financial loss; and be subject to increased regulation, litigation and damage to our reputation, any of which could have a negative impact on our business and results of operations.

TEP or UNS Electric might not be able to secure adequate right-of-way to construct transmission lines and distribution-related facilities, 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 and distribution-related facilities. If adequate right-of-way and siting permits to build new transmission lines cannot be secured:

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• 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 140 companies to interchange generation capacity and transmission of energy.

As of December 31, 2011, TEP owned or participated in an overhead electric transmission and distribution system consisting of:

• 512 circuit-miles of 500-kV lines;

• 1,088 circuit-miles of 345-kV lines;

• 405 circuit-miles of 138-kV lines;

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

• 2,615 circuit-miles of lower voltage primary lines.

TEP’s underground electric distribution system includes 4,389 cable-miles. TEP owns approximately 76% of the poles on which its lower voltage lines are located. Electric substation capacity consists of 103 substations with a total installed transformer capacity of 13,266,850 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, is not subject to the lien.

The electric generating stations (except as noted below), administrative 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.

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

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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 6 and Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for additional information on TEP’s capital lease obligations.

UES PROPERTIES

UNS Gas

As of December 31, 2011, UNS Gas’ transmission and distribution system consisted of approximately 31 miles of steel transmission mains, 4,220 miles of steel and plastic distribution piping, and 137,160 customer service lines.

UNS Electric

As of December 31, 2011, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 274 circuit-miles of 69-kV transmission lines, and 3,616 circuit-miles of underground and overhead distribution lines. UNS Electric also owns the 65 MW Valencia plant, the 90 MW BMGS as well as 39 substations having a total installed capacity of 1,494,000 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.

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

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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. The appeals are currently pending. TEP cannot predict the outcome of these appeals.

In addition, see legal proceedings described in Note 4.

ITEM 4. – MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Stock Trading

UniSource Energy’s common stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On February 21, 2012, the closing price was $37.76, with 8,339 shareholders of record.

TEP’s common stock is wholly-owned by UniSource Energy and is not listed for trading on any stock exchange.

Dividends

UniSource Energy

UniSource Energy’s Board of Directors expects to continue to pay regular quarterly cash dividends on our common stock; however, such dividends are subject to the Board’s evaluation of our financial condition, earnings, cash flows and dividend policy.

On February 24, 2012, UniSource Energy declared a first quarter cash dividend of $0.43 per share on its common stock. The first quarter dividend, totaling approximately $16 million, will be paid March 22, 2012, to shareholders of record at the close of business March 12, 2012. The table below summarizes UniSource Energy’s dividends paid in 2009 through 2011.

		September 30,		September 30,		September 30,
	2011		2010		2009
Quarterly Dividend Per Common Share	$	0.42	$	0.39	$	0.29
Annual Dividend Per Common Share	$	1.68	$	1.56	$	1.16
Common Stock Dividends Paid	$	62 million	$	57 million	$	41 million

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.

TEP

TEP did not pay any dividends to UniSource Energy in 2011. TEP declared and paid cash dividends to UniSource Energy of $60 million in 2010 and $60 million in 2009.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2011, TEP was in compliance with the terms of the TEP Credit Agreement.

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

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UNS Gas

UNS Gas paid dividends to UniSource Energy of $10 million in both 2011 and 2010. In February 2012, UNS Gas paid a $10 million dividend to UniSource Energy. 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, 2011, UNS Gas was in compliance with the terms of its note purchase agreement.

UNS Electric

As of December 31, 2011, UNS Electric had 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, 2011, UNS Electric was in compliance with the terms of its note purchase agreement.

Other Non-Reportable Segments

In 2011, 2010, and 2009 UED paid dividends to UniSource Energy of $39 million, $9 million and $30 million, respectively. Of those dividends paid by UED, the portions representing a return of capital were $28 million in 2011, $4 million in 2010 and $30 million in 2009.

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

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	2011						2010
Quarter:	Market Price per						Market Price per
	Share of Common Stock(1)				Dividends		Share of Common Stock(1)				Dividends
	High		Low		Declared		High		Low		Declared
First	$	37.74	$	34.84	$	0.42	$	33.54	$	29.13	$	0.39
Second		38.71		35.47		0.42		34.42		29.04		0.39
Third		38.55		34.36		0.42		33.75		29.85		0.39
Fourth		39.25		34.28		0.42		36.92		33.19		0.39
Total					$	1.68					$	1.56

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

Convertible Senior Notes

In March 2005, UniSource Energy issued $150 million of 4.50% convertible bonds due 2035. Each $1,000 of convertible bonds can be converted into 28.814 shares of UniSource Energy common stock at any time. The conversion ratio represents a conversion price of approximately $34.71 per share of common stock and is subject to adjustments including an adjustment to reduce the conversion price upon the payment of quarterly dividends in excess of $0.19 per share. As of February 21, 2012, there were $115 million of convertible bonds outstanding. SeeItem 7.- Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Convertible Senior Notes,below, for more information.

Issuer Purchases of Common Equity

UniSource Energy did not purchase any of its common stock during 2011, 2010, or 2009.

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ITEM 6. – SELECTED CONSOLIDATED FINANCIAL DATA

		September 30,			September 30,			September 30,			September 30,			September 30,
UniSource Energy	2011			2010*			2009*			2008*			2007*
	- In Thousands -
	(except per share data)
Summary of Operations
Operating Revenues	$	1,509,515		$	1,453,966		$	1,397,052		$	1,410,407		$	1,381,660
Net Income	$	109,975		$	112,984		$	105,901		$	16,955		$	60,712
Basic Earnings per Share:
Net Income	$	2.98		$	3.10		$	2.95		$	0.47		$	1.70
Diluted Earnings per Share:
Net Income	$	2.75		$	2.86		$	2.73		$	0.53		$	1.62
Shares of Common Stock Outstanding
Average		36,962			36,415			35,858			35,632			35,486
End of Year		36,918			36,542			35,851			35,458			35,315
Year-end Book Value per Share	$	24.07		$	22.73		$	21.18		$	19.35		$	19.65
Cash Dividends Declared per Share	$	1.68		$	1.56		$	1.16		$	0.96		$	0.90
Financial Position
Total Utility Plant – Net	$	3,182,263		$	2,961,498		$	2,785,714		$	2,617,693		$	2,407,295
Investments in Lease Debt and Equity	$	65,829		$	103,844		$	132,168		$	126,672		$	152,544
Other Investments and Other Property	$	34,205		$	61,676		$	60,239		$	64,096		$	70,677
Total Assets	$	3,985,231		$	3,791,243		$	3,610,065		$	3,503,821		$	3,189,747
Long-Term Debt	$	1,517,373		$	1,352,977		$	1,307,795		$	1,313,615		$	993,870
Non-Current Capital Lease Obligations		352,720			429,074			488,349			513,517			530,973
Common Stock Equity		888,474			830,756			759,329			686,090			693,958
Total Capitalization	$	2,758,567		$	2,612,807		$	2,555,473		$	2,513,222		$	2,218,801
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	337,320		$	346,920		$	347,310		$	273,767		$	320,642
Capital Expenditures	$	(374,122	)	$	(330,629	)	$	(294,020	)	$	(354,080	)	$	(243,242	)
Other Investing Cash Flows(1)		47,034			25,569			(2,624	)		(95,493	)		27,961
Net Cash Flows From Investing Activities	$	(327,088	)	$	(305,060	)	$	(296,644	)	$	(449,573	)	$	(215,281	)
Net Cash Flows From Financing Activities	$	(1,441	)	$	(51,183	)	$	(28,916	)	$	140,605		$	(119,229	)
Ratio of Earnings to Fixed Charges(2)		2.46			2.64			2.48			1.28			1.71

K-31

		September 30,			September 30,			September 30,			September 30,			September 30,
TEP	2011			2010*			2009*			2008*			2007*
	-Thousands of Dollars-
Summary of Operations
Operating Revenues	$	1,156,386		$	1,125,267		$	1,099,338		$	1,092,148		$	1,070,789
Net Income	$	85,334		$	108,260		$	90,688		$	7,206		$	55,591
Financial Position
Total Utility Plant – Net	$	2,650,652		$	2,410,077		$	2,261,325		$	2,120,619		$	1,957,506
Investments in Lease Debt and Equity		65,829			103,844			132,168			126,672			152,544
Other Investments and Other Property		32,313			43,588			31,813			31,291			35,460
Total Assets	$	3,275,484		$	3,075,978		$	2,922,062		$	2,847,408		$	2,567,808
Long-Term Debt	$	1,080,373		$	1,003,615		$	903,615		$	903,615		$	682,870
Non-Current Capital Lease Obligations		352,720			429,074			488,311			513,370			530,714
Common Stock Equity		824,943			709,884			650,591			589,613			580,512
Total Capitalization	$	2,258,036		$	2,142,573		$	2,042,517		$	2,006,598		$	1,794,096
Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	268,294		$	302,483		$	268,064		$	265,756		$	262,714
Capital Expenditures	$	(351,890	)	$	(277,309	)	$	(240,079	)	$	(291,990	)	$	(161,141	)
Other Investing Cash Flows(1)		39,879			24,273			(9,522	)		(95,814	)		25,414
Net Cash Flows From Investing Activities	$	(312,011	)	$	(253,036	)	$	(249,601	)	$	(387,804	)	$	(135,727	)
Net Cash Flows From Financing Activities	$	51,452		$	(51,882	)	$	(29,320	)	$	128,713		$	(120,088	)
Ratio of Earnings to Fixed Charges(2)		2.42			2.76			2.58			1.18			1.78

* As revised. See Note 1 to the financial statements for more information.

⁽¹⁾  Other Investing Cash Flows in 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, interest on operating lease payments, and expense on indebtedness.

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

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

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

• outlook and strategies;

• operating results during 2011 compared with 2010, and 2010 compared with 2009;

• factors which affect our results and outlook;

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

• dividends; and

• critical accounting policies.

UniSource Energy Corporation (UniSource Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UniSource Energy’s subsidiaries 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 82% of UniSource Energy’s total assets as of December 31, 2011. TEP generates, transmits and distributes electricity to approximately 404,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily 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 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 regulated gas distribution company with approximately 148,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated vertically integrated public utility with approximately 91,000 retail customers in Mohave and Santa Cruz counties.

UED developed the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility includes two natural gas-fired combustion turbines. Prior to July 2011, UNS Electric received energy from BMGS through a power sales agreement with UED. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no impact on UniSource Energy’s consolidated financial statements.

Millennium’s investments in unregulated businesses represent less than 1% of UniSource Energy’s assets as of December 31, 2011.

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

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

UNISOURCE ENERGY CONSOLIDATED

OUTLOOK AND STRATEGIES

Our financial prospects and outlook are affected by many factors including: the TEP 2008 Rate Order that freezes Base Rates through 2012; national and regional economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:

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

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• 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.

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

• Developing strategic responses to Arizona’s Energy Efficiency Standards that protect the financial stability of our utility businesses and provide benefits to our customers.

RESULTS OF OPERATIONS

Contribution by Business Segment

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

		September 30,			September 30,			September 30,
	2011			2010			2009
TEP	$	85		$	108		$	91
UNS Gas		10			9			7
UNS Electric		18			15			11
Other Non-Reportable Segments and Adj.(1)		(3	)		(19	)		(3	)
Consolidated Net Income	$	110		$	113		$	106

⁽¹⁾ Includes: UniSource Energy parent company expenses; Millennium; and UED.

Revision of Prior Period Financial Statements

In the second and third quarters of 2011, we identified errors related to amounts recorded, at their dollar value, owed to or payable by TEP for electricity deliveries settled in-kind or to be settled in-kind during prior years under three of our transmission agreements. In the second quarter of 2011, we also identified errors in prior years in the calculation of income tax expense arising from not treating Allowance for Equity Funds Used During Construction (AFUDC) as a permanent book to tax difference.

We assessed the materiality of these errors on prior period financial statements and concluded they were not material to any prior annual or interim periods; however, the cumulative impact, if recognized in 2011, could be material to results in 2011. In accordance with Staff Accounting Bulletin 108 and as set forth in Note 1 to the Financial Statements in our Quarterly Report on Form 10-Q for the quarters ended June 30, 2011, and September 30, 2011, we revised our prior period financial statements to correct these errors. See Note 1 for more information.

Executive Overview

2011 Compared with 2010

TEP

TEP reported net income of $85 million in 2011 compared with $108 million in 2010. The decrease in net income was due primarily to: a decline in long-term wholesale margin revenues; a decrease in wholesale transmission revenues; an increase in Base O&M; higher depreciation expense; and an increase in interest expense. Those factors were partially offset by the recognition of a gain related to the settlement of a dispute with El Paso Electric. SeeTucson Electric Power, Results of Operationsbelow for more information.

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UNS Gas and UNS Electric

UNS Gas reported net income of $10 million in 2011 compared with net income of $9 million in 2010. SeeUNS Gas, Results of Operations,below for more information.

UNS Electric reported net income of $18 million in 2011 compared with net income of $15 million in 2010. The increase is due in part to a Base Rate increase that took effect in October 2010. SeeUNS Electric, Results of Operations,below for more information.

Other Non-Reportable Segments

Millennium’s financial results are included in UniSource Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in 2011 compared with a net loss of $13 million in 2010. Millennium’s results in the 2010 reflect losses related to the write-off of deferred taxes and impairment losses. SeeOther Non-Reportable Segments, Results of Operations,below, for more information.

2010 Compared with 2009

TEP

TEP reported net income of $108 million in 2010 compared with net income of $91 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 O&M resulting from a decline in planned power plant maintenance outages, cost-containment efforts and lower pension and post retirement medical expense; and a $5 million decrease in retail margin revenues resulting from a 0.8% decrease in retail kWh sales.

UNS Gas and UNS Electric

UNS Gas reported net income of $9 million in 2010 compared with $7 million in 2009. The increase was due primarily to an increase in retail sales due to colder winter weather and an increase in Base Rates that took effect in April 2010.

UNS Electric reported net income of $15 million in 2010 compared with $11 million in 2009. The increase was due primarily to an increase in demand from a mining customer; the addition of a new industrial customer; and an increase in Base 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.

Other Non-Reportable Segments

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.

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O&M

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

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
TEP Base O&M (non-GAAP)(1)	$	237		$	228		$	231
UNS Gas Base O&M (non-GAAP)(1)		24			25			25
UNS Electric Base O&M (non-GAAP)(1)		20			21			21
Consolidating Adjustments and Other(2)		(11	)		(9	)		(7	)
UniSource Energy Base O&M (non-GAAP)		270			265			270
Reimbursed Expenses Related to Springerville Units 3 & 4		63			65			41
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management Programs		46			40			23
Total UniSource Energy O&M (GAAP)	$	379		$	370		$	334

⁽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. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.

⁽²⁾  Includes Millennium, UED, and UniSource Energy stand-alone O&M, and inter-company eliminations.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Dividends from UniSource Energy’s subsidiaries, primarily TEP, represent the parent company’s main source of liquidity. 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 and each of its segments.

		September 30,			September 30,		September 30,
Balances as of February 21, 2012	Cash and Cash Equivalents			Borrowings under Revolving Credit Facility(1)		Amount Available under Revolving Credit Facility
	-Millions of Dollars-
UniSource Energy Stand-Alone	$	5		$	52	$	73
TEP		21			86		114
UNS Gas		40			—		70	(2)
UNS Electric		6			6		64	(2)
Other		6	(3)		N/A		N/A
Total	$	78

⁽¹⁾  Includes LOCs issued under revolving credit facilities.

⁽²⁾ Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both companies cannot exceed $100 million.

⁽³⁾ Includes cash and cash equivalents at Millennium and UED.

Short-term Investments

UniSource Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update this policy in response to market conditions. As of December 31, 2011, UniSource Energy’s short-term investments included 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.

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Access to Revolving Credit Facilities

UniSource Energy and its three primary subsidiaries have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. 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 Credit Agreement also may be used to issue letters of credit for general corporate purposes.

We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. SeeItem 7A.Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Liquidity Outlook

In November 2011, UniSource Energy, TEP, UNS Gas, and UNS Electric each amended and extended their respective Credit Agreements that were due to expire in 2014 to extend the expiration dates to November 2016.

UniSource Energy Consolidated Cash Flows

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
Operating Activities	$	337		$	347		$	347
Investing Activities		(327	)		(305	)		(297	)
Financing Activities		(1	)		(51	)		(29	)

UniSource Energy’s operating cash flows are generated primarily by the 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. UniSource Energy, TEP, UNS Gas and UNS Electric use their revolving credit facilities to fund their business activities during periods when sales are seasonally lower.

Capital expenditures at TEP, UNS Gas and UNS Electric represent the primary use of cash for investing activities. 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 2011, net cash flows from operating activities were $10 million lower than they were in 2010 due to:

• a $32 million increase in O&M costs due in part to higher planned generating plant outage costs, higher up-front incentive payments for customer-installed solar systems, and higher DSM payments; and

• a $17 million increase in taxes other than income taxes paid due to a higher sales tax rate effective in June 2010 and sales taxes paid on higher retail kWh sales;

partially offset by

• a $14 million increase in cash receipts from electric and gas sales, net of fuel and purchased energy costs. The increase was due in part to: a Base Rate increase at UNS Gas in April 2010; a Base Rate increase at UNS Electric in October 2010; an increase in retail electric sales; higher fuel and purchased power cost recoveries from UNS Electric customers; and higher sales tax collections from customers resulting from a 1% increase in the sales tax rate that took effect in June 2010; and

• a $26 million decrease in income taxes paid net of income tax refunds due to lower taxable income resulting from bonus depreciation deductions.

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Investing Activities

Net cash flows used for investing activities increased by $22 million in 2011. Capital expenditures during 2011 were $374 million compared with $331 million last year. TEP’s 2011 capital expenditures include $85 million related to construction of a new administrative headquarters. Capital expenditures in 2010 included the purchase of Sundt Unit 4 by TEP for $51 million. Investing activities in 2011 included a $13 million increase in proceeds from investments in Springerville lease debt.

Capital Expenditures Forecast

		September 30,			September 30,		September 30,		September 30,		September 30,		September 30,
	Actual			Estimated
	2011			2012		2013		2014		2015		2016
				-Millions of Dollars-
TEP	$	352		$	289	$	346	$	379	$	331	$	418
UNS Gas		13			11		12		13		14		14
UNS Electric (1)		33			34		41		41		31		35
Consolidating Adjustments (2)		(24	)		—		—		—		—		—
UniSource Energy Consolidated	$	374		$	334	$	399	$	433	$	376	$	467

(1) UNS Electric purchased BMGS from UED for approximately $63 million in 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,below, for more information.

(2) Consolidating adjustments of approximately $24 million represent costs incurred during 2010 at UniSource Energy for the construction of a new administrative headquarters building. These costs were reimbursed to UniSource Energy when TEP purchased the building in November 2011.

TEP’s estimated capital expenditures exclude the potential purchase of interests in Springerville Unit 1 for $159 million and the potential purchase of interests in the Springerville Coal Handling Facilities for $120 million upon the expiration of their respective leases in January 2015.

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 flows used for financing activities were $50 million lower in 2011 compared with 2010 primarily due to:

• a $16 million increase in proceeds from the issuance of long-term debt (net of long-term debt repayments and issuance/retirement costs);

• a $70 million increase in borrowings (net of repayments) under revolving credit facilities;

partially offset by

• an $18 million increase in payments on capital lease obligations;

• a $5 million increase in common stock dividends paid; and

• a $7 million decrease in cash from other financing activities.

Capital Contributions

In July 2011, UniSource Energy contributed $20 million in capital to UNS Electric to help fund its purchase of BMGS from UED.

In December 2011, UniSource Energy contributed $30 million in capital to TEP.

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

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

UniSource Credit Agreement

In November 2011, UniSource Energy amended its existing credit agreement (the UniSource Credit Agreement). The UniSource Credit Agreement consists of a $125 million revolving credit and revolving letter of credit facility. The amendment extended the term of the UniSource Credit Agreement by two years to November 2016. As of December 31, 2011, there was $57 million outstanding at a weighted average interest rate of 2.0%.

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 stand-alone basis. Additionally, UniSource Energy cannot 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, 2011, 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. UniSource Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if LIBOR and other benchmark interest rates increase. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Convertible Senior Notes

In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035. Each $1,000 of Convertible Senior Notes can be converted into 28.814 shares of UniSource Energy common stock at any time. The conversion ratio represents a conversion price of approximately $34.71 per share of common stock and is subject to adjustments including an adjustment to reduce the conversion price upon the payment of quarterly dividends in excess of $0.19 per share.

On December 28, 2011, UniSource Energy gave notice of a partial redemption of the Convertible Senior Notes by calling $35 million of the $150 million outstanding. The redemption period ended on January 12, 2012. Holders of the called Convertible Senior Notes had the option of converting their interests to common stock or redeeming the Convertible Senior Notes at par plus accrued interest. The notes were convertible into shares of UniSource Energy’s common stock at a conversion rate of 28.814 shares per $1,000 principal amount of Convertible Senior Notes. Approximately $33.5 million of the Convertible Senior Notes selected for redemption converted their interests into approximately 964,000 shares of UniSource Energy’s common stock. The remaining $1.5 million was redeemed for cash on January 12, 2012.

The closing price of UniSource Energy’s Common Stock was $37.76 on February 21, 2012.

UniSource Energy has the option to redeem the remaining Convertible Senior 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 Convertible Senior Notes will have the right to require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain specified fundamental changes involving UniSource Energy occur. The repurchase price will be 100% of the principal amount of the remaining notes plus accrued and unpaid interest.

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Contractual Obligations

The following chart displays UniSource Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2011.

		000000		000000		000000		000000		000000		000000		000000		000000
UniSource Energy’s Contractual Obligations - Millions of Dollars -
Payment Due in Years Ending December 31,	2012		2013		2014		2015		2016		2017 and after		Other		Total
Long Term Debt
Principal(1) (9)	$	—	$	—	$	37	$	130	$	235	$	1,115	$	—	$	1,517
Interest(2)		73		73		73		73		67		728		—		1,087
Capital Lease Obligations(3)		118		122		195		23		18		61		—		537
Operating Leases		2		2		2		1		1		10		—		18
Purchase Obligations:
Fuel(4)		107		71		68		50		47		96		—		439
Purchased Power		83		61		48		16		16		227		—		451
Transmission		7		5		5		4		4		23		—		48
Other Long-Term Liabilities(5):
Pension & Other Post Retirement Obligations(6)		28		5		6		6		6		34		—		85
Acquisition of Springerville Coal Handling and Common Facilities(7)		—		—		—		120		—		106		—		226
Solar Equipment(8)		12		12		—		—		—		—		—		24
Unrecognized Tax Benefits		—		—		—		—		—		—		29		29
Total Contractual Cash Obligations	$	430	$	351	$	434	$	423	$	394	$	2,400	$	29	$	4,461

⁽¹⁾  TEP’s variable rate IDBs are secured by letters of credit issued pursuant to the TEP Credit Agreement, which expires in 2016, and 2010 Reimbursement Agreement, which expires in 2014. Although the variable rate IDBs mature between 2018 and 2032, the above maturity reflects a redemption or repurchase of such bonds as though the letters of credit terminate without replacement upon expiration of the TEP Credit Agreement in 2016 and the 2010 Reimbursement Agreement in 2014.

⁽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’s and UES’ expected contributions to pension plans in 2012, 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 2012 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 2012 obligation includes expected VEBA contributions. VEBA contributions for periods beyond 2012 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.

⁽⁸⁾  TEP has a commitment to purchase 9 MW of photovoltaic equipment through December 2013. 6 MW were approved by the ACC, and 3 MW remain subject to ACC approval, which is expected in the fourth quarter of 2012.

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⁽⁹⁾  In January 2012, UniSource Energy redeemed $35 million of its convertible senior notes. Pursuant to the redemption, substantially all of the notes were converted into approximately 1 million shares of UniSource Energy Common Stock.

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 24, 2012, UniSource Energy declared a first quarter cash dividend of $0.43 per share on its common stock. The first quarter dividend, totaling approximately $16 million, will be paid March 22, 2012 to shareholders of record at the close of business March 12, 2012. The table below summarizes UniSource Energy’s dividends paid in 2009 through 2011.

		September 30,		September 30,		September 30,
	2011		2010		2009
Quarterly Dividend Per Common Share	$	0.42	$	0.39	$	0.29
Annual Dividend Per Common Share	$	1.68	$	1.56	$	1.16
Common Stock Dividends Paid	$	62 million	$	57 million	$	41 million

Income Tax Position

As of December 31, 2011, UniSource Energy and TEP had the following carry-forward amounts:

		September 30,		September 30,		September 30,		September 30,
	UniSource Energy				TEP
	Amount		Expiring Year		Amount		Expiring Year
	-Amounts in Millions of Dollars-
Capital Loss	$	8		2015	$	—		—
Federal Net Operating Loss		230		2031		212		2031
State Net Operating Loss		—		2016		13		2016
State Credits		1		2016		2		2016
AMT Credit		43		None		25		None

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. The same law makes qualified property placed in service during 2012 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 did not pay any federal income taxes for the tax year 2011 and does not expect to pay any federal income taxes for 2012.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

Executive Summary

TEP’s financial condition and results of operations 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.

2011 Compared with 2010

TEP recorded net income of $85 million in 2011 compared with $108 million in 2010. The following factors contributed to the decrease in TEP’s net income:

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• a $15 million decline in long-term wholesale margin revenues resulting primarily from a change in the pricing of energy sold under the SRP wholesale contract effective June 1, 2011;

• a $5 million decrease in wholesale transmission revenues. In the first quarter of 2010, transmission revenues benefitted from the temporary sale of transmission capacity to SRP;

• an $9 million increase in Base O&M primarily due to TEP’s share of planned generating plant maintenance expense at San Juan; and

• a $5 million increase in depreciation expense as a result of an increase in plant-in-service;

partially offset by

• a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric; and

• a $3 million loss recorded in 2010 related to the settlement of disputed wholesale power transactions.

2010 Compared with 2009

TEP recorded net income of $108 million in 2010 compared with net income of $91 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;

• 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,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:

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• 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 2009.

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.

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.

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.

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		September 30,		September 30,		September 30,			September 30,		September 30,
Energy Sales, kWh (in millions)	2011		2010		2011 vs. 2010 % Change*			2009		2010 vs. 2009 % Change*
Electric Retail Sales:
Residential		3,888		3,870		0.5	%		3,906		(0.9	%)
Commercial		1,973		1,963		0.5	%		1,988		(1.3	%)
Industrial		2,145		2,139		0.3	%		2,161		(1.0	%)
Mining		1,083		1,079		0.3	%		1,065		1.4	%
Public Authorities		243		241		1.1	%		251		(4.1	%)
Total Electric Retail Sales		9,332		9,292		0.4	%		9,371		(0.8	%)
Retail Margin Revenues (in millions):
Residential	$	252	$	252		0.2	%	$	254		(0.9	%)
Commercial		160		159		0.6	%		160		(0.5	%)
Industrial		95		97		(2.1	%)		100		(3.1	%)
Mining		32		31		1.9	%		30		3.0	%
Public Authorities		12		12		0.8	%		12		(2.4	%)
Total Retail Margin Revenues (Non-GAAP)**	$	551	$	551		0.0	%	$	556		(1.0	%)
PPFAC Revenues		307		279		9.6	%		287		(2.2	%)
RES and DSM Revenues		46		38		23.3	%		25		48.8	%
Total Retail Revenues (GAAP)	$	904	$	868		4.1	%	$	868		0.1	%
Avg. Retail Margin Revenue (cents / kWh):
Residential		6.48		6.50		(0.3	%)		6.49		0.2	%
Commercial		8.11		8.10		0.1	%		8.04		0.8	%
Industrial		4.42		4.53		(2.4	%)		4.62		(2.1	%)
Mining		2.92		2.87		1.7	%		2.82		1.6	%
Public Authorities		5.05		5.07		(0.4	%)		4.98		1.7	%
Avg. Retail Margin Revenue / kWh		5.90		5.93		(0.5	%)		5.93		(0.1	%)
Avg. PPFAC Revenue / kWh		3.29		3.01		9.3	%		3.05		(1.4	%)
Avg. RES & DSM Revenue / kWh		0.50		0.41		22.0	%		0.27		50.0	%
Total Avg. Retail Revenue / kWh		9.69		9.35		3.7	%		9.25		0.9	%
Cooling Degree Days
Actual		1,528		1,543		(1.0	%)		1,599		(3.5	%)
10-Year Average		1,473		1,468		NM			1,469		NM
Heating Degree Days
Actual		1,597		1,469		8.7	%		1,287		14.1	%
10-Year Average		1,417		1,430		NM			1,434		NM

* 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. Retail Margin Revenues excludes: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business.

Residential

In 2011, residential kWh sales increased by 0.5% compared with 2010 due in part to a 0.2% increase in the number of residential customers. Residential margin revenues in 2011 were unchanged compared with 2010.

Commercial

Commercial kWh sales increased by 0.5% compared with 2010 due primarily to a 0.6% increase in the number of commercial customers. Commercial margin revenues increased by $1 million, or 0.6%, compared with 2010.

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Industrial

Industrial kWh sales increased by 0.3% in 2011 compared with 2010, while margin revenues declined by 2.1%. The decline in margin revenues, despite higher kWh sales, resulted from a change in usage patterns by certain industrial customers that reduced their demand charges paid to TEP.

Mining

The continuation of high copper prices led to increased mining activity, resulting in a 0.3% increase in sales volumes in 2011 compared with 2010. Margin revenues from mining customers increased by 1.9% over 2010, due to higher energy consumption and changing usage patterns which resulted in higher demand charges paid to TEP.

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.

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.

Wholesale Sales and Transmission Revenues

		September 30,		September 30,		September 30,
	2011		2010		2009
Long-Term Wholesale Revenues:	-Millions of Dollars-
Long-Term Wholesale Margin Revenues (Non-GAAP)*	$	13	$	28	$	25
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues		28		28		23
Total Long-Term Wholesale Revenues	$	41	$	56	$	48
Transmission Revenues		16		21		19
Short-Term Wholesale Revenues		73		64		86
Electric Wholesale Sales (GAAP)	$	130	$	141	$	153

* Long-Term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change in Long-Term Wholesale Margin Revenues between periods provides useful information to investors because it demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business.

Long-term wholesale margin revenues from long-term wholesale contracts were $15 million lower than in 2010. The decrease was due primarily to a change in pricing under the SRP contract. SeeFactors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project, below, for more information.

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Wholesale transmission revenues in 2011 decreased by $5 million compared with 2010. In 2010, TEP provided short-term transmission capacity to SRP for Springerville Unit 4.

TEP credits all revenues from short-term wholesale sales and 90% of the margin on wholesale trading activity against the fuel and purchased power costs eligible for recovery in the PPFAC. There was no wholesale trading activity in 2009, 2010 and 2011.

In April 2010, TEP settled all remaining claims arising from 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.

Other Revenues

		September 30,		September 30,		September 30,
	2011		2010		2009
	-Millions of Dollars-
Revenue related to Springerville Units 3 and 4(1)	$	97	$	97	$	60
Other Revenue		26		22		23
Total Other Revenue	$	123	$	119	$	83

⁽¹⁾  Represents reimbursements for expenses incurred by TEP related to the operation of Springerville Units 3 and 4.

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

2011 Compared with 2010

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for 2011, 2010 and 2009 are detailed below:

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
TEP	Generation and Purchased Power									Fuel and Purchased Power Expense
	2011			2010			2009			2011			2010			2009
	-Millions of kWh-									-Millions of Dollars-
Coal-Fired Generation		9,946			9,481			9,272		$	254		$	217		$	198
Gas-Fired Generation		929			1,078			992			55			60			76
Renewable Generation		37			32			30			—			—			—
Total Generation		10,912			10,591			10,294			309			277			274
Purchased Power		2,687			2,846			3,810			106			119			145
Reimbursed Fuel Expense		—			—			—			8			7			5
Transmission		—			—			—			(1	)		3			3
Increase (Decrease) to Reflect PPFAC Treatment		—			—			—			(6	)		(21	)		(18	)
Total Resources		13,599			13,437			14,104		$	416		$	385		$	409
Less Line Losses and Company Use		(795	)		(876	)		(941	)
Total Energy Sold		12,804			12,561			13,163

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Generation

Total generating output increased during 2011 compared with 2010. The higher output was primarily due to the increased availability of TEP’s largest coal-fired generating plants, Springerville Units 1 and 2. In 2010, Springerville Units 1 and 2 experienced unplanned outages, in addition to a planned maintenance outage at Springerville Unit 1.

Purchased Power

Purchased power volumes decreased in 2011 compared with 2010. The lower volume of power purchases was primarily due to the increased availability of TEP’s coal-fired generating resources.

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

		September 30,		September 30,		September 30,
	2011		2010		2009
	-cents per kWh generated-
Coal		2.56		2.29		2.14
Gas		5.99		5.58		7.66
Purchased Power		3.94		4.17		3.79

Market Prices

As a participant in the western U.S. wholesale power markets, TEP is affected by changes in market conditions. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during 2012.

		September 30,
Average Market Price for Around-the-Clock Energy	$/MWh
2011	$	30
2010		34
2009	$	30

		September 30,
Average Market Price for Natural Gas	$/MMBtu
2011	$	3.89
2010		4.18
2009	$	3.34

O&M

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

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
Base O&M (Non-GAAP)(1)	$	237		$	228		$	231
O&M recorded in Other Expense		(8	)		(7	)		(7	)
Reimbursed expenses related to Springerville Units 3 and 4		63			65			41
Expenses related to customer funded renewable energy and DSM programs		39			31			18
Total O&M (GAAP)	$	331		$	317		$	283

⁽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. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.

TEP’s base O&M expense in 2011 was $237 million, or $9 million above 2010. The increase is due primarily to unplanned outages at San Juan in 2011.

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Income Tax Expense

In 2011, TEP’s effective tax rate was 38% compared with 36% in 2010. The increase is primarily due to a decrease in federal deductions along with federal and state tax credits. See Note 8 for more information.

2010 Compared with 2009

Generation

Coal-related fuel expense in 2010 increased by $19 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.

Purchased Power

Purchased power volumes and expense during 2010 were lower than 2009 due to a decrease in short-term wholesale sales activity, an increase in coal-fired generating output, and a decline in retail sales volumes.

O&M

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.

FACTORS AFFECTING RESULTS OF OPERATIONS

Base Rate Increase Moratorium

Pursuant to the 2008 TEP Rate Order, TEP’s Base Rates are frozen through at least 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 change under 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.

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 2011 and 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.

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
Other Revenues	$	97		$	97		$	60
Fuel Expense		(8	)		(7	)		(5	)
Operations and Maintenance Expense		(63	)		(65	)		(41	)
Taxes Other Than Income Taxes		(2	)		(1	)		(1	)
Total Pre-Tax Income	$	24		$	24		$	13

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Pension and Postretirement Benefit Expense

The table below summarizes TEP’s pension and other postretirement benefit expenses charged to O&M in 2009, 2010, and 2011. See Note 9 for more information.

		September 30,		September 30,		September 30,
	2011		2010		2009
	-Millions of Dollars-
Pension Expense Charged to O&M	$	10	$	9	$	12
Other Postretirement Benefit Expense Charged to O&M		4		4		4
Total	$	14	$	13	$	16

In 2012, TEP expects to charge $10 million of pension and $5 million of other postretirement benefit expense to O&M.

Long-Term Wholesale Sales

In 2011 and 2010, TEP’s margin on long-term wholesale sales was $13 million and $28 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 received a monthly demand charge of approximately $1.8 million, or $22 million annually, and sold the energy at a price based on TEP’s average fuel cost. From June 1, 2011 to December 31, 2011, SRP was required to purchase 73,000 MWh per month. From January 1, 2012 through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the price of on-peak power on Palo Verde Market Index. As of February 21, 2012, the average forward price of on-peak power on the Palo Verde Market Index for the calendar year 2012 was $30.33 MWh.

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 2011, approximately 12% of the total energy sold to NTUA was priced based on the Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA.

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

Electric Energy Efficiency Standards (EE 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 programs to reduce customers’ energy consumption. In 2011, TEP’s programs saved energy equal to approximately 1.4% of its 2010 sales. In 2012, the EE Standards target total kWh savings of 3% of 2011 sales. The EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.

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

In January 2012, TEP filed a modification to its Energy Efficiency Implementation Plan with the ACC. The proposal includes a request for an increase in the performance incentive based on TEP’s ability to meet the EE targets for 2012 and for 2013. TEP’s proposed annual performance incentive for 2012 and 2013 ranges from $6 million to $8 million. TEP expects the ACC to issue a decision on this matter in the first quarter of 2012.

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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 Retail 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.

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, Electric Energy Efficiency Standards and Decoupling for more information.

Renewable Energy Standard and Tariff

In 2010, the ACC approved a funding mechanism that allows TEP to recover operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through RES funds until such costs are reflected in 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. During 2011, TEP earned approximately $1 million pre-tax on its 2010 investment in solar projects. In accordance with the funding mechanism approved by the ACC in 2010, TEP could earn approximately $1 million pre-tax in 2012 on solar investments made in 2010 and 2011.

In December 2011, the ACC approved TEP’s RES implementation plan including investments of $28 million in 2012 and $8 million in 2013 for company-owned solar projects. In 2011, TEP’s renewable energy investments totaled $28 million. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $1 million pre-tax in 2012 on solar investments made in 2010 and 2011 and approximately $4 million pre-tax in 2013. For more information seeItem 1. Business, TEP, Rates and Regulation, Renewable Energy Standard and Tariff.

Sales to Mining Customers

The continuation of copper prices of $3 per pound 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 2011, sales to TEP’s mining customers increased 0.3% compared with 2010 and represented 11% of TEP’s total retail kWh sales and 6% of total retail margin 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. The Rosemont mine requires electric service from TEP via a 138kV transmission line for the construction and ongoing operation of the mine. A certificate of environmental compatibility (CEC) from the ACC’s line siting committee was approved in December 2011 for the 138 kV transmission line. Appeals have been filed relative to the issuance of the CEC. 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.

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Interest Rates

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, 2011 TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds is 10% on the $37 million of bonds and 20% on the other $178 million. During 2011, the average rates paid ranged from 0.05% to 0.34%. At February 21, 2012, the average rate on the debt was 0.26%.

TEP has a fixed-for-floating interest rate swap in place to hedge $50 million of its variable rate IDBs.

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.

San Juan Mine Fire

In September 2011, a fire at the underground mine that provides coal to San Juan caused mining operations to shut down. TEP owns approximately 20% of San Juan, which is operated by PNM. As we are unable to predict when operations will resume at the mine, we and the other owners of San Juan are considering alternatives for operating the facility.

However, based on information we have received to date, we do not expect the mine fire to have a material effect on our financial condition, results of operations, or cash flows due to the current inventory of previously mined coal and the current low market price of wholesale power. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers through the PPFAC, subject to ACC approval.

Fair Value Measurements

TEP’s income statement exposure to risk is mitigated as TEP reports the change in fair value of energy contract derivatives 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:

		September 30,			September 30,			September 30,
	2011			2010			2009
Net Cash Flows – Operating Activities (GAAP)	$	268		$	302		$	268
Amounts from Statements of Cash Flows:
Less: Capital Expenditures(1)		(352	)		(277	)		(240	)
Net Cash Flows after Capital Expenditures (Non-GAAP)*		(84	)		25			28
Amounts From Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations		(74	)		(56	)		(24	)
Plus: Proceeds from Investment in Lease Debt		38			26			13
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)*	$	(120	)	$	(5	)	$	17

(1) 2010 includes a $51 million payment for the purchase of Sundt Unit 4 lease equity.

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		September 30,			September 30,			September 30,
	2011			2010			2009
Net Cash Flows – Operating Activities (GAAP)	$	268		$	302		$	268
Net Cash Flows – Investing Activities (GAAP)		(312	)		(253	)		(250	)
Net Cash Flows – Financing Activities (GAAP)		51			(52	)		(29	)
Net Cash Flows after Capital Expenditures (Non-GAAP)*		(84	)		25			28
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)*		(120	)		(5	)		17

* Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations, 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. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make required principal payments on debt and capital lease obligations (net), and pay dividends to UniSource Energy.

Liquidity Outlook

During 2012, 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 2011, net cash flows from operating activities decreased by $34 million compared with 2010. Net cash flows were impacted by:

• a $38 million increase in O&M costs due in part to higher generating plant outage costs, higher up-front incentive payments for customer-installed solar systems, and higher DSM payments;

• a $5 million increase in taxes other than income taxes due to a higher sales tax rate effective in June 2010 and sales taxes paid on higher retail kWh sales; and

• a $10 million decrease in cash receipts from electric sales, net of fuel and purchased power costs. This decrease was due to higher coal costs and lower long-term wholesale margins compared with 2010;

partially offset by

• a $17 million decrease in income taxes paid due to lower taxable income resulting from bonus depreciation deductions.

Investing Activities

Net cash flows used for investing activities increased by $59 million in 2011 compared with 2010. Capital expenditures during 2011 were $75 million higher than in 2010, which was partially offset by a $13 million increase in proceeds from the return of investment in Springerville lease debt.

Capital Expenditures

TEP’s forecasted capital expenditures are summarized below:

		September 30,		September 30,		September 30,		September 30,		September 30,
	2012		2013		2014		2015		2016
	-Millions of Dollars-
Transmission and Distribution	$	158	$	179	$	129	$	99	$	118
Generation Facilities		57		80		93		72		169
Renewable Energy Generation		32		30		30		30		30
Environmental		2		19		89		94		64
General and Other		40		38		38		36		37
Total	$	289	$	346	$	379	$	331	$	418

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TEP’s estimated capital expenditures in 2015 exclude the potential $159 million purchase of interests in Springerville Unit 1 and the potential $120 million purchase of interests in Springerville Coal Handling Facilities upon the expiration of their respective leases in January 2015. SeeCapital Lease Obligations, below for more information.

TEP’s capital expenditures also exclude 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, 2011, TEP had $29 million of investments in lease debt on its balance sheet. 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.

Financing Activities

In 2011, net cash from financing activities was $103 million higher than in 2010 due to: a $45 million increase in borrowings (net of repayments) under TEP’s revolving credit facility; a $15 million increase in capital contributions from UniSource Energy in 2011; and a $60 million reduction in dividends paid to UniSource Energy during 2011; partially offset by an $18 million increase in payments on capital lease obligations.

TEP Credit Agreement

In November 2011, TEP amended and extended its existing credit agreement (the TEP Credit Agreement). The TEP Credit Agreement consisted of a $200 million revolving credit and revolving letter of credit facility and a $341 million letter of credit facility to support variable rate tax-exempt bonds. The amendment extended the term of the TEP Credit Agreement by two years to November 2016.

In December 2011, TEP reduced its letter of credit facility from $341 million to $186 million, following the repurchase of $150 million of variable rate IDBs and the cancellation of $155 million of LOCs supporting those bonds. The TEP Credit Agreement is secured by $386 million of Mortgage Bonds. See2011 Bond Issuances, Purchase and Redemptions, below.

At December 31, 2011, TEP had $10 million in 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, 2011, TEP was in compliance with the terms of the TEP Credit Agreement.

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.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of December 31, 2011, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

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Capital Contribution from UniSource Energy

In December 2011, UniSource Energy contributed $30 million of capital to TEP.

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.

2011 Bond Issuances, Purchases and Redemptions

In November 2011, TEP issued $250 million in unsecured notes due in November 2021 (TEP Notes). The TEP Notes bear interest at 5.15% and are callable prior to August 2021 with a make-whole redemption premium. The TEP Notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds from the sale of the TEP Notes to (i) repurchase $150 million of its tax-exempt variable rate bonds, (ii) redeem approximately $22 million of fixed rate bonds with a coupon of 6.1% and (iii) repay $78 million on its revolving credit facility.

The $150 million of tax-exempt variable rate debt purchased by TEP was not retired but will be held in treasury and may be reissued or refunded in the future.

2010 Bond Issuances

In 2010, $137 million of tax-exempt bonds were issued on behalf of TEP, with $37 million of such bonds being applied to redeem a corresponding amount of outstanding tax-exempt bonds. In addition, in 2010 TEP converted the interest rate mode on $100 million of tax-exempt bonds from a variable rate to a fixed rate.

Tax-Exempt Bonds

TEP has financed a substantial portion of utility plant assets with revenue bonds issued by governmental entities on TEP’s behalf. The interest on these bonds is excluded from gross income of the bondholder for federal income tax purposes. The proceeds of the bonds are loaned to TEP, with TEP agreeing to repay the loans by making payments in amounts and at times to enable payments of principal of and interest on the tax-exempt bonds to be paid when due. Of the $831 million of tax-exempt bonds outstanding as of December 31, 2011, $616 million are unsecured and bear interest at fixed rates and $215 million are variable rate bonds. The variable rate bonds accrue interest at a weekly rate, with bondholders having the right to require their bonds to be purchased upon demand at a purchase price of par plus accrued interest. Variable rate bonds which have been put for purchase are generally remarketed to third parties to pay the purchase price. Payments of principal, interest and purchase price on the variable rate bonds are supported by direct-pay letters of credit, with TEP being required to reimburse the letter of credit banks for drawings on the letters of credit. SeeTEP Credit Agreement andTEP Reimbursement Agreementfor more information.

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, 2011, TEP had a total of $423 million in outstanding Mortgage Bonds, consisting of $386 million in bonds securing the TEP Credit Agreement, and $37 million in bonds securing the 2010 TEP Reimbursement Agreement.

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Capital Lease Obligations

At December 31, 2011, TEP had $430 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.

		September 30,		September 30,	September 30,
Leases	Capital Lease Obligation Balance		Expiration		Renewal/Purchase Option
	-Millions of Dollars-
Springerville Unit 1(1)	$	253		2015	Fair market value purchase option of $159 million
Springerville Coal Handling Facilities Lease		65		2015	Fixed price purchase option of $120  million(2)
Springerville Common Facilities(3)		112		2017 and 2021	Fixed price purchase option of $106 million(2)
Total Capital Lease Obligations	$	430

(1) The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities.

(2) TEP agreed with Tri-State, the owner of Springerville Unit 3 and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri State will then be obligated to either 1) buy a portion of these facilities; or 2) continue making payments to TEP for the use of these facilities.

(3) The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville 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.

Contractual Obligations

The following chart displays TEP’s contractual obligations as of December 31, 2011 by maturity and by type of obligation.

TEP’s Contractual Obligations

- Millions of Dollars -

		000000		000000		000000		000000		000000		000000		000000		000000
Payment Due in Years Ending December 31,	2012		2013		2014		2015		2016		2017 and after		Other		Total
Long Term Debt
Principal	$	—	$	—	$	37	$	—	$	178	$	866	$	—	$	1,081
Interest		53		53		53		53		53		551		—		816
Capital Lease Obligations		118		122		195		23		18		61		—		537
Operating Leases		2		2		2		1		1		10		—		18
Purchase Obligations:
Fuel (including Transportation)		84		59		58		44		41		75		—		361
Purchased Power1		29		21		17		13		13		184		—		277
Transmission		3		3		3		3		3		23		—		38
Other Long-Term Liabilities:
Pension & Other Post Retirement Obligations		26		5		6		6		6		34		—		83
Acquisition of Springerville Coal Handling and Common Facilities		—		—		—		120		—		106		—		226
Solar Equipment		12		12		—		—		—		—		—		24
Unrecognized Tax Benefits		—		—		—		—		—		—		24		24
Total Contractual Cash Obligations	$	327	$	277	$	371	$	263	$	313	$	1,910	$	24	$	3,485

¹  Purchased Power includes two long-term Power Purchase Agreements (PPAs) with renewable energy generation producers to meet compliance under the RES tariff. The facilities achieved commercial operation in 2011. TEP is obligated to purchase 100% of the output from these facilities. The table above includes estimated future payments based on expected power deliveries under these contracts through 2031. TEP has entered into additional long-term renewable PPAs to comply with the RES tariff; however, TEP’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

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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, 2011, 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, 2011, TEP had posted a $1 million letter of credit as collateral with counterparties for credit enhancement.

Dividends on Common Stock

TEP did not pay any dividends to UniSource Energy in 2011. TEP declared and paid dividends to UniSource Energy of $60 million in 2010 and $60 million in 2009.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 Reimbursement Agreement, and certain financial covenants. As of December 31, 2011, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 Reimbursement Agreement.

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

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported net income of $10 million in 2011, $9 million in 2010 and $7 million in 2009. 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.

		September 30,		September 30,		September 30,
	2011		2010		2009
	-Millions of Dollars-
Gas Revenues	$	148	$	146	$	149
Other Revenues		3		4		4
Total Operating Revenues		151		150		153
Purchased Gas Expense		90		91		99
Other Operations and Maintenance Expense		25		26		25
Depreciation and Amortization		9		8		7
Taxes Other Than Income Taxes		3		3		3
Total Other Operating Expenses		127		128		134
Operating Income		24		22		19
Total Interest Expense		7		7		6
Income Tax Expense		7		6		6
Net Income	$	10	$	9	$	7

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The table below shows UNS Gas’ therm sales and revenues for 2011, 2010 and 2009.

		September 30,		September 30,		September 30,			September 30,			September 30,
					Increase (Decrease)
	2011		2010		Amount			Percent*			2009
Energy Sales, Therms (in millions)
Gas Retail Sales:
Residential		74		73		1			1.2	%		70
Commercial		31		30		1			2.9	%		30
Industrial		2		2		—			22.9	%		2
Public Authorities		7		7		—			(0.2	%)		6
Total Gas Retail Sales		114		112		2			1.9	%		108
Negotiated Sales Program (NSP)		26		28		(2	)		(8.4	%)		30
Total Gas Sales		140		140		—			(0.2	%)		138
Gas Revenues (in millions):
Retail Margin Revenues:
Residential	$	40	$	39	$	1			2.6	%	$	36
Commercial		11		10		1			4.9	%		10
Industrial		—		—		—			21.9	%		—
Public Authorities		2		2		—			4.8	%		2
Total Retail Margin Revenues (Non-GAAP)**		53		51		2			3.1	%		48
Transport and NSP		17		17		—			(4.6	%)		16
DSM		1		1		—			10.0	%		1
Retail Fuel Revenues		77		77		—			1.0	%		84
Total Gas Revenues (GAAP)	$	148	$	146	$	2			1.2	%	$	149
Weather Data:
Heating Degree Days
Year Ended December 31		25,794		25,457		337			1.3	%		24,305
10-Year Average		24,894		24,828		NM			NM			24,739

* Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

** Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business.

Retail therm sales during 2011 increased by 1.9% compared with 2010 due in part to a 1.3% increase in heating degree days and an increase in the number of retail customers. Retail margin revenues increased by 3.1%, or $2 million, during 2011 due in part to colder winter weather and a Base Rate increase that was implemented in April 1, 2010. As of December 31, 2011, UNS Gas had approximately 148,000 retail customers, which represents an increase of less than 1% compared with the end of 2010.

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 Decouplingfor more information.

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Rates

SeeItem 1. Business, UNS Gas, Rates and Regulation, 2011 UNS Gas Rate Filing.

Interest Rates

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, Interest Rate Risk, below.

Fair Value Measurements

UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability 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 2011, capital expenditures were $13 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.

Operating Cash Flow and Capital Expenditures

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

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	32		$	18		$	37
Investing Activities		(12	)		(9	)		(13	)
Financing Activities		(11	)		(11	)		—
Net Increase (Decrease in Cash)		9			(2	)		24
Beginning Cash		29			31			7
Ending Cash	$	38		$	29		$	31

Operating cash flows increased in 2011 due in part to the temporary over-collection of PGA gas costs from customers.

UNS Gas/UNS Electric Revolver

In November 2011, UNS Gas and UNS Electric amended their existing unsecured credit agreement. The UNS Electric/UNS Gas Revolver consists of a $100 million unsecured revolving credit and revolving letter of credit facility. Either company can borrow up to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The amendment extended the term of the UNS Electric/UNS Gas Revolver by two years to November 2016.

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

The UNS Gas/UNS Electric Revolver 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, 2011, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.

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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 December 31, 2011, UNS Gas had no outstanding borrowings or letters of credit under the UNS Gas/UNS Electric Revolver.

Senior Unsecured Notes

UNS Gas has $100 million of senior unsecured notes outstanding, of which $50 million matures in 2015 and $50 million matures in 2026.

All of UNS Gas’ senior unsecured notes are guaranteed by UES. The note purchase agreements for UNS Gas restrict transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness. The agreements also contain a minimum net worth test. As of December 31, 2011, UNS Gas was in compliance with the terms of its note purchase agreements.

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 $5 million in short-term debt.

Note Issuance

In August 2011, UNS Gas issued $50 million of 5.39% senior unsecured notes. The proceeds were used to pay off $50 million of senior unsecured notes that matured in August 2011.

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 2012 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 2011/2012 winter season (November through March). Additionally, UNS Gas has approximately 38% of its expected gas consumption hedged for April through October 2012, and 32% hedged for the period November 2012 through March 2013.

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The following table displays UNS Gas’ contractual obligations as of December 31, 2011 by maturity and by type of obligation.

	000000		000000		000000		000000		000000		000000		000000		000000		000000
UNS Gas Contractual Obligations -Millions of Dollars-
Payment Due in Years Ending December 31,		2012		2013		2014		2015		2016		2017 and after		Other		Total
Long Term Debt
Principal		$	—	$	—	$	—	$	50	$	—	$	50	$	—	$	100
Interest			6		6		6		6		3		27		—		54
Purchase Obligations—Fuel			23		12		10		6		6		21		—		78
Pension & Other Post Retirement Obligations			1		—		—		—		—		—		—		1
Unrecognized Tax Benefits			—		—		—		—		—		—		1		1
Total Contractual Cash Obligations		$	30	$	18	$	16	$	62	$	9	$	98	$	1	$	234

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, 2011, UNS Gas had not posted any such credit enhancements.

Dividends on Common Stock

UNS Gas paid dividends to UniSource Energy of $10 million in 2010, 2011, and in February 2012. 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, 2011, UNS Gas was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above.

UNS ELECTRIC

RESULTS OF OPERATIONS

In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for $63 million on July 1, 2011. In accordance with accounting rules related to the transfer of a business held under common control, we reflect UNS Electric’s purchase of BMGS as if it occurred on January 1, 2009. The transaction had no impact on UniSource Energy’s consolidated financial statements for 2009 or 2010.

UNS Electric had net income of $18 million in 2011, compared with net income of $15 million in 2010. The increase is due primarily to a rate increase that was implemented in October 2010.

Results in 2010 included $3 million of pre-tax income related to a settlement with Arizona Public Service Company for refunds related to transactions with the California Power Exchange.

As with TEP, UNS Electric’s operations are generally seasonal in nature, with peak energy demand occurring in the summer months.

The table below provides summary financial information for UNS Electric.

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		September 30,		September 30,		September 30,
	2011		2010		2009
	-Millions of Dollars-
Retail Electric Revenues	$	182	$	183	$	180
Wholesale Electric Revenues		37		31		5
Other Revenues		2		2		2
Total Operating Revenues		221		216		187
Purchased Energy and Fuel Expense		137		137		116
Other Operations and Maintenance Expense		27		29		26
Depreciation and Amortization Expense		17		17		16
Taxes Other Than Income Taxes		4		4		4
Total Other Operating Expenses		185		187		162
Operating Income		36		29		25
Other Income		—		3		—
Total Interest Expense		7		7		7
Income Tax Expense		11		10		7
Net Income	$	18	$	15	$	11

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The table below summarizes UNS Electric’s kWh sales and margin revenues for 2011, 2010 and 2009.

		September 30,		September 30,		September 30,			September 30,			September 30,
					Increase (Decrease)
	2011		2010		Amount			Percent*			2009
Energy Sales, kWh (in millions)
Electric Retail Sales:
Residential		828		820		8			0.9	%		814
Commercial		602		606		(4	)		(0.7	%)		608
Industrial		221		219		2			0.8	%		197
Mining		200		210		(10	)		(4.2	%)		163
Public Authorities		2		2		—			(16.3	%)		2
Total Electric Retail Sales		1,853		1,857		(4	)		(0.2	%)		1,784
Electric Retail Revenues (in millions):
Retail Margin Revenues:
Residential	$	31	$	27	$	4			13.9	%	$	21
Commercial		29		27		2			5.9	%		22
Industrial		9		9		—			4.7	%		7
Mining		7		6		1			22.2	%		3
Public Authorities		—		—		—			(25.0	%)		—
Total Retail Margin Revenues (Non-GAAP)**	$	76	$	69	$	7			10.0	%	$	53
Retail Fuel Revenues		99		105		(6	)		(5.6	%)		121
DSM and RES Revenues		7		9		(2	)		(22.4	%)		6
Total Retail Revenues (GAAP)	$	182	$	183	$	(1	)		(0.5	%)	$	180

		September 30,		September 30,	September 30,	September 30,			September 30,
Weather – Cooling Degree Days	2011		2010					2009
Year Ended December 31		9,092		8,821	271	3.1	%		9,183
10-Year Average		8,994		9,031	NM	NM			9,059

* Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

** Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business.

In 2011, retail kWh sales decreased by 0.2% compared with 2010. A 4% Base Rate increase that took effect in October 2010, contributed to a $7 million increase in retail margin revenues in 2011 compared with 2010.

As of December 31, 2011, UNS Electric had approximately 91,000 retail customers, which was an increase of less than 1% compared with 2010.

Wholesale revenues increased by $6 million in 2011 due to an increase in short-term wholesale sales. All revenues from wholesale 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, Energy Efficiency Standards and Decoupling for more information.

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Rates

SeeItem 1. Business, UNS Electric, Rates and Regulation, 2010 UNS Electric Rate Order for more information.

Mining Customer

UNS Electric’s largest customer, a copper mine located near Kingman, Arizona, began generating a portion of its own electricity needs in 2011. In 2012, UNS Electric expects its mining kWh sales to decrease by approximately 50% compared with 2011; however, due to UNS Electric’s retail rate structure, UNS Electric expects the margin revenues from this customer to be near the same level as 2011. In 2011, UNS Electric’s mining-related margin revenues were $7 million.

Renewable Energy Standard and Tariff

As part of the 2010 UNS Electric rate order, the ACC authorized UNS Electric to recover operating costs, depreciation, property taxes and a return on its investment in company-owned solar projects through RES funds until these costs are reflected in its Base Rates. Under these terms, UNS Electric expects to invest $5 million annually in 2012 through 2014 in solar photovoltaic projects. We estimate that each $5 million investment would build approximately 1.25 MW of solar capacity. For more information, seeItem 1. Business, UNS Electric, Rates and Regulation, Renewable Energy Standard and Tariff.

Interest Rates

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, Interest Rate Risk, below.

Fair Value Measurements

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

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

In 2011, UNS Electric’s capital expenditures were $96 million which included the purchase of BMGS for $63 million from an affiliate, UED. Going forward, UNS Electric expects operating cash flows to fund a large 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

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

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	43		$	34		$	48
Investing Activities		(93	)		(23	)		(28	)
Financing Activities		44			(10	)		(19	)
Net Increase (Decrease in Cash)		(6	)		1			1
Beginning Cash		11			10			9
Ending Cash	$	5		$	11		$	10

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Operating cash flows increased in 2011 due in part to a Base Rate increase that became effective in October 2010 as well as an increase in wholesale sales.

UNS Gas/UNS Electric Revolver

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

UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, 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 21, 2012, UNS Electric had $6 million outstanding under the UNS Gas/UNS Electric Revolver.

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, 2011, 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.

UNS Electric Credit Agreement

In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.25%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three month LIBOR rate on a $30 million notional amount over a four year period ending August 10, 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt in the balance sheet, is guaranteed by UES.

The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio, and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement. As of December 31, 2011, UNS Electric was in compliance with the terms of the credit agreement.

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, 2011, UNS Electric had posted $6 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. SeeItem 1. Business, UNS Electric, Power Supply and Transmission, Transmission for more information.

The following table displays UNS Electric’s contractual obligations as of December 31, 2011 by maturity and by type of obligation.

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		Sept 30		Sept 30		Sept 30		Sept 30		Sept 30		Sept 30		Sept 30		Sept 30
UNS Electric Contractual Obligations -Millions of Dollars-
Payment Due in Years Ending December 31,	2012		2013		2014		2015		2016		2017 and after		Other		Total
Long Term Debt:
Principal	$	—	$	—	$	—	$	80	$	—	$	50	$	—	$	130
Interest		7		7		7		7		4		25		—		57
Purchase Obligations:
Purchased Power1		54		40		31		3		3		43		—		174
Transmission		4		2		2		1		1		—		—		10
Pension & Other Post Retirement Obligations		1		—		—		—		—		—		—		1
Unrecognized Tax Benefits		—		—		—		—		—		—		4		4
Total Contractual Cash Obligations	$	66	$	49	$	40	$	91	$	8	$	118	$	4	$	376

¹  Purchased Power includes a long-term Power Purchase Agreement (PPA) with a renewable energy generation producer to meet compliance under the RES tariff. The facility achieved commercial operation in September 2011. UNS Electric is obligated to purchase 100% of the output from this facility. The table above includes estimated future payments based on expected power deliveries under the contract through 2031. UNS Electric has entered into additional long-term renewable PPAs to comply with the RES tariff; however, UNS Electric’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

Dividends on Common Stock

As of December 31, 2011, UNS Electric had 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, 2011, UNS Electric was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above.

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.

		September 30,			September 30,			September 30,
	2011			2010			2009
	- Millions of Dollars -
Millennium	$	2		$	(13	)	$	2
Other (1)		(5	)		(6	)		(5	)
Total Other Net Loss	$	(3	)	$	(19	)	$	(3	)

(1) Includes parent company expenses, UED and reconciling adjustments.

Millennium

Millennium recorded net income of $2 million in 2011 compared with a net loss of $13 million in 2010. 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 2011 and December 2010, Millennium received annual interest payments of $1 million on its $15 million note receivable from Mimosa.

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UniSource Energy Parent Company

UniSource Energy parent company expenses primarily include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes and the UniSource Credit Agreement.

UED

In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for $63 million on July 1, 2011.

In 2011, UED paid dividends of $39 million to UniSource Energy of which $28 million represented a return of capital. In 2010, UED paid a $9 million dividend to UniSource Energy, of which $4 million represented a return of capital. In 2009, UED paid a $30 million dividend to UniSource Energy which also represented a return of capital.

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, 2011, Millennium had assets of $20 million including a $15 million note receivable and a cash balance of $5 million.

In July 2011, Millennium sold a building for $3 million resulting in an after-tax gain of approximately $1 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 $3 million in dividend payments to UniSource Energy in 2011, $8 million in 2010 and $3 million in 2009. All of these dividends represented return of capital distributions. Millennium’s remaining commitment for all of its investments combined is less than $1 million.

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 and 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

We 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 we are allowed to recover certain expenses at a designated time in the future. In this situation, we defer these items as regulatory assets on the balance sheet and then reflect the costs as expenses when we are allowed to recover the costs from ratepayers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until Retail Rates to customers are reduced. We evaluate regulatory assets each period and believe recovery is probable.

If in the future a portion of operations no longer meets regulatory accounting criteria, the impact would be material to the financial statements. If we stopped applying regulatory accounting to all our 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).

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At December 31, 2011, regulatory assets net of regulatory liabilities totaled $4 million at TEP and $15 million at UNS Electric. Regulatory liabilities net of regulatory assets totaled $26 million at UNS Gas. We 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.

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. Additionally, TEP entered into a ground lease agreement with Campus Research Corporation for the installation of photovoltaic (PV) assets. The provisions of the PV ground lease require TEP to remove the PV facilities upon expiration of the lease in 2031. The legal retirement obligation related to the PV assets is estimated to be approximately $4 million at the retirement date. TEP also has certain environmental obligations at the Luna, 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 Luna, San Juan, Sundt and Springerville environmental obligations will be approximately $160 million at the retirement dates. No other legal obligations to retire generation plant assets were identified.

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 Retail 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 net cost of removal for interim retirements.

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.

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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 Retail Rates.

At December 31, 2011, TEP discounted its future pension plan obligations at 5.0% and its other postretirement plan obligations at a rate of 4.7%. 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-graded 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 $9 million and the 2012 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 7.0% at December 31, 2011. 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 2012 by less than $1 million.

TEP used a current year health care cost trend rate of 6.9% in valuing its postretirement benefit obligation at December 31, 2011. 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 2012 by less than $1 million.

In 2012, TEP will incur pension and other postretirement benefit costs of approximately $14 million and $6 million, respectively. TEP expects to charge approximately $15 million of these costs to O&M expense, $3 million to capital and $2 million to Other Expense. TEP expects to make pension plan contributions of $20 million in 2012. In 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA) trust to fund its other postretirement benefit plan. In 2012, 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.

UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 4.9% at December 31, 2011. For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2012 pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2012, 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 2012.

UNS Gas and UNS Electric discounted their other postretirement plan obligations using a rate of 4.7% at December 31, 2011. 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 2012.

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Accounting for Derivative Instruments 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.

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.

The market prices used to determine fair values for TEP, UNS Gas and UNS Electric’s derivative instruments at December 31, 2011, 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.

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. At December 31, 2011, TEP hedged approximately $29 million and $34 million of variable rate lease debt payments for the Springerville Common Facilities Lease to a fixed rate through July 1, 2014, and 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.

In August 2011, UNS Electric entered into an interest rate swap with the effect of converting the variable interest rate for their $30 million term loan to a fixed rate from August 2011 through August 2015. See Note 6.

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. See Note 1 for additional details regarding Cash Flow Hedges.

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

Unbilled Revenue

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 Retail 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 the unbilled revenue amount 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.

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Plant Asset Depreciable Lives

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. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate at our balance sheet date.

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, 2011, UniSource Energy had a $7 million valuation allowance. The valuation allowances 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 (FASB) issued authoritative guidance that will eliminate the current option to report other comprehensive income in the statement of changes in equity. An entity can elect to present items of net income and other comprehensive income in one continuous statement, or in two separate but consecutive statements. We will be required to comply in the first quarter of 2012 and plan to present a separate statement of other comprehensive income.

• The FASB issued authoritative guidance that changed some fair value measurement principles and disclosure requirements. The most significant disclosure change is expansion of required information for unobservable inputs. We will be required to comply in the first quarter of 2012, and we do not expect this pronouncement to have a material impact on the valuation techniques used to estimate the fair value of assets and liabilities.

• The FASB issued authoritative guidance that requires entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting arrangements. We will be required to comply in the first quarter of 2013.

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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 our 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; cyber attacks or challenges to our information security; 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, 2011 and December 31, 2010, TEP had $215 million and $365 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 rate payable under the indentures for these bonds is 10% for $37 million of variable rate IDBs, and 20% on the remaining $178 million in variable rate IDBs. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 0.18% in 2011 and 0.26% in 2010. The average weekly interest rate ranged from 0.05% to 0.34% in 2011 and 0.17% to 0.39% during 2010. Although short-term interest rates have been relatively low and stable in 2011 and 2010, 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 $2 million.

TEP manages its exposure to variable interest rate risk by entering into interest rate swaps and financing transactions to rebalance its mix of variable rate and fixed rate long-term debt.

TEP has fixed-for-floating interest rate swaps in place to hedge floating rate interest rate risk associated with $63 million of Springerville Common Facilities lease debt and $50 million of its variable rate IDBs. In addition, in 2010 and 2011, TEP entered into the following transactions to change its mix of fixed and floating rate debt.

• In 2010, TEP converted the interest rate on its $130 million IDBs from a variable rate to an unsecured fixed rate of 5.75% through maturity in 2029;

• In 2010, TEP refinanced $37 million of its 7.125% unsecured fixed rate IDBs with variable rate IDBs; and

• TEP issued $250 million of 5.15% unsecured notes in 2011, and repurchased $150 million of variable rate IDBs to hold in treasury, and redeemed $22 million of its 6.1% unsecured fixed-rate IDBs.

As a result of these transactions, TEP’s variable rate debt comprised approximately 15% and 31% of its total long-term debt at December 31, 2011 and 2010, respectively.

In August 2011, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount through August 2015 to hedge the interest rate risk associated with its $30 million credit agreement.

Interest Rate Swaps

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):

		September 30,			September 30,			September 30,
	2011			2010			2009
	- Millions of Dollars -
Unrealized Gains (Losses)	$	(5	)	$	(8	)	$	1

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, 2011, UniSource Energy’s short-term investments consisted of liquid, highly-rated money market funds, commercial paper, and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the balance sheet.

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TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $50 million at December 31, 2011, and $111 million at December 31, 2010. At December 31, 2011, the carrying value exceeded fair value by $16 million. No impairment was recorded as TEP expects to recover the full carrying value of its lease equity investment in future Retail Rates. At December 31, 2010, the fair value exceeded the carrying value by $6 million. 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. 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.

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 are not considered to be “normal purchases and sales” and therefore are accounted for as derivatives. 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.

Long-Term Wholesale Sales

Prior to June 1, 2011, under the terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, or $22 million annually, and sold the energy at a price based on TEP’s average fuel cost. From June 1, 2011 to December 31, 2011, SRP was required to purchase 73,000 MWh per month. From January 1, 2012 through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of

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on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the price of on-peak power on Palo Verde Market Index. As of February 21, 2012, the average forward price of on-peak power on the Palo Verde Market Index for the calendar year 2012 was $30.33 MWh.

The chart below summarizes the annual change in pre-tax income if the market price of power on the Palo Verde Market Index changes by $5 per MWh.

		September 30,		September 30,
	Change in Per MWh Price
	$5 Increase		$5 Decrease
	-Millions of Dollars-
Change in Pre-Tax Income	$	3	$	(3	)

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, 2011, TEP considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for TEP was less than $0.5 million at December 31, 2011.

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):

		September 30,			September 30,		September 30,
	2011			2010		2009
	- Millions of Dollars -
Unrealized Gains (Losses)	$	(2	)	$	4	$	11

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

		September 30,			September 30,			September 30,			September 30,
	Unrealized Gain (Loss) of TEP’s Hedging Activities
	- Millions of Dollars -
Source of Fair Value at Dec. 31, 2011	Maturity 0 –6 months			Maturity 6 –12 months			Maturity over 1 yr.			Total Unrealized Gain (Loss)
Prices actively quoted	$	(3	)	$	(5	)	$	(3	)	$	(11	)
Prices based on models and other valuation methods		—			1			1			2
Total	$	(3	)	$	(4	)	$	(2	)	$	(9	)

Sensitivity Analysis of Derivatives

TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its derivative forward contracts. TEP records unrealized gains and losses 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%.

		September 30,		September 30,
	- Millions of Dollars -
Change in Market Price As of December 31, 2011	10% Increase		10% Decrease
Non-Cash Flow Hedges
Forward power sales and purchase contracts	$	2	$	(2	)

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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 is determined by the cost of Powder River Basin coal delivered to Springerville Unit 3 subject to a floor and ceiling. This range would be from $19.30 to $26.15 per ton. TEP estimates its future minimum annual payments under this contract to be $14 million from 2012 through 2020.

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. In December 2011, the take-or-pay obligations under a coal transportation agreement previously effective through December 2015 were terminated. As a result, TEP is relieved of a $4 million obligation recognized under this contract in December 2010. TEP reversed a $4 million regulatory asset. TEP has a short-term coal supply contract for Sundt Unit 4 ending December 31, 2012, and has hedged gas costs through September 2012.

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. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations and Note 4.

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, 2011, UNS Gas considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Gas was less than $0.5 million at December 31, 2011.

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):

		September 30,			September 30,			September 30,
	2011			2010			2009
	- Millions of Dollars -
Unrealized Gains (Losses)	$	(1	)	$	(2	)	$	6

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 $2 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 $2 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 allows for the recovery of costs from 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

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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 $51 million in 2012, $37 million in 2013, and $28 million in 2014 based on natural gas prices at December 31, 2011.

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 gains reported as a regulatory asset of $5 million, while a 10% increase in market prices would result in a decrease in unrealized net gains reported as a reduction in regulatory assets of $5 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 2012. 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 $0.5 million at December 31, 2011.

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):

		September 30,		September 30,			September 30,
	2011		2010			2009
	- Millions of Dollars-
Unrealized Gains (Losses)	$	1	$	(2	)	$	12

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.

Credit Risk

UniSource Energy is exposed to credit risk in its energy-related marketing 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.

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, 2011, the combined credit exposure to TEP, UNS Gas and UNS Electric from financial institution counterparties was approximately $4 million.

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As of December 31, 2011, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $17 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit exposure, totaling approximately $4 million. TEP’s total exposure to non-investment grade counterparties was $4 million.

At December 31, 2011, TEP posted no cash collateral and $1 million in letters of credit as credit enhancements with its 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, 2011, UNS Gas had purchased under fixed price contracts approximately 32% of its expected consumption for the 2012/2013 winter season. At December 31, 2011, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts.As of December 31, 2011, UNS Gas had posted no 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, 2011, UNS Electric had $1 million in credit exposure under such contracts. As of December 31, 2011, UNS Electric had posted $6 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’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 UniSource Energy’s internal control over financial reporting as of December 31, 2011. 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, 2011, UniSource Energy’s internal control over financial reporting was effective.

The effectiveness of UniSource Energy’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report in Item 8 of this Annual Report on Form 10-K.

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, 2011. 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, 2011, Tucson Electric Power Company’s internal control over financial reporting was effective.

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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, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

February 27, 2012

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of

Tucson Electric Power Company:

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 Tucson Electric Power Company and its subsidiaries at December 31, 2011 and December 31, 2010 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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 LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

February 27, 2012

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UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	- Thousands of Dollars -
	(Except Per Share Amounts)
Operating Revenues
Electric Retail Sales	$	1,085,822		$	1,051,002		$	1,047,619
Electric Wholesale Sales		163,159			151,962			131,255
California Power Exchange (CPX) Provision for Wholesale Refunds		—			(2,970	)		(4,172	)
Gas Revenue		145,053			141,036			144,609
Other Revenues		115,481			112,936			77,741
Total Operating Revenues		1,509,515			1,453,966			1,397,052
Operating Expenses
Fuel		324,520			295,652			296,248
Purchased Energy		307,423			307,288			296,861
Transmission		7,334			10,945			10,181
Decrease to Reflect PPFAC/PGA Recovery Treatment		(4,932	)		(29,622	)		(14,553	)
Total Fuel and Purchased Energy		634,345			584,263			588,737
Other Operations and Maintenance		379,220			370,037			333,579
Depreciation		133,832			128,215			144,960
Amortization		30,983			28,094			31,058
Taxes Other Than Income Taxes		49,463			46,243			45,858
Total Operating Expenses		1,227,843			1,156,852			1,144,192
Operating Income		281,672			297,114			252,860
Other Income (Deductions)
Interest Income		4,568			7,779			12,072
Other Income		8,293			11,038			18,063
Other Expense		(5,249	)		(15,202	)		(5,292	)
Total Other Income (Deductions)		7,612			3,615			24,843
Interest Expense
Long-Term Debt		73,217			65,020			58,134
Capital Leases		40,359			46,740			49,270
Other Interest Expense		2,535			1,651			3,468
Interest Capitalized		(3,753	)		(2,587	)		(2,302	)
Total Interest Expense		112,358			110,824			108,570
Income Before Income Taxes		176,926			189,905			169,133
Income Tax Expense		66,951			76,921			63,232
Net Income	$	109,975		$	112,984		$	105,901
Weighted-Average Shares of Common Stock Outstanding (000)
Basic		36,962			36,415			35,858
Diluted		41,609			41,041			40,450
Earnings per Share
Basic	$	2.98		$	3.10		$	2.95
Diluted	$	2.75		$	2.86		$	2.73
Dividends Declared per Share	$	1.68		$	1.56		$	1.16

See Notes to Consolidated Financial Statements.

K-80

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,163,537		$	1,142,364		$	1,145,051
Cash Receipts from Electric Wholesale Sales		183,151			194,580			175,679
Cash Receipts from Gas Sales		159,529			157,397			162,725
Cash Receipts from Operating Springerville Units 3 & 4		104,754			102,563			68,951
Cash Receipts from Wholesale Gas Sales		12,404			422			716
Performance Deposits Received		7,050			18,470			34,630
Interest Received		6,334			10,026			13,470
Income Tax Refunds Received		4,672			341			20,242
Other Cash Receipts		23,937			32,011			26,176
Purchased Energy Costs Paid		(328,713	)		(364,132	)		(334,481	)
Payment of Other Operations and Maintenance Costs		(291,607	)		(255,988	)		(246,895	)
Fuel Costs Paid		(281,441	)		(247,484	)		(300,810	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(179,766	)		(163,037	)		(161,574	)
Wages Paid, Net of Amounts Capitalized		(122,370	)		(125,893	)		(122,245	)
Interest Paid, Net of Amounts Capitalized		(68,027	)		(59,749	)		(54,641	)
Capital Lease Interest Paid		(32,103	)		(38,646	)		(38,598	)
Wholesale Gas Costs Paid		(11,822	)		—			—
Performance Deposits Paid		(4,550	)		(19,220	)		(22,260	)
Income Taxes Paid		(700	)		(22,797	)		(9,050	)
Other Cash Payments		(6,949	)		(14,308	)		(9,776	)
Net Cash Flows - Operating Activities		337,320			346,920			347,310
Cash Flows from Investing Activities
Capital Expenditures		(374,122	)		(279,240	)		(294,020	)
Purchase of Intangibles - Renewable Energy Credits		(5,992	)		(7,514	)		—
Purchase of Sundt Unit 4 Lease Asset		—			(51,389	)		—
Purchase of Springerville Lease Debt		—			—			(31,375	)
Prepayment Deposits on UED Debt		—			(3,188	)		(3,625	)
Other Cash Payments		(578	)		(2,302	)		(868	)
Return of Investments in Springerville Lease Debt		38,353			25,615			12,736
Other Cash Receipts		15,251			12,958			20,508
Net Cash Flows - Investing Activities		(327,088	)		(305,060	)		(296,644	)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities		391,000			239,000			203,000
Proceeds from Issuance of Long-Term Debt		340,285			127,815			—
Proceeds from Stock Options Exercised		8,115			13,391			3,441
Proceeds from Issuance of Short-Term Debt		—			—			30,000
Other Cash Receipts		4,743			12,406			8,937
Repayments of Borrowings Under Revolving Credit Facilities		(351,000	)		(268,500	)		(198,000	)
Repayments of Long-Term Debt		(252,125	)		(51,592	)		(6,000	)
Payments of Capital Lease Obligations		(74,381	)		(55,997	)		(24,192	)
Common Stock Dividends Paid		(61,904	)		(56,590	)		(41,429	)
Payments of Debt Issue/Retirement Costs		(4,361	)		(8,341	)		(2,268	)
Other Cash Payments		(1,813	)		(2,775	)		(2,405	)
Net Cash Flows - Financing Activities		(1,441	)		(51,183	)		(28,916	)
Net Increase (Decrease) in Cash and Cash Equivalents		8,791			(9,323	)		21,750
Cash and Cash Equivalents, Beginning of Year		67,599			76,922			55,172
Cash and Cash Equivalents, End of Year	$	76,390		$	67,599		$	76,922
Non-Cash Financing Activity
Repayment of UED Short-Term Debt	$	—		$	(3,188	)	$	(3,625	)

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-81

UNISOURCE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

		September 30,			September 30,
	December 31,
	2011			2010
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,856,108		$	4,452,928
Utility Plant Under Capital Leases		582,669			583,374
Construction Work in Progress		89,749			210,971
Total Utility Plant		5,528,526			5,247,273
Less Accumulated Depreciation and Amortization		(1,869,300	)		(1,824,843	)
Less Accumulated Amortization of Capital Lease Assets		(476,963	)		(460,932	)
Total Utility Plant - Net		3,182,263			2,961,498
Investments and Other Property
Investments in Lease Debt and Equity		65,829			103,844
Other		34,205			61,676
Total Investments and Other Property		100,034			165,520
Current Assets
Cash and Cash Equivalents		76,390			67,599
Accounts Receivable - Customer		94,585			98,333
Unbilled Accounts Receivable		51,464			53,084
Allowance for Doubtful Accounts		(5,572	)		(6,125	)
Fuel Inventory		33,263			29,216
Materials and Supplies		82,649			65,832
Derivative Instruments		11,966			5,214
Regulatory Assets - Current		97,056			56,962
Deferred Income Taxes - Current		23,158			30,822
Other		32,577			30,091
Total Current Assets		497,536			431,028
Regulatory and Other Assets
Regulatory Assets - Noncurrent		173,199			192,966
Derivative Instruments		2,019			9,806
Other Assets		30,180			30,425
Total Regulatory and Other Assets		205,398			233,197
Total Assets	$	3,985,231		$	3,791,243

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-82

UNISOURCE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

		September 30,		September 30,
	December 31,
	2011		2010
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	888,474	$	830,756
Capital Lease Obligations		352,720		429,074
Long-Term Debt		1,517,373		1,352,977
Total Capitalization		2,758,567		2,612,807
Current Liabilities
Current Obligations Under Capital Leases		77,482		60,347
Current Maturities of Long-Term Debt		—		57,000
Borrowing Under Revolving Credit Facility		10,000		—
Accounts Payable - Trade		109,759		108,950
Interest Accrued		38,302		39,120
Accrued Taxes Other than Income Taxes		41,997		39,140
Accrued Employee Expenses		24,917		26,969
Customer Deposits		32,485		29,795
Regulatory Liabilities - Current		41,911		69,483
Derivative Instruments		36,467		30,574
Other		5,151		1,678
Total Current Liabilities		418,471		463,056
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent		300,326		246,466
Regulatory Liabilities - Noncurrent		234,945		201,329
Derivative Instruments		20,403		22,969
Pension and Other Postretirement Benefits		139,356		127,343
Other		113,163		117,273
Total Deferred Credits and Other Liabilities		808,193		715,380
Commitments, Contingencies, and Proposed Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	3,985,231	$	3,791,243

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-83

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	September 30,	September 30,		September 30,			September 30,
			December 31,
			2011			2010
			- Thousands of Dollars -
COMMON STOCK EQUITY
Common Stock-No Par Value			$	725,903		$	715,687
	2011	2010
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	36,918,024	36,541,954
Accumulated Earnings				172,655			124,838
Accumulated Other Comprehensive Loss				(10,084	)		(9,769	)
Total Common Stock Equity				888,474			830,756
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding				—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1				253,481			302,229
Springerville Coal Handling Facilities				65,022			76,583
Springerville Common Facilities				111,699			110,571
Other				—			38
Total Capital Lease Obligations				430,202			489,421
Less Current Maturities				(77,482	)		(60,347	)
Total Long-Term Capital Lease Obligations				352,720			429,074
LONG-TERM DEBT
Issue	Maturity	Interest Rate
UniSource Energy:
Convertible Senior Notes	2035	4.50%		150,000			150,000
Credit Agreement	2016	Variable		57,000			27,000
Tucson Electric Power Company:
Variable Rate IDBs	2014 - 2016	Variable		215,300			365,300
Unsecured Fixed Rate IDBs	2020 - 2040	3.25% to 6.375%		615,855			638,315
Unsecured Notes	2021	5.15%		249,218			—
UNS Gas and UNS Electric:
Senior Unsecured Notes	2015 - 2026	5.39% to 7.1%		230,000			200,000
UED:
Secured Term Loan	2012	Variable		—			29,362
Total Stated Principal Amount				1,517,373			1,409,977
Less Current Maturities				—			(57,000	)
Total Long-Term Debt				1,517,373			1,352,977
Total Capitalization			$	2,758,567		$	2,612,807

See Notes to Consolidated Financial Statements.

K-84

UNISOURCE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

		September 30,		September 30,		September 30,			September 30,			September 30,
	Common Shares Outstanding*		Common Stock		Accumulated Earnings			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	- Thousands of Dollars -
Balances at December 31, 2008		35,458	$	687,360	$	5,590		$	(6,855	)	$	686,095
Comprehensive Income:
2009 Net Income						105,901						105,901
Unrealized Loss on Cash Flow Hedges (net of $33 income taxes)									51			51
Reclassification of Realized 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												106,954
Dividends, Including Non-Cash Dividend Equivalents						(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 Stock Compensation Plans		101		—								—
Other				4,490								4,490
Balances at December 31, 2009		35,851	$	696,206	$	68,925		$	(5,802	)	$	759,329
Comprehensive Income:
2010 Net Income						112,984						112,984
Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes)									(6,431	)		(6,431	)
Reclassification of Realized 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												109,017
Dividends, Including Non-Cash Dividend Equivalents						(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 Stock Compensation Plans		15		—								—
Other				6,206								6,206
Balances at December 31, 2010		36,542	$	715,687	$	124,838		$	(9,769	)	$	830,756
Comprehensive Income:
2011 Net Income						109,975						109,975
Unrealized Loss on Cash Flow Hedges (net of $2,376 income taxes)									(3,626	)		(3,626	)
Reclassification of Realized Losses on Cash Flow Hedges to Net Income (net of $1,412 income taxes)									2,153			2,153
Employee Benefit Obligations Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $804 income taxes)									1,158			1,158
Total Comprehensive Income												109,660
Dividends, Including Non-Cash Dividend Equivalents						(62,158	)					(62,158	)
Shares Issued for Stock Options		319		8,176								8,176
Shares Issued Under Stock Compensation Plans		57		—								—
Other				2,040								2,040
Balances at December 31, 2011		36,918	$	725,903	$	172,655		$	(10,084	)	$	888,474

* 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-85

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	- Thousands of Dollars -
Operating Revenues
Electric Retail Sales	$	903,930		$	868,188		$	867,516
Electric Wholesale Sales		129,861			141,103			153,306
California Power Exchange (CPX) Provision for Wholesale Refunds		—			(2,970	)		(4,172	)
Other Revenues		122,595			118,946			82,688
Total Operating Revenues		1,156,386			1,125,267			1,099,338
Operating Expenses
Fuel		318,268			284,744			279,303
Purchased Power		105,766			118,716			144,529
Transmission		(1,435	)		3,254			3,066
Decrease to Reflect PPFAC Recovery Treatment		(6,165	)		(21,541	)		(18,186	)
Total Fuel and Purchased Energy		416,434			385,173			408,712
Other Operations and Maintenance		330,801			316,625			282,986
Depreciation		104,894			99,510			116,970
Amortization		34,650			32,196			35,931
Taxes Other Than Income Taxes		40,226			37,732			37,406
Total Operating Expenses		927,005			871,236			882,005
Operating Income		229,381			254,031			217,333
Other Income (Deductions)
Interest Income		3,567			6,707			11,471
Other Income		5,693			6,629			10,996
Other Expense		(12,037	)		(11,506	)		(9,589	)
Total Other Income (Deductions)		(2,777	)		1,830			12,878
Interest Expense
Long-Term Debt		49,858			42,378			36,226
Capital Leases		40,358			46,734			49,258
Other Interest Expense		1,127			433			1,571
Interest Capitalized		(2,073	)		(1,880	)		(1,752	)
Total Interest Expense		89,270			87,665			85,303
Income Before Income Taxes		137,334			168,196			144,908
Income Tax Expense		52,000			59,936			54,220
Net Income	$	85,334		$	108,260		$	90,688

See Notes to Consolidated Financial Statements.

K-86

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	963,247		$	947,498		$	944,873
Cash Receipts from Electric Wholesale Sales		152,618			190,779			199,918
Cash Receipts from Operating Springerville Units 3 & 4		104,754			102,563			68,951
Reimbursement of Affiliate Charges		18,448			18,356			19,998
Cash Receipts from Wholesale Gas Sales		11,825			—			—
Income Tax Refunds Received		7,492			3,369			14,462
Interest Received		5,367			8,998			12,768
Performance Deposits Received		1,640			5,040			14,000
Other Cash Receipts		17,971			18,389			19,440
Payment of Other Operations and Maintenance Costs		(283,560	)		(245,050	)		(233,075	)
Fuel Costs Paid		(276,030	)		(236,436	)		(282,653	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(139,728	)		(134,540	)		(124,053	)
Purchased Power Costs Paid		(117,224	)		(169,658	)		(185,129	)
Wages Paid, Net of Amounts Capitalized		(100,942	)		(101,815	)		(97,289	)
Interest Paid, Net of Amounts Capitalized		(45,433	)		(38,232	)		(33,128	)
Capital Lease Interest Paid		(32,103	)		(38,640	)		(38,586	)
Wholesale Gas Costs Paid		(11,822	)		—			—
Income Taxes Paid		(2,346	)		(19,663	)		(14,606	)
Performance Deposits Paid		(1,640	)		(5,040	)		(14,000	)
Other Cash Payments		(4,240	)		(3,435	)		(3,827	)
Net Cash Flows - Operating Activities		268,294			302,483			268,064
Cash Flows from Investing Activities
Capital Expenditures		(351,890	)		(225,920	)		(240,079	)
Purchase of Intangibles - Renewable Energy Credits		(5,111	)		(7,903	)		—
Purchase of Sundt Unit 4 Lease Asset		—			(51,389	)		—
Purchase of Springerville Lease Debt		—			—			(31,375	)
Other Cash Payments		(558	)		(1,483	)		(411	)
Return of Investments in Springerville Lease Debt		38,353			25,615			12,736
Other Cash Receipts		7,195			8,044			9,528
Net Cash Flows - Investing Activities		(312,011	)		(253,036	)		(249,601	)
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt		260,285			118,245			—
Proceeds from Borrowings Under Revolving Credit Facility		220,000			177,000			171,000
Equity Investment from UniSource Energy		30,000			15,000			30,000
Other Cash Receipts		2,458			3,241			2,447
Repayments of Borrowings Under Revolving Credit Facility		(210,000	)		(212,000	)		(146,000	)
Repayments of Long-Term Debt		(172,460	)		(30,000	)		—
Payments of Capital Lease Obligations		(74,343	)		(55,889	)		(24,091	)
Payments of Debt Issue/Retirement Costs		(3,594	)		(5,988	)		(1,329	)
Dividends Paid to UniSource Energy		—			(60,000	)		(60,000	)
Other Cash Payments		(894	)		(1,491	)		(1,347	)
Net Cash Flows - Financing Activities		51,452			(51,882	)		(29,320	)
Net Increase (Decrease) in Cash and Cash Equivalents		7,735			(2,435	)		(10,857	)
Cash and Cash Equivalents, Beginning of Year		19,983			22,418			33,275
Cash and Cash Equivalents, End of Year	$	27,718		$	19,983		$	22,418

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-87

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

		September 30,			September 30,
	December 31,
	2011			2010
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,222,236		$	3,863,431
Utility Plant Under Capital Leases		582,669			582,669
Construction Work in Progress		76,517			153,981
Total Utility Plant		4,881,422			4,600,081
Less Accumulated Depreciation and Amortization		(1,753,807	)		(1,729,747	)
Less Accumulated Amortization of Capital Lease Assets		(476,963	)		(460,257	)
Total Utility Plant - Net		2,650,652			2,410,077
Investments and Other Property
Investments in Lease Debt and Equity		65,829			103,844
Other		32,313			43,588
Total Investments and Other Property		98,142			147,432
Current Assets
Cash and Cash Equivalents		27,718			19,983
Accounts Receivable - Customer		71,435			78,200
Unbilled Accounts Receivable		32,386			32,217
Allowance for Doubtful Accounts		(3,766	)		(4,106	)
Accounts Receivable - Due from Affiliates		4,049			5,444
Fuel Inventory		32,981			29,209
Materials and Supplies		70,749			54,732
Derivative Instruments		1,439			1,318
Regulatory Assets - Current		71,747			34,023
Deferred Income Taxes - Current		21,678			32,077
Other		13,753			26,467
Total Current Assets		344,169			309,564
Regulatory and Other Assets
Regulatory Assets - Noncurrent		157,386			182,304
Derivative Instruments		1,398			1,834
Other Assets		23,737			24,767
Total Regulatory and Other Assets		182,521			208,905
Total Assets	$	3,275,484		$	3,075,978

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-88

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

		September 30,		September 30,
	December 31,
	2011		2010
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	824,943	$	709,884
Capital Lease Obligations		352,720		429,074
Long-Term Debt		1,080,373		1,003,615
Total Capitalization		2,258,036		2,142,573
Current Liabilities
Current Obligations Under Capital Leases		77,482		60,309
Borrowing Under Revolving Credit Facility		10,000		-
Accounts Payable - Trade		84,508		77,021
Accounts Payable - Due to Affiliates		4,827		3,990
Interest Accrued		30,877		31,771
Accrued Taxes Other than Income Taxes		32,155		29,873
Accrued Employee Expenses		21,356		23,710
Customer Deposits		23,743		21,191
Derivative Instruments		9,040		7,288
Regulatory Liabilities - Current		23,702		58,936
Other		4,524		3,379
Total Current Liabilities		322,214		317,468
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent		263,225		227,615
Regulatory Liabilities - Noncurrent		200,599		170,223
Derivative Instruments		14,142		11,650
Pension and Other Postretirement Benefits		130,660		120,590
Other		86,608		85,859
Total Deferred Credits and Other Liabilities		695,234		615,937
Commitments, Contingencies, and Proposed Envirionmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	3,275,484	$	3,075,978

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-89

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	September 30,	September 30,		September 30,			September 30,
			December 31,
			2011			2010
			- Thousands of Dollars -
COMMON STOCK EQUITY
Common Stock-No Par Value			$	888,971		$	858,971
	2011	2010
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				(47,627	)		(132,961	)
Accumulated Other Comprehensive Loss				(10,044	)		(9,769	)
Total Common Stock Equity				824,943			709,884
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding				—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1				253,481			302,229
Springerville Coal Handling Facilities				65,022			76,583
Springerville Common Facilities				111,699			110,571
Total Capital Lease Obligations				430,202			489,383
Less Current Maturities				(77,482	)		(60,309	)
Total Long-Term Capital Lease Obligations				352,720			429,074
LONG-TERM DEBT
Issue	Maturity	Interest Rate
Variable Rate IDBs	2014 - 2016	Variable		215,300			365,300
Unsecured Fixed Rate IDBs	2020 - 2040	3.25% to 6.375%		615,855			638,315
Unsecured Notes	2021	5.15%		249,218			—
Total Long-Term Debt				1,080,373			1,003,615
Total Capitalization			$	2,258,036		$	2,142,573

See Notes to Consolidated Financial Statements.

K-90

TUCSON ELECTRIC POWER COMPANY

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

		September 30,		September 30,			September 30,			September 30,			September 30,
	Common Stock		Capital Stock Expense			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	- Thousands of Dollars -
Balances at December 31, 2008	$	813,971	$	(6,357	)	$	(211,146	)	$	(6,855	)	$	589,613
Comprehensive Income:
2009 Net Income							90,688						90,688
Unrealized Loss on Cash Flow Hedges (net of $33 income taxes)										51			51
Reclassification of Realized 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													91,741
Capital Contribution from UniSource Energy		30,000											30,000
Dividends							(60,763	)					(60,763	)
Balances at December 31, 2009		843,971		(6,357	)		(181,221	)		(5,802	)		650,591
Comprehensive Income:
2010 Net Income							108,260						108,260
Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes)										(6,431	)		(6,431	)
Reclassification of Realized 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													104,293
Capital Contribution from UniSource Energy		15,000											15,000
Dividends Paid							(60,000	)					(60,000	)
Balances at December 31, 2010		858,971		(6,357	)		(132,961	)		(9,769	)		709,884
Comprehensive Income:
2011 Net Income							85,334						85,334
Unrealized Loss on Cash Flow Hedges (net of $2,331 income taxes)										(3,555	)		(3,555	)
Reclassification of Realized Losses on Cash Flow Hedges to Net Income (net of $1,390 income taxes)										2,122			2,122
Employee Benefit Obligations Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $804 income taxes)										1,158			1,158
Total Comprehensive Income													85,059
Capital Contribution from UniSource Energy		30,000											30,000
Balances at December 31, 2011	$	888,971	$	(6,357	)	$	(47,627	)	$	(10,044	)	$	824,943

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

See Notes to Consolidated Financial Statements.

K-91

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. Each of UniSource Energy’s subsidiaries 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 82% of UniSource Energy’s total assets as of December 31, 2011. TEP generates, transmits and distributes electricity to approximately 404,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily 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 Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).

UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 148,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated public utility, which generates, transmits and distributes electricity to approximately 91,000 retail customers in Mohave and Santa Cruz counties.

UED developed the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility includes two natural gas-fired combustion turbines. Prior to July 2011, UNS Electric received energy from BMGS through a power sales agreement with UED. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no impact on UniSource Energy’s consolidated financial statements.

Millennium’s investments in unregulated businesses represent less than 1% of UniSource Energy’s assets as of December 31, 2011. Millennium’s $13 million net loss for 2010, which reflected impairment losses, caused it to be a reportable segment at December 31, 2010. Millennium is not a reportable segment at December 31, 2011.

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

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

REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS

In the second and third quarters of 2011, we identified errors related to amounts recorded as owed to or payable by TEP for electricity deliveries settled in-kind or to be settled in-kind during prior years under our transmission, interconnection and certain joint operating agreements. These agreements typically provide that the parties to such agreements will monitor transmission and delivery losses and other energy imbalances and make payments to each other to compensate for any losses and imbalances. Payments for such losses and imbalances are made in-kind with energy (MWh) rather than cash. The amount of these losses and imbalances is typically a very low portion of the energy flows subject to these agreements and is usually settled on a one day or one month lag. We also identified minor errors to prior year amounts billed to third parties for operations and maintenance expense. Separately, in the second quarter of 2011, we identified errors in prior years in the calculation of income tax expense arising from not treating Allowance for Equity Funds Used During Construction (AFUDC) as a permanent book to tax difference.

We assessed the materiality of these errors on prior period financial statements and concluded they were not material to any prior annual or interim periods, but the cumulative impact, if recognized in 2011, could be material to the annual period ending December 31, 2011 and the interim period ended June 30, 2011. As a result, in accordance with Staff Accounting Bulletin 108, we revised our prior period financial statements to correct these

K-92

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

errors. We assessed the materiality of the third quarter 2011 errors, together with the errors identified in the first half of 2011, on prior period financial statements and concluded that, while they were not material to any prior annual or interim periods, we should update the prior revision to reflect all of the errors identified in 2011.

The income tax adjustment affected fiscal years 2003 through 2010 for UniSource Energy and fiscal years 2009 and 2010 for TEP. The adjustment for transmission and delivery losses and energy imbalances settled in-kind or to be settled in-kind affected fiscal years 2004 through 2010. The operations and maintenance expense adjustment affected fiscal years 2006 through 2010. The revision increased UniSource Energy’s net income by $2 million for each of the years ended December 31, 2010 and 2009. The revision increased TEP’s net income by $1 million for each of the years ended December 31, 2010 and 2009. UniSource Energy’s Accumulated Earnings increased by $7 million for the periods prior to January 1, 2009, as a result of the revisions.

The revised amounts include reclassifications to conform to the current year presentation. TEP reclassified Other Operations and Maintenance costs of $7 million in 2010, and $6 million in 2009 to Other Expense to correctly account for the regulatory treatment of certain expenses.

The revision and reclassifications impacted statements of income and balance sheets as shown in the tables below:

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy						TEP
	Year Ended December 31, 2010
	As Reported			As Revised			As Reported			As Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	151,673		$	151,962		$	140,815		$	141,103
Fuel		296,980			295,652			286,071			284,744
Purchased Energy		307,288			307,288			118,716			118,716
Decrease to Reflect PPFAC/PGA Recovery Treatment		(31,105	)		(29,622	)		(23,025	)		(21,541	)
Other Operations and Maintenance		370,067			370,037			323,537			316,625
Income Tax Expense		78,266			76,921			61,057			59,936
Net Income		111,477			112,984			106,978			108,260
Basic EPS		3.06			3.10			N/A			N/A
Diluted EPS		2.82			2.86			N/A			N/A
Balance Sheet
Accounts Receivable -Customer		91,556			98,333			71,425			78,200
Deferred Income Taxes –Current Assets		32,386			30,822			33,640			32,077
Regulatory Assets -Noncurrent		196,736			192,966			186,074			182,304
Common Stock Equity		828,368			830,756			707,495			709,884
Accounts Payable -Trade		109,896			108,950			77,967			77,021
Deferred Income Taxes –Noncurrent Liabilities		246,466			246,466			227,615			227,615

K-93

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy						TEP
	Year Ended December 31, 2009
	As Reported			As Revised			As Reported			As Revised
	-Thousands of Dollars- (Except Per Share Amounts)
Income Statement
Electric Wholesale Sales	$	130,904		$	131,255		$	152,955		$	153,306
Fuel		298,655			296,248			281,710			279,303
Purchased Energy		296,861			296,861			144,528			144,529
Decrease to Reflect PPFAC/PGA Recovery Treatment		(17,091	)		(14,553	)		(20,724	)		(18,186	)
Other Operations and Maintenance		333,887			333,579			289,765			282,986
Income Tax Expense		64,348			63,232			55,130			54,220
Net Income		104,258			105,901			89,248			90,688
Basic EPS		2.91			2.95			N/A			N/A
Diluted EPS		2.69			2.73			N/A			N/A

BASIS OF PRESENTATION

We consolidate our investments in subsidiaries 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 used the equity and cost methods to report Millennium’s investments until the assets became fully impaired in 2010. See Note 13.

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

We 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, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer Retail Rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through billing reductions. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

We apply regulatory accounting as the following conditions exist:

• 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.

K-94

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 includes the business property and equipment that supports electric and gas services, consisting primarily of generation, transmission and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, contractor services, construction overhead (where applicable), and an Allowance for Funds Used During Construction (AFUDC).

We record the cost of repairs and maintenance, including planned major overhauls to Other Operations and Maintenance Expense on the income statements as the costs are incurred.

When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage value. There is no income statement impact.

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 amounts capitalized are included in rate base for establishing Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The interest capitalized that relates to debt reduces Other Interest Expense on the income statements. The cost capitalized for equity funds is recorded as Other Income.

		September 30,			September 30,			September 30,
Average AFUDC Rate on Regulated Construction Expenditures	2011			2010			2009
TEP		6.72	%		6.65	%		6.40	%
UNS Gas		8.32	%		8.19	%		7.05	%
UNS Electric		8.18	%		8.22	%		7.62	%

UniSource Energy capitalized interest at a rate of 3.30% for 2011 and 1.96% for 2010 related to the development of a new corporate headquarters.

Depreciation

We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 5. The ACC approves depreciation rates for all utility plant. TEP transmission assets 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. Below are the summarized average annual depreciation rates for all utility plants.

		September 30,			September 30,			September 30,			September 30,
	TEP			UNS Gas			UNS Electric			UED
2011		3.15	%		3.32	%		4.31	%		3.03	%
2010		3.14	%		2.83	%		4.35	%		2.57	%
2009		3.64	%		2.76	%		4.33	%		2.57	%

K-95

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Computer Software Costs

We 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 income statements. The lease terms are described in Note 6.

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP holds investments in lease debt in TEP’s Springerville Unit 1 capital leases. These holdings are considered 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. The fair value of these investments is described in Note 11. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to debt and equity holders.

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

JOINTLY-OWNED FACILITIES

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

ASSET RETIREMENT OBLIGATIONS

TEP and UNS Electric record 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 and UNS Electric capitalize the cost by increasing the carrying amount of the related long-lived asset. TEP and UNS Electric adjust the liability to its present value by recognizing accretion expense 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.

TEP and UNS Electric record cost of removal for generation assets that are recoverable through Retail Rates charged to customers. See Note 2. We record cost of removal for transmission and distribution assets through depreciation rates and recover those amounts in Retail Rates charged to customers. There are no legal obligations associated with these assets. We have recorded an obligation for estimated costs of removal as regulatory liabilities.

EVALUATION OF ASSETS FOR IMPAIRMENT

We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If discounted expected future cash flows are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other than temporary and the loss is not recoverable through rates, and the asset is written down to the fair value of the asset.

K-96

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DEFERRED FINANCING COSTS

We defer the costs to issue debt and amortize such costs to interest expense 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.

We 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.

UTILITY OPERATING REVENUES

We 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.

We determine amounts delivered through periodic 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 Retail 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 Retail Rates and changes in the composition of customer classes.

We are authorized a rate-adjustment mechanism that provides for the recovery of actual fuel, transmission and purchased power/energy cost. The revenue surcharge or surcredit adjusts the customers’ retail rate for delivered electricity or gas to collect or return under- or over- recovered energy costs. The ACC revises these rate-adjustment mechanisms periodically (annually for TEP and UNS Electric; monthly for UNS Gas) and may increase or decrease the level of costs recovered through Retail Rates for any difference between the total amount collected under the clauses and the recoverable costs incurred. See Note 2.

Arizona’s mandatory Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy and allows recovery of RES compliance costs through a surcharge to customers. We charge customers a Demand Side Management (DSM) surcharge to recover the cost of ACC-approved energy efficiency programs. We defer differences between actual RES or DSM qualified costs incurred and the recovery of such costs through the RES and DSM surcharges. Cost over-recoveries (the excess of cost recoveries through the RES and DSM surcharges over actual qualified costs incurred) are deferred as regulatory liabilities and cost under-recoveries (the excess of actual qualified costs incurred over cost recoveries through the RES and DSM surcharges) are deferred as regulatory assets. The surcharges are reset annually and incorporate an adjustor mechanism that, upon approval of the ACC, allows us to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s RES or DSM surcharge. See Note 2.

For contracts that are not settled with energy, TEP nets the sales contracts with the purchase power contracts and reflects the net amount as Electric Wholesale Sales. The corresponding cash receipts are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales, while cash payments are recorded as Purchased Energy Costs Paid.

We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales and economic conditions. We refer uncollected accounts to external collection agencies after 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 at the Springerville generating station. Tri-State and SRP also pay TEP for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities which are recorded as Other Revenues. Operating expenses are recorded in the respective line item of the income statements based on the nature of service or materials provided.

K-97

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

INVENTORY

Materials and supplies consist of transmission, distribution and generation construction and repair materials. We record fuel, materials and supply inventories at the lower of weighted average cost or market prices. We capitalize handling and procurement costs (such as materials, labor, overhead costs and transportation costs) as part of the cost of the inventory.

RECOVERY OF FUEL AND PURCHASED ENERGY COSTS

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

TEP and UNS Electric defer differences between actual fuel, transmission and purchased power costs and current PPFAC costs incurred and the recovery of such costs in base rates. Cost over-recoveries (the excess of fuel costs recoveries in Base Rates over actual costs incurred) are deferred as regulatory liabilities and cost under-recoveries (the excess of actual 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 actual gas costs incurred and the recovery of such costs under a Purchased Gas Adjustor (PGA) mechanism. Gas cost over-recoveries (the excess of gas costs recovered under the PGA mechanism over actual gas costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of actual gas costs incurred over gas costs recovered via the PGA mechanism) are deferred as regulatory assets. See Note 2.

RENEWABLE ENERGY CREDITS (RECs)

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.

When RECs are purchased, TEP and UNS Electric record the cost of the RECs as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. Unretired RECs are recorded as Other Assets on the balance sheet. RECs are expensed to the income statements when the RECs are reported to the ACC for compliance with the RES requirements. See Note 2.

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.

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.

K-98

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

We act as conduits or collection agents for sales taxes, utility taxes, franchise fees and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies for these taxes and assessments. These amounts are not reflected in the income statements.

DERIVATIVE FINANCIAL INSTRUMENTS

Risks and Overview

We are exposed to energy price risk associated with gas and purchased power requirements, volumetric risk associated with seasonal load, and operational risk associated with power plants, transmission and transportation systems. We reduce our energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability; ensuring we can meet load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Note 2.

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 current and long-term portions on the balance sheet.

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. UNS Electric entered into a cash flow hedge in August 2011 to fix the UNS Electric term loan variable interest rate. TEP and UNS Electric account for cash flow hedges as follows:

• The effective portion of the changes in the fair value of the 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 and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC.

In 2009 through 2011 we had no trading activity.

• UNS Gas

UNS Gas enters into derivative contracts 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. 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.

Normal Purchase and Normal Sale

We enter into forward energy purchase and sales contracts, including call options, to support our current load forecasts, with counterparties for load serving requirements or counterparties with 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.

PENSION AND OTHER POSTRETIREMENT BENEFITS

We 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. We 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 we evaluate annually. See Note 9.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 2. REGULATORY MATTERS

RATES AND REGULATION

The ACC and the FERC each regulate portions of the utility accounting practices and rates used by TEP, UNS Gas and UNS Electric. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, and transactions with affiliated parties. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

TEP 2008 Rate Order

The 2008 TEP Rate Order, issued by the ACC and effective December 1, 2008, provided an average base rate increase of 6% over TEP’s previous Base Rates; an 8% authorized rate of return on original cost rate base; a fuel rate included in Base Rates of 2.9 cents per kilowatt-hour (kWh); a PPFAC effective January 1, 2009; and a base rate increase moratorium through January 1, 2013.

2010 UNS Gas Rate Order

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

Pending UNS Gas Rate Case

In April 2011, UNS Gas filed a general rate case (on a cost-of-service basis) with the ACC requesting a base rate increase of 3.8% to cover a revenue deficiency of $5.6 million.

In February 2012, ACC Staff recommended a base rate increase of $2.7 million as well as a mechanism to enable UNS Gas to recover lost fixed-cost revenues as a result of implementing the ACC’s EE Standards. The ACC is expected to issue a final order in the second quarter of 2012.

2008 UNS Electric Rate Order

In May 2008, the ACC approved a base rate increase of 2.5% ($4 million) effective June 2008.

2010 UNS Electric Rate Order

In September 2010, the ACC approved a base rate increase of 4% ($7 million), including an 8% authorized rate of return on original cost rate base, effective October 1, 2010. The ACC approved new depreciation rates effective in October 2010.

In July 2011, UNS Electric completed the ACC and FERC approved purchase of BMGS from UED for $63 million, UED’s book value for the assets. BMGS was 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.

COST RECOVERY MECHANISMS

TEP, UNS Gas and UNS Electric have received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Purchased Power and Fuel Adjustment Clause (PPFAC)

The PPFAC provides for the adjustment of Retail Rates to reflect variations in retail fuel, transmission and purchased power costs, including demand charges, and the prudent costs of contracts for hedging fuel. TEP and UNS Electric record deferrals for recovery or refund to the extent actual retail fuel, transmission and purchased power costs vary from the fuel rate and current PPFAC rates. The TEP PPFAC became effective in January 2009. A PPFAC rate adjustment is made annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period automatically unless suspended by the ACC. UNS Electric’s PPFAC rate adjustment is made annually each June 1^st, effective for the subsequent 12-month period.

The PPFAC rate includes (a) a “Forward Component,” under which TEP and UNS Electric recover or refund differences between forecasted fuel, transmission and purchased power costs for the upcoming calendar year and those embedded in the fuel rate and the current PPFAC rates; (b) a “True-up Component,” which reconciles differences between actual fuel, transmission and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.

The table below summarizes TEP’s and UNS Electric’s PPFAC rates in cents per kWh that are compared against actual fuel cost to create regulatory assets or liabilities:

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	2011									2010
	June - December			April - May			January - March			June – December			April - May			January - March(2)
TEP
PPFAC		0.53			0.53			0.09			0.09			0.09			0.18
CTC(1)		(0.53	)		(0.53	)		(0.09	)		(0.09	)		(0.09	)		(0.18	)
Total PPFAC Rate		—			—			—			—			—			—
UNS Electric		(0.88	)		0.08			0.08			(0.28	)		(1.06	)		(1.06	)

(1) Competition Transition Charge

(2) TEP’s first PPFAC rate began April 2009 at 0.18 cents per kWh. UNS Electric’s PPFAC rate from January to May 2009 was 1.50 cents per kWh, and the PPFAC rate from June to December 2009 was (1.06) cents per kWh.

As part of the 2008 Rate Order, TEP was required to credit previously collected revenues to customers through the PPFAC. As a result, the PPFAC charge has been zero since it became effective in January 2009. In November 2011, the Fixed CTC revenue was fully refunded to customers and TEP began deferring the PPFAC eligible costs until a new PPFAC rate is approved by the ACC.

The following table shows the changes in TEP’s PPFAC related accounts and the impacts on revenue and expense for the year ended December 31, 2011:

		September 30,		September 30,			September 30,		September 30,
	Assets (Liability) at December 31,					Year Ended December 31, 2011
	2011		2010			Increase to Revenue		Reduction to Fuel and Purchased Power Expense
	-Millions of Dollars-
PPFAC - Fixed CTC Revenue to be Refunded (current and noncurrent)	$	—	$	(36	)	$	36
PPFAC (current and noncurrent)	$	60	$	54				$	6

For the year ended December 31, 2010, changes in the deferred PPFAC regulatory asset (liability) resulted in a $10 million increase to revenue and a $22 million decrease to fuel and purchased power expense.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Gas Purchased Gas Adjustor (PGA)

The PGA mechanism provides for the adjustment of Retail Rates to reflect variations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than $0.15 per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million or more on a billed basis.

The PGA rate ranged from $0.6593 to $0.7296 cents per therm in 2011, and ranged from $0.6433 to $0.7306 cents per therm in 2010.

RES and Energy Efficiency Standards

The ACC has a mandatory 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 DSM surcharges established by the ACC.

The following table shows RES and DSM tariffs collected:

		September 30,		September 30,		September 30,		September 30,		September 30,
	TEP RES		UNS Electric RES		TEP DSM		UNS Gas DSM		UNS Electric DSM
	-Millions of Dollars-
2011	$	35	$	7	$	11	$	1	$	2
2010		32		7		10		1		2
2009		29		5		7		1		1

Renewable Energy Standard

In 2010, the ACC approved:

• A funding mechanism for approximately $14 million of TEP-owned renewable energy projects in 2010, and approximately $5 million in UNS Electric owned solar projects per year between 2011 and 2014. TEP’s projects were completed in 2010, and TEP began recovering its costs through the RES tariff in January 2011.

• TEP’s 2011 RES implementation plan. As approved by the plan, TEP invested $28 million in TEP-owned solar projects in 2011.

In 2011, the ACC approved TEP’s 2012 RES implementation plan. The plan allows TEP to invest $28 million in 2012, and $8 million in 2013 for TEP-owned solar projects.

The funding mechanism allows TEP and UNS Electric to use RES funds to recover operating costs, depreciation, and property taxes and to earn a return on company-owned solar projects until the projects can be incorporated in Base Rates.

TEP and UNS Electric entered into multiple ACC approved long-term purchase power agreements with companies developing renewable energy generation facilities. 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Electric Energy Efficiency Standards

In 2010, the ACC approved new Electric Energy Efficiency (EE) Standards designed to require TEP and UNS Electric to implement cost-effective Demand Side Management (DSM) programs, effective in 2011. In 2011, the EE Standards targeted total retail kWh savings equal to 1.25% of 2010 sales increasing to 22% by 2020. The EE Standards provide for a DSM surcharge to recover the costs to implement DSM programs.

In January 2012, the ACC granted UNS Electric a waiver from complying with the 2011 and 2012 EE Standards.

The ACC approved new Gas EE Standards which required UNS Gas to implement cost effective DSM programs to reduce total retail therm sales in 2011, by 701,113 therms, or 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 January 2012, TEP filed a modification to its 2012/2013 Energy Efficiency Implementation Plan with the ACC. The proposal includes a request for an increase in the performance incentive based on TEP’s ability to meet the EE targets for 2012 and for 2013. TEP’s proposed annual performance incentive in each of 2012 and 2013 ranges from $6 million to $8 million.

Renewable Energy Credits

The following table shows the REC activity for 2011 and 2010:

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy									TEP
	December 31,						December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Beginning Balance, included in Other Assets	$	3		$	—		$	2		$	—
RECs Purchased		6			8			5			8
RECs Recovered Through Revenues (RES surcharge)		(8	)		(5	)		(7	)		(6	)
Ending Balance, included in Other Assets	$	1		$	3		$	—		$	2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Regulatory Assets and Liabilities

The following tables summarize regulatory assets and liabilities:

		September 30,			September 30,			September 30,			September 30,
	December 31, 2011
	TEP			UNS Gas			UNS Electric			UniSource Energy
	-Millions of Dollars-
Regulatory Assets—Current
Property Tax Deferrals(1)	$	16		$	—		$	—		$	16
Derivative Instruments (Notes 11 and 16)		7			7			10			24
Deregulation Costs(2)		3			—			—			3
PPFAC(3)		34			—			7			41
DSM(3)		8			—			1			9
Other Current Regulatory Assets(4)		4			—			—			4
Total Regulatory Assets—Current		72			7			18			97
Regulatory Assets—Noncurrent
Pension and Other Postretirement Benefits (Note 9)		107			3			4			114
Income Taxes Recoverable through Future Revenues(5)		10			—			2			12
PPFAC/PGA(3)		6			—			—			6
PPFAC—Final Mine Reclamation and Retiree Health Care Costs(6)		20			—			—			20
Derivative Instruments (Notes 11 and 16)		2			2			3			7
Other Regulatory Assets(4)		12			1			1			14
Total Regulatory Assets—Noncurrent		157			6			10			173
Regulatory Liabilities—Current
PPFAC/PGA(7)		—			(15	)		—			(15	)
RES(7)		(22	)		—			(3	)		(25	)
Other Current Regulatory Liabilities		(2	)		—			—			(2	)
Total Regulatory Liabilities—Current		(24	)		(15	)		(3	)		(42	)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements(8)		(198	)		(23	)		(10	)		(231	)
Other Regulatory Liabilities		(3	)		(1	)		—			(4	)
Total Regulatory Liabilities—Noncurrent		(201	)		(24	)		(10	)		(235	)
Total Net Regulatory Assets (Liabilities)	$	4		$	(26	)	$	15		$	(7	)

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,			September 30,			September 30,			September 30,
	December 31, 2010
	TEP			UNS Gas			UNS Electric			UniSource Energy
	-Millions of Dollars-
Regulatory Assets—Current
Property Tax Deferrals(1)	$	16		$	—		$	—		$	16
Derivative Instruments (Notes 11 and 16)		5			8			12			25
Deregulation Costs(2)		4			—			—			4
PPFAC(3)		—			—			3			3
DSM(3)		5			—			—			5
Other Current Regulatory Assets(4)		4			—			—			4
Total Regulatory Assets—Current		34			8			15			57
Regulatory Assets—Noncurrent
Pension and Other Postretirement Benefits (Note 9)		90			2			2			94
Income Taxes Recoverable through Future Revenues(5)		22			—			1			23
PPFAC/PGA(3)		37			—			—			37
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (6)		17			—			—			17
Deregulation Costs(2)		3			—			—			3
Derivative Instruments (Notes 11 and 16)		—			2			2			4
Other Regulatory Assets(4)		13			2			—			15
Total Regulatory Assets—Noncurrent		182			6			5			193
Regulatory Liabilities—Current
PPFAC/PGA(7)		—			(9	)		—			(9	)
PPFAC—Fixed CTC Revenue to be Refunded(7)		(36	)		—			—			(36	)
RES(7)		(22	)		—			(1	)		(23	)
Other Current Regulatory Liabilities		(1	)		—			—			(1	)
Total Regulatory Liabilities—Current		(59	)		(9	)		(1	)		(69	)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements(8)		(169	)		(22	)		(9	)		(200	)
Other Regulatory Liabilities		(1	)		—			—			(1	)
Total Regulatory Liabilities—Noncurrent		(170	)		(22	)		(9	)		(201	)
Total Net Regulatory Assets (Liabilities)	$	(13	)	$	(17	)	$	10		$	(20	)

Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets and state when we earn a return below:

(1) Property Tax is recovered over an approximately six-month period as costs are paid, rather than as costs are accrued.

(2) Deregulation costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders, as authorized by the ACC. TEP earns a return on this asset and is recovering these costs through Retail Rates over a four-year period ending November 2012.

(3) See Cost Recovery Mechanisms discussion.

(4) TEP’s other assets include unamortized loss on reacquired debt (recovery through 2032); coal contract amendment (recovery through 2017); and other assets (recovery through 2014). UNS Gas’ other assets consist of rate case costs (recovery over 3 years), and costs of the low income assistance program.

(5) Income Taxes Recoverable through Future Revenues are amortized over the life of the 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 mine 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 remaining life of the mines, which is estimated to be between 15 and 21 years.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(7) See Cost Recovery Mechanisms discussion above.

(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 and UNS Electric have also collected amounts for generation plant, which they have not yet expended.

Income Statement Impact of Applying Regulatory Accounting

Regulatory accounting had the following effects on TEP’s net income:

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	-Millions of Dollars-
TEP
Operating Revenues
Amortization of the Fixed CTC Revenue to be Refunded	$	36		$	10		$	13
Operating Expenses
Depreciation (related to Net Cost of Removal for Interim Retirements)		(29	)		(30	)		(41	)
Deferral of PPFAC Costs		6			22			18
Other		—			(8	)		(16	)
Non-Operating Income/Expenses
Long-Term Debt (Amortization of Loss on Reacquired Debt Costs)		1			1			—
AFUDC—Equity		4			4			4
Income Taxes—Deferral		(8	)		1			—
Offset by the Tax Effect of the Above Adjustments		(4	)		—			9
Net (Decrease)/Increase to Net Income	$	6		$	—		$	(13	)

UNS Gas and UNS Electric would have recognized the difference between expected and actual purchased energy costs and commodity derivative unrealized gains or losses as a change in income statement expense, rather than as a change in regulatory balances.

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	-Millions of Dollars-
UNS Gas
Net (Decrease)/Increase to Net Income	$	(5	)	$	(1	)	$	6
UNS Electric
Net (Decrease)/Increase to Net Income		3			(7	)		7

Future Implications of Discontinuing Application of Regulatory Accounting

We regularly assess whether we can continue to apply regulatory accounting to regulated operations, and concluded regulatory accounting is applicable. If we stopped applying regulatory accounting to our 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 statements;

• At December 31, 2011, based on the regulatory assets balances, net of regulatory liabilities:

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

• TEP would have recorded an extraordinary after-tax gain of $62 million and an after-tax loss in AOCI of $64 million;

• UNS Gas would have recorded an extraordinary after-tax gain of $18 million and an after-tax loss in AOCI of $2 million; and

• UNS Electric would have recorded an extraordinary after-tax loss of $6 million and an after-tax loss in AOCI of $3 million.

While future regulatory orders and market conditions may affect cash flows, our cash flows would not be affected if we stopped applying regulatory accounting to our regulated operations.

NOTE 3. SEGMENT AND RELATED INFORMATION

We have three reportable segments that are determined based on the way we organize our operations and evaluate performance:

(1) TEP, a regulated electric utility business, is our largest subsidiary;

(2) UNS Gas is a regulated gas distribution utility business; and

(3) UNS Electric is a regulated electric utility business.

Results for the UniSource Energy and UES holding companies, Millennium and UED are included in Other below.

In accordance with accounting rules related to the transfer of a business held under common control, we reflect UNS Electric’s purchase of BMGS as if it occurred on January 1, 2009. UNS Electric’s net income and reconciling adjustments in the table below increased by $3 million for the year ended December 31, 2011, and $5 million for each of the years ended December 31, 2010 and 2009. The transaction had no impact on UniSource Energy’s consolidated financial statements. In addition, the segments disclosed in the 2010 and 2009 sections of the table below were revised to move Millennium into the “Other” segment as it is no longer a reportable segment.

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

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Reportable Segments
2011	TEP			UNS Gas			UNS Electric			Other			Reconciling Adjustments			UniSource Energy
	-Millions of Dollars-
Income Statement
Operating Revenues-External	$	1,141		$	149		$	219		$	—		$	1		$	1,510
Operating Revenues- Intersegment		15			2			2			23			(42	)		—
Depreciation and Amortization		140			8			17			1			(1	)		165
Interest Income		4			—			—			1			—			5
Interest Expense		89			7			7			9			—			112
Income Tax Expense (Benefit)		52			7			11			(1	)		(2	)		67
Net Income (Loss)		85			10			18			—			(3	)		110
Cash Flow Statement
Capital Expenditures		(352	)		(13	)		(96	)		(34	)		121			(374	)
Balance Sheet
Total Assets		3,275			319			370			1,172			(1,151	)		3,985

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Reportable Segments
2010	TEP			UNS Gas			UNS Electric			Other			Reconciling Adjustments			UniSource Energy
	-Millions of Dollars-
Income Statement
Operating Revenue-External	$	1,096		$	144		$	213		$	—		$	1		$	1,454
Operating Revenue- Intersegment		29			6			2			28			(65	)		—
Depreciation and Amortization		132			8			16			2			(2	)		156
Interest Income		7			—			—			1			—			8
Interest Expense		88			7			7			9			—			111
Net Loss from Equity Method Investments		—			—			—			(6	)		—			(6	)
Income Tax Expense (Benefit)		60			6			10			4			(3	)		77
Net Income (Loss)		108			9			15			(14	)		(5	)		113
Cash Flow Statement
Capital Expenditures		(277	)		(12	)		(24	)		(18	)		—			(331	)
Balance Sheet
Total Assets		3,076			310			356			1,152			(1,103	)		3,791
2009
Income Statement
Operating Revenues-External	$	1,065		$	148		$	183		$	—		$	1		$	1,397
Operating Revenues- Intersegment		34			5			4			28			(71	)		—
Depreciation and Amortization		153			7			16			2			(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)		54			5			7			—			(3	)		63
Net Income (Loss)		91			7			11			2			(5	)		106
Cash Flow Statement
Capital Expenditures		(240	)		(15	)		(29	)		(10	)		—			(294	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

		September 30,		September 30,		September 30,		September 30,
	Reportable Segments
	TEP		UNS Gas		UNS Electric		Other
	-Millions of Dollars-
Intersegment Revenue
2011:
Wholesale Sales—TEP to UNS Electric(4)	$	2	$	—	$	—	$	—
Wholesale Sales—UNS Electric to TEP(4)		—		—		2		—
Wholesale Sales—UED to UNS Electric		—		—		—		5
Wholesale Sales—UNS Gas to TEP(5)		—		—		—		—
Gas Revenue—UNS Gas to UNS Electric		—		2		—		—
Other Revenue—TEP to Affiliates(1)		10		—		—		—
Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas(2)		—		—		—		18
Other Revenue—TEP to UNS Electric(3)		3		—		—		—
Total Intersegment Revenue	$	15	$	2	$	2	$	23
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	$	28
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	$	28

(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 $17 million in 2011, $16 million in 2010, and $15 million in 2009 for these services.

(3) TEP charged UNS Electric for control area services based on a FERC approved tariff.

(4) TEP and UNS Electric sell power to each other at Dow Jones Four Corners Daily Index prices.

(5) Starting in 2010, UNS Gas provides gas to TEP for generation of power at third-party market prices.

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 2011, 2010, and 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 $2 million in 2011, $3 million in 2010, and $2 million in 2009.

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.

NOTE 4. COMMITMENTS, CONTINGENCIES, AND PROPOSED ENVIRONMENTAL MATTERS

TEP COMMITMENTS

Firm Purchase Commitments

At December 31, 2011, TEP had the following firm non-cancelable purchase commitments (minimum purchase obligations) and operating leases:

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	Purchase Commitments
	2012		2013		2014		2015		2016		Thereafter		Total
	-Millions of Dollars-
Fuel (including Transportation)	$	84	$	59	$	58	$	44	$	41	$	75	$	361
Purchased Power		29		21		17		13		13		184		277
Solar Equipment		12		12		—		—		—		—		24
Transmission		3		3		3		3		3		23		38
Operating Leases		2		2		2		1		1		10		18
Total Unrecognized Firm Commitments	$	130	$	97	$	80	$	61	$	58	$	292	$	718

Fuel, Purchased Power and Transmission 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 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 2012 and 2014. 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, 2011.

Additionally, Purchased Power includes two 20-year Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011. TEP is obligated to purchase 100% of the output from these facilities. TEP has additional long-term renewable PPAs to comply with the RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational.

Fuel, purchased power and transmission costs are recoverable from customers through the PPFAC.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Solar Equipment

TEP has a commitment to purchase 9 MW of photovoltaic equipment through December 2013. The ACC approved 6 MW, and we are seeking approval from the ACC for the remaining 3 MW in 2012. TEP spent $10 million in 2011 under this contract. TEP earns a return on company-owned solar projects. See Note 2.

Operating Leases

TEP’s aggregate operating lease expense is primarily for rail cars, office facilities and computer equipment, with varying terms, provisions, and expiration dates. This expense totaled $2 million in each of 2011, 2010, and 2009.

UNS GAS and UNS ELECTRIC COMMITMENTS

At December 31, 2011, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in the table below:

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	Purchase Commitments
	2012		2013		2014		2015		2016		Thereafter		Total
	-Millions of Dollars-
Total Unrecognized Firm Commitments – Fuel	$	23	$	12	$	10	$	6	$	6	$	21	$	78

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, 2011. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2012 and 2024.

At December 31, 2011, UNS Electric had various firm non-cancelable purchase commitments as described in the table below:

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	Purchase Commitments
	2012		2013		2014		2015		2016		Thereafter		Total
	-Millions of Dollars-
Purchased Power	$	54	$	40	$	31	$	3	$	3	$	43	$	174
Transmission		4		2		2		1		1		—		10
Total Unrecognized Firm Commitments	$	58	$	42	$	33	$	4	$	4	$	43	$	184

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 2014. 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, 2011. Purchased power commitments also include one 20-year PPA with a renewable energy generation facility that achieved commercial operation in September 2011. UNS Electric is obligated to purchase 100% of the output from this facility.

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 2012 and 2016. However, the effects of both purchased power and transmission cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Gas and UNS Electric have operating lease expense, primarily for office facilities and computer equipment, with varying terms and expiration dates. The expense was $1 million in each of the years 2011, 2010, and 2009. UNS Gas’ and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are less than $1 million per year for 2012 through 2017.

TEP CONTINGENCIES

San Juan Mine Fire

In September 2011, a fire at the underground mine that provides coal to San Juan caused mining operations to shut down. TEP owns approximately 20% of San Juan, which is operated by PNM. As we are unable to predict when operations will resume at the mine, we and the other owners of San Juan are considering alternatives for operating the facility.

However, based on information we have received to date, we do not expect the mine fire to have a material effect on our financial condition, results of operations, or cash flows due to the current inventory of previously mined coal and the current low market price of wholesale power. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers through the PPFAC, subject to ACC approval.

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 the 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.

SJCC operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC has compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the 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 Generating Station, and is responsible for its share of any resulting liabilities.

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project.

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TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities.

TEP cannot predict the final outcome of the claims relating to San Juan and Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for these claims, estimates of the range of loss cannot be determined at this time. TEP accrued estimated losses of less than $1 million in 2011 in respect of these claims.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of these mines. TEP’s share of the reclamation costs for coal supply agreements expiring in 2016 through 2019 is approximately $26 million. TEP recognizes this cost over the remaining terms of these coal supply agreements and had recorded liabilities of $13 million at December 31, 2011, and $11 million at December 31, 2010.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates 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 terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur 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 recover the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

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 authorized 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. If a decision is made to pursue an alternative route, approvals will be needed from the ACC, the Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and Water Commission. As of December 31, 2011, and December 31, 2010, 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.

RESOLUTION OF CONTINGENCIES

Settlement of El Paso Electric Dispute

In November 2011, a settlement agreement between TEP and El Paso became effective after receiving FERC approval in August 2011. The settlement resolved a dispute over transmission service from Luna to TEP’s system, totaling $11 million, under the 1982 Power Exchange and Transmission Agreement between the parties (Exchange Agreement).

The settlement reduced TEP’s rights for transmission under the Exchange Agreement from 200 MW to 170 MW and required TEP to pay El Paso a lump-sum of $5 million, equivalent to the total amount that TEP would have paid El Paso for 30 MW of transmission from February 1, 2006, through the settlement date, including interest.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Under the PPFAC mechanism, TEP is allowed to recover $2 million of this additional transmission expense from its customers. In accordance with the settlement agreement, TEP has entered into two new firm transmission service agreements under El Paso’s Open Access Transmission Tariff for a total of 40 MW. The settlement agreement also required El Paso to withdraw its appeal before the United States Court of Appeals District of Columbia Circuit and required TEP to withdraw its related complaint before the Arizona District of the United States District Court.

TEP recognized a pre-tax gain of approximately $7 million, including interest, in the third quarter of 2011. To reflect the gain, TEP recorded a $7.1 million net reduction to Transmission Expense, $0.9 million of Interest Income, and $0.6 million of Interest Expense on the income statements. TEP recorded the payment of $5 million in Purchased Power in the cash flow statements.

Take-Or-Pay Accrual for Coal Transportation Agreement

In December 2010, TEP recorded a $4 million liability and regulatory asset for take-or-pay obligations under a coal transportation agreement for Sundt Unit 4, effective through December 2015. In December 2011, TEP’s take-or-pay obligations were terminated. As a result, TEP reversed its $4 million liability and regulatory asset.

Claims Related to Navajo Generating Station

In June 1999, the Navajo Nation filed suit in the U.S. District Court for the District of Columbia (D.C. Lawsuit) against parties including SRP; several Peabody Coal Company entities including Peabody Western Coal Company (Peabody), the coal supplier to Navajo Generating Station (Navajo); Southern California Edison Company (SCE); and other defendants. 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 alleged, 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 initially sought $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 April 2010, the Navajo Nation filed a Second Amended Complaint which dropped the treble damages claim. In August 2011, the Navajo Nation, Peabody, SCE and SRP executed a written settlement agreement in return for the Navajo Nation’s dismissal of all claims in the D.C. Lawsuit. SRP asked that the Navajo participants, including TEP, contribute toward the settlement based on their respective ownership interests in the Navajo plant, which for TEP is 7.5%. TEP paid SRP the requested contribution which did not have a material impact on TEP’s financial statements.

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 does not believe the lawsuit will be re-filed based upon the final outcome of the D.C. Lawsuit.

PROPOSED ENVIRONMENTAL MATTERS

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 $8 million in 2011, $18 million in 2010 and $24 million in 2009 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 $7 million in 2012 and $25 million in 2013. In addition, TEP recorded operating expenses of $12 million in 2011, $14 million in 2010 and $13 million in 2009 related to environmental compliance. TEP expects environmental expenses to be $14 million in 2012.

TEP may incur additional costs to comply with future changes in federal and state environmental laws, and regulations and permit requirements at its electric generating facilities. Compliance with these changes may reduce operating efficiency.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. The EPA is required to develop rules establishing standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units. The EPA issued the final rule in December 2011.

Navajo

Based on the EPA’s final standards, mercury and particulate emission control equipment may be required at Navajo by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and approximately $43 million if the installation of baghouses to control particulates is necessary.

Springerville

Based on the EPA’s final standards, mercury emission control equipment may be required at Springerville by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is approximately $5 million. The annual operating cost associated with the mercury emission control equipment is expected to be approximately $3 million.

San Juan

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s final federal standards.

Sundt

TEP does not anticipate the final EPA rule will have a material capital impact on Sundt Unit 4.

Four Corners

Based on the EPA’s final standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated capital cost of this equipment is less than $1 million. The annual operating cost associated with the mercury emission control equipment is expected to be less than $1 million.

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 for approval. Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions. The EPA oversees regional haze planning for these plants.

Compliance 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 the San Juan, Four Corners and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants. TEP cannot predict the ultimate outcome of these matters.

San Juan

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO₂ and sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (SCR) technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions. Based on two cost analyses commissioned by PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180 million and $200 million.

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In September 2011, PNM filed a petition to review the Federal Implementation Plan with the 10th Circuit Court of Appeals challenging various aspects of that plan. In addition, PNM filed a request with the EPA to stay the five-year installation timeframe for environmental upgrades ordered by the Federal Implementation Plan until the 10th Circuit considers and rules on the petition to review.

In October 2011, PNM filed a Petition for Reconsideration of the Federal Implementation Plan. PNM also filed a Request to Stay the effective date of the final BART Federal Implementation Plan under the Clean Air Act with the EPA. In November 2011, PNM filed with the 10th Circuit a Motion to Stay the Federal Implementation Plan. WildEarth Guardians, Dine Citizens against Ruining our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance and Sierra Club were granted leave to intervene in PNM’s petition to review in the 10th Circuit. Neither the Petition in the 10th Circuit, nor the Petition for Reconsideration by the EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted leave to intervene in that appeal.

In October 2011, Governor Susana Martinez of New Mexico and the New Mexico Environment Department filed a Petition for Review of the EPA’s final Federal Implementation Plan determination in the 10th Circuit and a Petition for Reconsideration of the rule with the EPA. In November 2011, the New Mexico Governor and Environment Department filed a motion with the 10th Circuit to stay the rule. These appeals and motions are all currently pending.

Four Corners

In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that would require the installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the capital costs to install SCR is approximately $35 million.

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the National Renewable Energy Laboratory (NREL) in partnership with the Department of the Interior and the Department of Energy. The report addresses potential energy, environmental and economic issues related to compliance with the regional haze rule. The report was submitted to the EPA in January 2012. If the EPA determines that SCR is required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital expenditure for the required baghouses would be approximately $43 million. The cost of required pollution controls 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5. UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

The following table shows Utility Plant in Service by major class.

		September 30,		September 30,		September 30,		September 30,
	UniSource Energy				TEP
	December 31,				December 31,
	2011		2010		2011		2010
	-Millions of Dollars-
Plant in Service:
Electric Generation Plant	$	1,879	$	1,787	$	1,795	$	1,709
Electric Transmission Plant		810		741		766		705
Electric Distribution Plant		1,453		1,368		1,234		1,168
Gas Distribution Plant		233		224		—		—
Gas Transmission Plant		18		18		—		—
General Plant		331		215		302		187
Intangible Plant—Software Costs		44		34		43		33
Intangible Plant—Other		83		61		78		57
Electric Plant Held for Future Use		5		5		4		4
Total Plant in Service(1)		4,856		4,453		4,222		3,863
Utility Plant under Capital Leases	$	583	$	583	$	583	$	583

⁽¹⁾  At December 31, 2010, UniSource Energy’s total plant included $65 million of non-regulated plant in service related to BMGS, with $4 million of accumulated depreciation. See Note 2 for information regarding UNS Electric’s 2011 purchase of BMGS from UED.

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. See Note 6. In April 2010, TEP terminated the capital lease of Sundt Unit 4 and purchased the related leased assets. At December 31, 2011, 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:

		September 30,		September 30,		September 30,
	Years Ended December 31,
	2011		2010		2009
	-Millions of Dollars-
Lease Expense:
Interest Expense – Included in:
Capital Leases	$	40	$	47	$	49
Operating Expenses – Fuel		4		4		4
Other Expense		1		2		1
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel		3		3		2
Operating Expenses – Depreciation and Amortization		14		14		26
Total Lease Expense	$	62	$	70	$	82

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The depreciable lives as of December 31, 2011 were as follows:

Major Class of Utility Plant in Service	TEP	UNS Gas and UNS Electric
Electric Generation Plant	6-59 years	38-42 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

SeeUtility Plantin Note 1 andTEP Capital Lease Obligationsin Note 6.

JOINTLY-OWNED FACILITIES

At December 31, 2011, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:

	September 30,		September 30,		September 30,		September 30,		September 30,
	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Net Book Value
	-Millions of Dollars-
San Juan Units 1 and 2	50.0%	$	430	$	8	$	219	$	219
Navajo Station Units 1, 2 and 3	7.5		146		1		99		48
Four Corners Units 4 and 5	7.0		96		2		71		27
Transmission Facilities	7.5 to 95.0		289		9		179		119
Luna Energy Facility	33.3		52		—		1		51
Total		$	1,013	$	20	$	569	$	464

TEP has financed or provided funds for the above facilities and TEP’s share of its operating expenses is reflected in the income statements based on the nature of the expense.

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

In 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due in 2035. UniSource Energy has the option to redeem the Convertible Senior Notes, in whole or in part, for cash at par plus accrued interest. Investors may require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash at par plus accrued interest on March 1 of 2015, 2020, 2025 and 2030, and upon the occurrence of certain fundamental changes, such as a change in control. Each $1,000 of Convertible Senior Notes can be converted into 28.814 shares of UniSource Energy Common Stock at any time, which is equivalent to a conversion price of approximately $34.71 per share of common stock. The conversion rate is subject to adjustments including an adjustment to reduce the conversion price upon the payment of quarterly dividends in excess of $0.19 per share.

In December 2011, UniSource Energy announced that it would redeem $35 million of the $150 million outstanding Convertible Senior Notes on January 12, 2012, at a redemption price of 100% of the principal amount plus accrued interest. In January 2012, holders of approximately $33 million of the Convertible Senior Notes converted their interests into approximately 964,000 shares of UniSource Energy Common Stock. The remaining $2 million of

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Convertible Senior Notes were redeemed for cash. After the partial redemption, UniSource Energy had $115 million of Convertible Senior Notes outstanding.

TEP DEBT

Variable Rate Tax-Exempt Bonds (IDBs)

At December 31, 2011, TEP had $215 million in tax-exempt variable rate debt outstanding. At December 31, 2010, TEP had $365 million outstanding. Each series of bonds is supported by a letter of credit issued under the TEP Credit Agreement or separate TEP Letter of Credit and Reimbursement Agreements. The letters of credit are secured by mortgage bonds issued under TEP’s 1992 Mortgage.

In November 2011, TEP repurchased $150 million of variable rate IDBs. TEP did not cancel the repurchased bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. See 2011 TEP Unsecured Notes below.

In December 2010, TEP issued $37 million of Coconino County, Arizona, tax-exempt pollution control bonds (2010 Coconino Bonds). The 2010 Coconino Bonds are supported by a letter of credit (LOC). The LOC is secured by $37 million of 1992 Mortgage Bonds and expires December 2014. The bonds accrue interest at a variable weekly rate and are due October 2032. These bonds are multi-modal bonds that allow TEP to change the interest feature of the bonds. They are callable at any time at par plus accrued interest and are subject to mandatory redemption under certain circumstances if the LOC is not extended. The average interest rate on TEP’s 2010 Coconino Bonds was 0.23% in 2011 and 0.38% in 2010. TEP used the proceeds to redeem a corresponding principal amount of fixed rate Coconino pollution control bonds.

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

The following table shows interest rates on TEP’s variable rate IDBs which are reset weekly by its remarketing agents:

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
Interest Rates on IDBs:
Average Interest Rate		0.18	%		0.26	%		0.41	%
Range of Average Weekly Rates		0.05 to 0.34	%  %		0.17 to 0.39	%  %		0.25 to 0.79	%  %

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.

Unsecured Fixed Rate IDBs

At December 31, 2011, TEP had $616 million in unsecured fixed rate IDBs. At December 31, 2010, TEP had $638 million outstanding.

In November 2011, TEP redeemed $22 million in unsecured fixed rate IDBs. See 2011 TEP Unsecured Notes below.

In October 2010, TEP issued $100 million of Pima County, Arizona tax-exempt IDBs. The 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 in 2010 and $11 million in 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

2011 TEP Unsecured Notes

In November 2011, TEP issued $250 million of 5.15% Notes due November 2021 at a discount of $0.8 million. The debt is callable anytime before August 15, 2021, with a make-whole premium plus accrued interest. Anytime after August 15, 2021, the debt is callable at par plus accrued interest. TEP used the net proceeds from the sale to 1) repurchase $150 million of variable rate IDBs, 2) redeem $22 million of 6.1% fixed rate IDBs and 3) repay $78 million of outstanding revolving credit facility balances, with any remaining proceeds to be applied to general corporate purposes. The variable rate IDBs were supported by letters of credit (LOCs) issued under TEP’s Credit Facility. As a result of the repurchase of the variable rate IDBs, TEP cancelled $155 million of LOCs and reduced its mortgage bonds supporting the LOCs by the same amount.

TEP capitalized $2 million in costs related to the issuance of the notes and will amortize the costs to interest expense through November 2021, the term of the notes.

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, 2011 and December 31, 2010.

TEP CAPITAL LEASE OBLIGATIONS

Springerville Leases

The terms of TEP’s 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. Instead of extending the leases TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of common facilities are: $38 million in 2017 and $68 million in 2021.

• The Springerville Coal Handling Facilities Leases have an initial term to April 2015 but have fixed-rate lease renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million. The lease provides for one renewal period of six years beginning in April 2015, with additional renewal periods of five or more years through 2035.

• The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030. TEP has a fair market value purchase option for facilities under the Springerville Unit 1 Lease.

TEP agreed with Tri-State, the owner of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri State will then be obligated to either 1) buy a portion of these facilities; or 2) continue making payments to TEP for the use of these facilities.

In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal process to determine the fair market value purchase price, in accordance with the Springerville Unit 1 Leases agreements. Based on that appraisal, TEP would have to pay $159 million in 2015 for the 86% interest not already owned by TEP.

In January 2012, through scheduled lease payments, TEP reduced its capital lease obligations by $74 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Investments in Springerville Lease Debt and Equity

TEP’s investments in Springerville Unit 1 lease debt totaled $29 million at December 31, 2011 and $67 million at December 31, 2010. The investments in lease debt mature in 2013. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $37 million at December 31, 2011 and December 31, 2010.

Interest Rate Swaps—Springerville Common Facilities Lease Debt

TEP’s interest rate swaps 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, 2011 and December 31, 2010. The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

		September 30,			September 30,
Outstanding at December 31, 2011	Fixed Ratio			LIBOR Spread
$ 34 million		5.77	%		1.625	%
$ 22 million		3.18	%		1.625	%
$ 7 million		3.32	%		1.625	%

TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 16.

UNS ELECTRIC SENIOR UNSECURED NOTES

UNS Electric has $100 million of senior unsecured notes; $50 million at 6.5%, due 2015 and $50 million at 7.1%, due 2023. The UNS Electric long-term notes are 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 notes contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments and incurrence of indebtedness.

UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP

In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.25%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four-year period ending August 10, 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES.

The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio, and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement.

UNS GAS SENIOR UNSECURED NOTES

In August 2011, UNS Gas issued $50 million of senior guaranteed notes at 5.39%, due August 2026. UNS Gas used the proceeds to pay in full the $50 million of UNS Gas 6.23% notes that matured in August 2011. UNS Gas has another $50 million of notes 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Gas capitalized less than $0.5 million of costs related to the issuance of the notes and will amortize these costs over the life of 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 CREDIT AGREEMENT

In November 2011, UniSource Energy amended its existing credit agreement to extend the expiration date from November 2014 to November 2016.

In November 2010, UniSource Energy amended and restated its existing credit agreement. As amended, the agreement consists of a $125 million revolving credit facility and revolving letter of credit facility. UniSource Energy's obligations under the agreement are secured by a pledge of the capital stock of Millennium, UES and UED.

UniSource Energy capitalized less than $0.5 million related to the 2011 credit agreement amendment and $1 million related to the 2010 credit agreement amendment and restatement and will amortize these costs through November 2016.

Unisource Energy had $57 million outstanding borrowings at December 31, 2011 and $27 million outstanding borrowings at December 31, 2010, under its revolving credit facility. The weighted average interest rate on the revolver was 2.04% at December 31, 2011, and 3.26% at December 31, 2010. 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 21, 2012, outstanding borrowings under the UniSource Credit Agreement were $52 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 1.75% for Eurodollar loans or Alternate Base Rate plus 0.75% 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 the UniSource Credit Agreement, UniSource Energy may pay dividends so long as it maintains compliance with the agreement.

TEP CREDIT AGREEMENT

In December 2011, TEP reduced its letter of credit facility from $341 million to $186 million, following the repurchase of $150 million of variable rate IDBs and the cancellation of $155 million of LOCs supporting those bonds.

In November 2011, TEP amended its existing credit agreement to extend the expiration date from November 2014 to November 2016.

In November 2010, TEP amended and restated its existing credit agreement, consisting 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 facility is secured by $386 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 $1 million related to the 2011 credit agreement amendment and $4 million related to the 2010 credit agreement amendment and restatement and will amortize these costs through November 2016.

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 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $186 million letter of credit facility is 1.125%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 TEP Credit Agreement, TEP may pay dividends to UniSource Energy so long as it maintains compliance with the agreement.

As of December 31, 2011, TEP had $10 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility. The weighted average interest rate on the revolver was 3.38%, at December 31, 2011. As of December 31, 2010, TEP only had $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 21, 2012, TEP had $85 million in borrowings and $1 million outstanding in letters of credit under its revolving credit facility.

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 (See Variable Rate Tax-Exempt 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 2011, UNS Gas and UNS Electric amended their existing unsecured credit agreement to extend the expiration date from November 2014 to November 2016.

In November 2010, UNS Gas and UNS Electric amended and restated their existing unsecured credit agreement. As amended, the UNS Gas/UNS Electric Credit Agreement consists of a $100 million revolving credit and revolving letter of credit facility. 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 each are liable for only their own individual borrowings under the UNS Gas/UNS Electric Credit Agreement. UES guarantees the obligations of both UNS Gas and UNS Electric. The UNS Gas/UNS Electric Credit Agreement 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 less than $0.5 million of costs related to the 2011 credit agreement amendment and $1 million related to the 2010 credit agreement amendment and restatement, and will amortize these costs through November 2016.

Interest rates and fees under the UNS Electric/UNS Gas Credit Agreement are based on a pricing grid tied to their credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.5% for Eurodollar loans or Alternate Base Rate plus 0.5% for Alternate Base Rate loans.

The UNS Electric/UNS Gas Credit Agreement contains a number of covenants which impose restrictions on UNS Gas, UNS Electric and UES, including restrictions on additional indebtedness, liens and mergers. The UNS Electric/UNS Gas Credit Agreement also stipulates a maximum leverage ratio. Under the terms of the UNS Electric/UNS Gas Credit Agreement, UNS Gas and UNS Electric may pay dividends so long as they maintain compliance with the agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Electric had $6 million and $13 million in outstanding letters of credit under the UNS Gas/UNS Electric Credit Agreement as of December 31, 2011, and December 31, 2010, respectively, which are not shown on the balance sheet.

UED SECURED TERM LOAN

In July 2011, UED received $63 million from UNS Electric from the sale of BMGS. UED used a portion of those funds to fully repay the $27 million outstanding under its secured term loan.

Other

As of December 31, 2011, UniSource Energy and its subsidiaries were in compliance with the terms of their respective loan, note purchase and credit agreements. No amounts of net income were subject to dividend restrictions.

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:

		000000		000000		000000			000000			000000		000000		000000		000000
	TEP Variable Rate IDBs Supported by Letters of Credit(1)		TEP Scheduled Debt Retirements(2)		TEP Capital Lease Obligations			TEP Total			UNS Gas		UNS Electric		UniSource Energy Parent Company(3)		Total
	- Millions of Dollars -
2012	$	—	$	—	$	118		$	118		$	—	$	—	$	—	$	118
2013		—		—		122			122			—		—		—		122
2014		37		—		195			232			—		—		—		232
2015		—		—		23			23			50		80		—		153
2016		178		—		18			196			—		—		57		253
Total 2012 – 2016		215		—		476			691			50		80		57		878
Thereafter		—		866		61			927			50		50		150		1,177
Less: Imputed Interest		—		—		(107	)		(107	)		—		—		—		(107	)
Total	$	215	$	866	$	430		$	1,511		$	100	$	130	$	207	$	1,948

⁽¹⁾  TEP’s Variable Rate IDBs are backed by $186 million in LOCs issued pursuant to TEP’s Credit Agreement which expires in November 2016 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 and 2016 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.

⁽²⁾  The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

⁽³⁾ In January 2012, UniSource Energy redeemed $35 million of its convertible senior notes. Pursuant to the redemption, substantially all of the notes were converted into approximately 1 million shares of UniSource Energy Common Stock.

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. UniSource Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2011; therefore, TEP and the other subsidiaries were not restricted from paying dividends.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In February 2012, UniSource Energy declared a first quarter dividend to shareholders of $0.43 per share of UniSource Energy Common Stock. The dividend, totaling approximately $16 million, will be paid on March 22, 2012, to common shareholders of record as of March 12, 2012.

In January 2012, holders of approximately $33 million of the Convertible Senior Notes converted their interests into approximately 964,000 shares of UniSource Energy Common Stock increasing common stock equity by $33 million.

TEP

UniSource Energy is the holder of TEP’s common stock. TEP pays dividends from current year earnings; therefore the dividend restriction in the Federal Power Act does not limit TEP’s payment of dividends from net income. TEP paid dividends to UniSource Energy of $60 million in both 2010 and 2009. TEP did not pay dividends to UniSource Energy in 2011.

UniSource Energy contributed capital to TEP of $30 million in 2011, $15 million in 2010, and $30 million in 2009.

NOTE 8. INCOME TAXES

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

		000000			000000			000000			000000			000000			000000
	UniSource Energy									TEP
	Years Ended December 31,
	2011			2010			2009			2011			2010			2009
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	62		$	66		$	59		$	48		$	58		$	51
State Income Tax Expense, Net of Federal Benefit		8			9			7			6			8			6
Deferred Tax Asset Valuation Allowance		—			8			—			—			—			—
Deferred Tax Asset Write-Off Related to Unregulated Investment		—			3			—			—			—			—
AFUDC Equity		(1	)		(1	)		(1	)		(1	)		(1	)		(1	)
Domestic Production Deduction		—			(3	)		(1	)		—			(3	)		(1	)
Federal/State Tax Credits		(3	)		(2	)		(1	)		(2	)		(2	)		(1	)
Other		1			(3	)		—			1			—			—
Total Federal and State Income Tax Expense	$	67		$	77		$	63		$	52		$	60		$	54
Effective Tax Rate		38	%		41	%		37	%		38	%		36	%		37	%

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

		September 30,			September 30,			September 30,		September 30,			September 30,			September 30,
	UniSource Energy								TEP
	Years Ended December 31,
	2011			2010			2009		2011			2010			2009
	-Millions of Dollars-
Current Tax Expense (Benefit)
Federal	$	(7	)	$	34		$	6	$	(5	)	$	28		$	7
State		(2	)		7			—		(2	)		7			1
Total		(9	)		41			6		(7	)		35			8
Deferred Tax Expense (Benefit)
Federal		64			32			47		50			24			38
Federal Investment Tax Credits		(1	)		(1	)		—		(1	)		(1	)		—
State		13			5			10		10			2			8
Total		76			36			57		59			25			46
Total Federal and State Income Tax Expense	$	67		$	77		$	63	$	52		$	60		$	54

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

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy December 31,						TEP December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Gross Deferred Income Tax Assets
Capital Lease Obligations	$	169		$	192		$	169		$	192
Net Operating Loss Carryforwards		81			—			76			—
Customer Advances and Contributions in Aid of Construction		30			43			17			27
Alternative Minimum Tax Credit		43			34			25			16
Accrued Postretirement Benefits		23			24			23			24
Renewable Energy Credit Up-Front Incentive Payments		22			14			18			11
Emission Allowance Inventory		10			11			10			11
Unregulated Investment Losses		9			9			—			—
Other		34			29			29			26
Gross Deferred Income Tax Assets		421			356			367			307
Deferred Tax Assets Valuation Allowance		(7	)		(8	)		—			—
Gross Deferred Income Tax Liabilities
Plant—Net		(581	)		(465	)		(513	)		(413	)
Capital Lease Assets—Net		(41	)		(48	)		(41	)		(48	)
Regulatory Asset—Income Taxes Recoverable Through Future Revenues		(4	)		(7	)		(3	)		(7	)
Pensions		(17	)		(12	)		(18	)		(13	)
PPFAC		(19	)		(1	)		(16	)		—
Other		(29	)		(30	)		(17	)		(22	)
Gross Deferred Income Tax Liabilities		(691	)		(563	)		(608	)		(503	)
Net Deferred Income Tax Liabilities	$	(277	)	$	(215	)	$	(241	)	$	(196	)

K-127

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy						TEP
	December 31,						December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Deferred Income Taxes – Current Assets	$	23		$	31		$	22		$	32
Deferred Income Taxes – Noncurrent Liabilities		(300	)		(246	)		(263	)		(228	)
Net Deferred Income Tax Liability	$	(277	)	$	(215	)	$	(241	)	$	(196	)

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 $7 million of capital loss at December 31, 2011 and $8 million at December 31, 2010. The deferred tax asset 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 a $7 million valuation allowance against the deferred tax asset as of December 31, 2011 and $8 million at 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.

State Tax Rate Change

We record deferred tax assets and liabilities using the income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. In the first quarter of 2011, the Arizona legislature passed a bill reducing the corporate income tax rate from the current rate of 6.968%. The tax rate reduction will be phased in beginning in 2014, with a reduction of approximately 0.5% per year until the income tax rate reaches 4.9% for 2017 and later years. As a result of these tax rate reductions, we reduced the net deferred tax liabilities at UniSource Energy and TEP by $13 million, offset entirely by adjustments to regulatory assets and liabilities. The income tax rate change did not have an impact on UniSource Energy’s and TEP’s effective tax rate for 2011.

Uncertain Tax Positions

In accordance with accounting rules related to uncertain tax positions, we are required 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:

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy						TEP
	December 31,						December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Unrecognized Tax Benefits, beginning of year	$	41		$	19		$	35		$	19
Additions based on tax positions taken in the current year		9			11			8			8
Reductions based on settlements with tax authorities		(22	)		—			(19	)		—
Additions based on tax positions taken in the prior year		1			16			—			13
Reductions based on tax positions taken in the prior year		—			(4	)		—			(4	)
Reductions based on expiration of the statute of limitations		—			(1	)		—			(1	)
Unrecognized Tax Benefits, end of year	$	29		$	41		$	24		$	35

Unrecognized tax benefits of $1 million, if recognized, would reduce the effective tax rate at December 31, 2011, and December 31, 2010, for both UniSource Energy and TEP. Included in reductions based on settlements with authorities is $13 million for UniSource Energy and $10 million for TEP related to a change in accounting method filed with the Internal Revenue Service (IRS) in 2011. The remaining balance in unrecognized tax benefits could change in the next twelve months as a result of ongoing IRS audits, but we are unable to determine the amount of the change.

K-128

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UniSource Energy and TEP recognize interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements. UniSource Energy and TEP recorded a reduction to interest expense of $1 million in 2011 and 2009. We did not recognize a reduction to interest expense in 2010. The balance of interest payable for UniSource Energy and TEP was $1 million at December 31, 2011 and $2 million at December 31, 2010. We have no penalties accrued in the years presented.

UniSource Energy and TEP have been audited by the IRS through tax year 2006 and are currently under audit by the IRS for 2008 through 2010. 2007 was not selected for audit. We are unable to determine when the audits will be completed. UniSource Energy and TEP are not currently under audit by any state tax agencies.

NOTE 9. EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

We 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. We 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 Retail Rates, and expect to recover these costs over the estimated service lives of employees.

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. 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. Our plans are in compliance with The Pension Act.

In 2012, UniSource Energy expects to contribute $23 million to the pension plans, including $20 million in contributions by TEP.

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 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA) to fund its other postretirement benefit plan. TEP contributed $2 million in each of 2011 and 2010 and $1 million in 2009 to the VEBA. We record changes in other postretirement obligation, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in Retail Rates. TEP’s retiree medical plan was amended effective December 31, 2011 to increase the participant contributions for unclassified employees who retire on or after July 1, 2012.

K-129

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The pension and other postretirement benefit related amounts (excluding tax balances) included on the UniSource Energy balance sheet are:

		September 30,			September 30,			September 30,			September 30,
	Pension Benefits						Other Postretirement Benefits
	Years Ended December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Regulatory Pension Asset included in Other Regulatory Assets	$	106		$	86		$	8		$	8
Accrued Benefit Liability included in Accrued Employee Expenses		(1	)		—			(2	)		(4	)
Accrued Benefit Liability included in Pension and Other Postretirement Benefits		(72	)		(63	)		(66	)		(65	)
Accumulated Other Comprehensive Loss (SERP)		2			4			—			—
Net Amount Recognized	$	35		$	27		$	(60	)	$	(61	)

The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $8 million at December 31, 2011, and $6 million at December 31, 2010. The table also includes a postretirement benefit liability of $1 million for UNS Gas and UNS Electric for each period presented.

OBLIGATIONS AND FUNDED STATUS

We measured the actuarial present values of all pension benefit obligations and other postretirement benefit plans at December 31, 2011, and December 31, 2010. The tables below include TEP’s, 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:

		September 30,			September 30,			September 30,			September 30,
	Pension Benefits						Other Postretirement Benefits
	Years Ended December 31,
	2011			2010			2011			2010
	-Millions of Dollars-
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	283		$	242		$	73		$	71
Actuarial (Gain) Loss		22			28			—			(1	)
Interest Cost		16			15			4			4
Service Cost		10			8			3			3
Amendments		—			—			(2	)		—
Other		—			1			—			—
Benefits Paid		(12	)		(11	)		(5	)		(4	)
Projected Benefit Obligation at End of Year		319			283			73			73
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		220			184			4			2
Actual Return on Plan Assets		14			25			—			—
Benefits Paid		(12	)		(11	)		(5	)		(4	)
Employer Contributions (1)		23			22			6			6
Fair Value of Plan Assets at End of Year		245			220			5			4
Funded Status at End of Year	$	(74	)	$	(63	)	$	(68	)	$	(69	)

(1) TEP made $20 million in pension contributions and $6 million of other postretirement benefits contributions in 2011 and 2010.

K-130

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 starting in 2018. There are 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 $1 million at December 31, 2011 and $2 million at December 31, 2010.

The table above includes the following for UNS Gas and UNS Electric:

• Pension benefit obligations of $8 million at December 31, 2011, and $6 million at December 31, 2010;

• Plan assets of $10 million December 31, 2011, and $9 million at December 31, 2010; and

• A postretirement benefit liability of $1 million at December 31, 2011 and December 31, 2010.

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 the dates presented:

		September 30,		September 30,		September 30,			September 30,
	Pension Benefits				Other Postretirement Benefits
	Years Ended December 31,
	2011		2010		2011			2010
	-Millions of Dollars-
Net Loss	$	108	$	89	$	11		$	11
Prior Service Cost (Benefit)		1		1		(3	)		(3	)

Information for pension plans with Accumulated Benefit Obligations in excess of pension plan assets follows:

		September 30,		September 30,
	December 31,
	2011		2010
	-Millions of Dollars-
Projected Benefit Obligation at End of Year	$	319	$	283
Accumulated Benefit Obligation at End of Year		281		243
Fair Value of Plan Assets at End of Year		245		220

At December 31, 2011, and December 31, 2010, 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:

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Pension Benefits									Other Postretirement Benefits
	Years Ended December 31,
	2011			2010			2009			2011			2010			2009
	-Millions of Dollars-
Service Cost	$	10		$	8		$	7		$	3		$	3		$	2
Interest Cost		15			15			14			4			4			4
Expected Return on Plan Assets		(16	)		(14	)		(11	)		—			—			—
Prior Service Cost Amortization		—			—			1			(1	)		(2	)		(2	)
Recognized Actuarial Loss		6			5			7			—			—			1
Net Periodic Benefit Cost	$	15		$	14		$	18		$	6		$	5		$	5

Approximately 19% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in current year earnings.

K-131

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:

		September 30,			September 30,			September 30,			September 30,		September 30,
	Pension Benefits
	2011						2010					2009
	Regulatory Asset			AOCI			Regulatory Asset			AOCI		Regulatory Asset
	-Millions of Dollars-
Current Year Actuarial (Gain) Loss	$	25		$	(2	)	$	16		$	1	$	(21	)
Amortization of Actuarial (Gain) Loss		(5	)		—			(5	)		—		(7	)
Plan Amendments		—			—			—			—		(1	)
Total Recognized (Gain) Loss	$	20		$	(2	)	$	11		$	1	$	(29	)

		September 30,			September 30,			September 30,
	Other Postretirement Benefits
	2011			2010			2009
	Regulatory Asset			Regulatory Asset			Regulatory Asset
	-Millions of Dollars-
Prior Service Cost (Credit)	$	(2	)	$	—		$	—
Current Year Actuarial (Gain) Loss		—			(1	)		1
Amortization of Actuarial Gain (Loss)		—			(1	)		(1	)
Prior Service (Cost) Amortization		1			2			2
Total Recognized (Gain) Loss	$	(1	)	$	—		$	2

For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $7 million estimated net loss and less than $0.5 million prior service cost from other regulatory assets and less than $0.5 million prior service cost from AOCI into net periodic benefit cost in 2012. The estimated net loss for the defined benefit postretirement plans that will be amortized from other regulatory assets into net periodic benefit cost in 2012 is less than $1 million. The estimated prior service benefit that will be amortized is less than $1 million.

		September 30,		September 30,		September 30,		September 30,
	Pension Benefits				Other Postretirement Benefits
	2011		2010		2011		2010
Weighted-Average Assumptions Used to Determine Benefit Obligations as of the Measurement Date
Discount Rate		4.9%-5.0%		5.5% - 5.6%		4.7%		5.2%
Rate of Compensation Increase		3.0%		3.0% – 5.0%		N/A		N/A

	September 30,	September 30,	September 30,	September 30,	September 30,	September 30,
	Pension Benefits			Other Postretirement Benefits
	2011	2010	2009	2011	2010	2009
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate	5.5%-5.6%	6.3%	6.3%	5.2%	6.0%	6.5%
Rate of Compensation Increase	3.0%-5.0%	3.0%–5.0%	3.0% -5.0%	N/A	N/A	N/A
Expected Return on Plan Assets	7.0%	7.5%	8.0%	5.1%	5.6%	N/A

Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets.

We 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.

K-132

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

		September 30,			September 30,
	December 31,
	2011			2010
Assumed Health Care Cost Trend Rates
Health Care Cost Trend Rate Assumed for Next Year		6.9	%		7.9	%
Ultimate Health Care Cost Trend Rate Assumed		4.5	%		4.5	%
Year that the Rate Reaches the Ultimate Trend Rate		2049			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, 2011 amounts:

		September 30,		September 30,
	One-Percentage- Point Increase		One-Percentage- 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

We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, were as follows:

		September 30,			September 30,			September 30,			September 30,
	TEP Plan Assets						UNS Gas and UNS Electric Plan Assets
	December 31, 2011			December 31, 2010			December 31, 2011			December 31, 2010
Asset Category
Equity Securities		49	%		57	%		55	%		57	%
Fixed Income Securities		42			34			34			32
Real Estate		7			7			11			11
Other		2			2			—			—
Total		100	%		100	%		100	%		100	%

K-133

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:

		September 30,		September 30,		September 30,		September 30,
	Fair Value Measurements of Pension Assets December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	- Millions of Dollars -
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
U.S. Large Cap		—		61		—		61
U.S. Small Cap		—		13		—		13
Non-U.S.		—		47		—		47
Fixed Income		—		101		—		101
Real Estate		—		7		11		18
Private Equity		—		—		4		4
Total	$	1	$	229	$	15	$	245

		September 30,		September 30,		September 30,		September 30,
	Fair Value Measurements of Pension Assets December 31, 2010
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	- Millions of Dollars -
Asset Category
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

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, U.S. 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 using a real estate index value. The real estate index value was developed based on appraisals comprising 85% of real estate assets tracked by the index in 2011, and comprising 94% in 2010.

Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.

K-134

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 $10 million at December 31, 2011, and $9 million at December 31, 2010.

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.

		September 30,		September 30,		September 30,		September 30,
	Year Ended December 31, 2011
	Private Equity		Real Estate		Hedge Fund		Total
	- Millions of Dollars -
Beginning Balance at January 1, 2011	$	2	$	10	$	—	$	12
Actual Return on Plan Assets:
Assets Held at Reporting Date		—		1		—		1
Assets Sold During the Period		—		—		—		—
Purchases, Sales, and Settlements		2		—		—		2
Ending Balance at December 31, 2011	$	4	$	11	$	—	$	15

		September 30,		September 30,		September 30,			September 30,
	Year Ended December 31, 2010
	Private Equity		Real Estate		Hedge Fund			Total
	- Millions of Dollars -
Beginning Balance at January 1, 2010	$	1	$	8	$	1		$	10
Actual Return on Plan Assets:
Assets Held at Reporting Date		—		1		—			1
Assets Sold During the Period		—		—		(1	)		(1	)
Purchases, Sales, and Settlements		1		1		—			2
Ending Balance at December 31, 2010	$	2	$	10	$	—		$	12

UES has no pension assets classified as Level 3 in the fair value hierarchy.

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.

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.

K-135

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 as of December 31, 2011 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.

		September 30,			September 30,			September 30,
	TEP Plan			UES Plan			VEBA Trust
Fixed Income		41	%		33	%		38	%
U.S. Large Cap		24	%		28	%		33	%
Non-U.S. Developed		15	%		17	%		9	%
Real Estate		8	%		11	%		—
U.S. Small Cap		5	%		5	%		7	%
Non-U.S. Emerging		5	%		6	%		11	%
Private Equity		2	%		—			—
Cash / Treasury Bills		—			—			2	%
Total		100	%		100	%		100	%

Pension Fund Descriptions

The funds are manager of manager funds, which allow different fund managers to make investment decisions, with the exception of the private equity fund, which holds a portfolio of investment funds.

Other Postretirement Benefit Assets

As of December 31, 2011, the fair value of VEBA trust assets were $5 million, of which $3 million were fixed income investments and $2 million were equities. 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. There are no level three assets in the VEBA trust.

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.

		September 30,		September 30,
	Pension Benefits		Other Postretirement Benefits
	-Millions of Dollars-
2012	$	13	$	4
2013		15		5
2014		16		5
2015		17		5
2016		18		5
Years 2017-2021		109		31

UNS Gas and UNS Electric expect annual pension and postretirement benefit payments of approximately $6 million in 2012 through 2016 and $9 million in 2017 through 2021 to be made by the defined benefit pension and postretirement plans.

K-136

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DEFINED CONTRIBUTION PLANS

We 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. We match part of a participant’s contributions to the plans. TEP made matching contributions to these plans of $5 million in 2011 and $4 million in each of 2010 and 2009. UNS Gas and UNS Electric made matching contributions of less than $1 million in each of 2011, 2010, and 2009.

NOTE 10. SHARE-BASED COMPENSATION PLAN

In 2011, UniSource Energy shareholders approved the UniSource Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), a new share-based compensation plan. Under the 2011 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 which may be awarded under the 2011 Plan cannot exceed 1.2 million shares. The 2011 Plan supersedes and replaces the UniSource Energy 2006 Omnibus Stock and Incentive Plan (2006 Plan) and all other prior equity compensation plans (Prior Plans). The Prior Plans, however, remain in effect until all stock options and other awards granted thereunder have been exercised, forfeited, canceled, expired or terminated.

STOCK OPTIONS

No stock options were granted by the Compensation Committee during 2011 or 2010. In 2009, the Compensation Committee granted 248,760 stock options to officers with an exercise price of $26.11.

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.

The fair value of the 2009 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 term of the stock options granted in 2009 was 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 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.

		September 30,
	2009
Expected Term (years)		7
Risk-free Rate		3.4	%
Expected Volatility		25.0	%
Expected Dividend Yield		3.2	%
Weighted-Average Grant-Date Fair Value of
Options Granted During the Period	$	5.53

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

See summary of the stock option activity in the table below:

		September 30,			September 30,		September 30,			September 30,		September 30,			September 30,
(Shares in Thousands)	2011					2010					2009
Stock Options	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding, Beginning of Year		921		$	27.96		1,598		$	24.50		1,635		$	22.50
Granted		—			—		—			—		249			26.11
Exercised		(319	)		25.60		(660	)		19.33		(282	)		14.46
Forfeited/Expired		(21	)		31.92		(17	)		37.88		(4	)		12.28
Outstanding, End of Year		581			29.11		921			27.96		1,598			24.50
Exercisable, End of Year		508		$	29.53		654		$	28.70		1,085		$	23.06
Aggregate Intrinsic Value of Options Exercised ($000s)	$	3,690				$	9,124				$	4,177

		September 30,
	At December 31, 2011
Aggregate Intrinsic Value for Options Outstanding ($000s)	$	4,670
Aggregate Intrinsic Value for Options Exercisable ($000s)	$	3,892
Weighted Average Remaining Contractual Life of Outstanding Options		5.6 years
Weighted Average Remaining Contractual Life of Exercisable Options		5.4 years

See summary of stock options in the table below:

		September 30,		September 30,		September 30,		September 30,		September 30,
	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number of Shares (000s)		Weighted- Average Remaining Contractual Life		Weighted- Average Exercise Price		Number of Shares (000s)		Weighted- Average Exercise Price
$17.44 - $17.84		20		1.3 years	$	17.75		20	$	17.75
$26.11 - $37.88		561		5.7 years	$	29.51		489	$	30.01

RESTRICTED STOCK UNITS/AWARDS AND PERFORMANCE SHARES

Restricted Stock Units

Restricted stock and stock units are generally granted 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 56,705 in 2011, 14,866 in 2010, and 101,765 in 2009 were issued with no additional increase in equity as the expense was previously recognized over the vesting period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Compensation Committee granted the following stock units to non-employee directors:

• May 2011—14,655 stock units at a weighted average fair value of $37.53 per share,

• 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.

Performance Share Awards

In 2011, the Compensation Committee granted performance share awards to officers. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $33.73 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 the Edison Electric Institute Index during the performance period of January 1, 2011 through December 31, 2013. The remaining half had a grant date fair value of $36.58 per share and will be paid out in shares of UniSource Energy Common Stock based on cumulative net income for the three-year period ending December 31, 2013. The performance shares vest based on the achievement of goals by the end of the performance period; any unearned awards are forfeited. Performance shares are eligible for dividend equivalents during the performance period.

In 2010, the Compensation Committee granted performance share awards to officers. Half 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 the Edison Electric Institute Index during the performance period of January 1, 2010 through December 31, 2012. The remaining half 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 three-year period ending December 31, 2012. The performance shares vest based on the achievement of goals by the end of the performance period; any unearned awards are forfeited. Performance shares are eligible for dividend equivalents during the performance period.

In 2009, the Compensation Committee granted performance share awards to officers at a grant date fair value, based on a Monte Carlo simulation, of $21.62 per share. At December 31, 2011, upon completion of the three-year performance period, 45,642 shares vested based on goal attainment at 75% 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; 23,414 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.

		September 30,			September 30,		September 30,			September 30,
	Performance Shares					Restricted Stock Units
	Shares (000s)			Weighted- Average Grant-Date Fair Value		Shares (000s)			Weighted- Average Grant-Date Fair Value
Non-vested at January 1, 2011		156		$	27.19		16		$	31.69
Granted		93			35.26		15			37.53
Vested		(46	)		23.41		(16	)		31.69
Forfeited		(50	)		28.29		—			—
Non-vested at December 31, 2011		153		$	32.85		15		$	37.53

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units)

Annually during 2009 through 2011, UniSource Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. No share-based compensation was capitalized as part of the cost of an asset. UniSource Energy did not realize a tax deduction from the exercise of share-based payment arrangements in 2011. In each of 2010 and 2009, UniSource Energy realized an actual tax deduction from the exercise of share-based payment arrangements of $3 million.

At December 31, 2011, the total unrecognized compensation cost related to non-vested share-based compensation was $2 million, which will be recorded as compensation expense over the remaining vesting periods through December 2013. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at December 31, 2011, was 0.7 million.

NOTE 11. FAIR VALUE MEASUREMENTS

The following tables set forth, by level within the fair value hierarchy, UniSource Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These 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 between Levels 1, 2 or 3 for either reporting period.

		September 30,		September 30,			September 30,			September 30,
	UniSource Energy
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	December 31, 2011
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	23	$	—		$	—		$	23
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		16			—			16
Energy Contracts(4)		—		—			14			14
Total Assets		23		16			14			53
Liabilities
Energy Contracts(4)		—		(21	)		(24	)		(45	)
Interest Rate Swaps(5)		—		(12	)		—			(12	)
Total Liabilities		—		(33	)		(24	)		(57	)
Net Total Assets and (Liabilities)	$	23	$	(17	)	$	(10	)	$	(4	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,		September 30,			September 30,			September 30,
	UniSource Energy
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (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(3)		—		3			—			3
Energy Contracts(4)		—		—			15			15
Total Assets		38		19			15			72
Liabilities
Energy Contracts(4)		—		(19	)		(25	)		(44	)
Interest Rate Swaps(5)		—		(10	)		—			(10	)
Total Liabilities		—		(29	)		(25	)		(54	)
Net Total Assets and (Liabilities)	$	38	$	(10	)	$	(10	)	$	18

		September 30,		September 30,			September 30,			September 30,
	TEP
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	December 31, 2011
	- Millions of Dollars -
Assets
Cash Equivalents(1)	$	8	$	—		$	—		$	8
Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2)		—		16			—			16
Energy Contracts(4)		—		—			3			3
Total Assets		8		16			3			27
Liabilities
Energy Contracts(4)		—		(9	)		(3	)		(12	)
Interest Rate Swaps(5)		—		(11	)		—			(11	)
Total Liabilities		—		(20	)		(3	)		(23	)
Net Total Assets and (Liabilities)	$	8	$	(4	)	$	—		$	4

K-141

UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,		September 30,			September 30,			September 30,
	TEP
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (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(4)		—		—			3			3
Total Assets		21		16			3			40
Liabilities
Energy Contracts(4)		—		(7	)		(2	)		(9	)
Interest Rate Swaps(5)		—		(10	)		—			(10	)
Total Liabilities		—		(17	)		(2	)		(19	)
Net Total Assets and (Liabilities)	$	21	$	(1	)	$	1		$	21

(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 on the 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 on the balance sheets.

(3) Collateral provided for energy contracts with counterparties to reduce credit risk exposure. Collateral Posted is included in Current Assets—Other on the UniSource Energy balance sheet.

(4) Energy Contracts include gas swap agreements (Level 2), gas collars (Level 3), 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 on the balance sheets. The valuation techniques are described below. See Note 16.

(5) Interest Rate Swaps are valued based on the 3-month or 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 on the balance sheets.

Energy Contracts

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs 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—we categorize the instrument in Level 2. We categorize derivatives in Level 3 using an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices, TEP and UNS Electric obtain quotes from brokers, major market participants, exchanges or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms including: delivery periods during non-standard time blocks, delivery during only a few months of a given year when prices are quoted only for the annual average, or delivery at illiquid delivery points. In these cases, we use percentage multipliers to value non-standard time blocks, we apply historical price curve relationships to calendar year quotes, and we include 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. We review these assumptions quarterly.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP estimates the fair value of its purchase power call option 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.

UNS Gas estimates the fair value of its gas collar using the Black-Scholes-Merton option pricing model which includes assumptions about future prices of energy, interest rates, volatility, credit worthiness and credit spread.

UniSource Energy’s and TEP’s assessments 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:

		September 30,			September 30,
	Year Ended December 31, 2011
	UniSource Energy			TEP
	Energy Contracts
	-Millions of Dollars-
Balance as of December 31, 2010	$	(10	)	$	1
Gains and (Losses) (Realized/Unrealized) Recorded to:
Net Regulatory Assets – Derivative Instruments		(9	)		2
Other Comprehensive Income		(1	)		(1	)
Settlements		10			(2	)
Balance as of December 31, 2011	$	(10	)	$	—
Total gains (losses) attributable to the change in unrealized gains or losses relating to assets/liabilities still held at the end of the period	$	(9	)	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,			September 30,			September 30,			September 30,
	Year Ended December 31, 2010
	UniSource Energy									TEP
	Energy Contracts			Equity Investments(1)			Total			Energy Contracts
	- Millions of Dollars -
Balance as of December 31, 2009	$	(13	)	$	6		$	(7	)	$	(4	)
Gains and (Losses) (Realized/Unrealized) Recorded to:
Net Regulatory Assets – Derivative Instruments		(9	)		—			(9	)		9
Other Comprehensive Income		(1	)		—			(1	)		(1	)
Other Expense		—			(6	)		(6	)		—
Settlements		13			—			13			(3	)
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

(1) In December 2010, Millennium reduced to zero the book value of its equity investments classified as Level 3 in the fair value hierarchy.

Financial Instruments Not Carried at Fair Value

The market price received when selling an asset or paid to transfer a liability at the measurement date is the fair value of a financial instrument. 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, outstanding at December 31, 2010, 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 calculates 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 incorporate the impact of counterparty credit risk using market credit default swap data. The fair value of TEP’s Investment in Lease Equity decreased significantly during the fourth quarter of 2011 based on the recent Springerville Unit 1 appraisal. No impairment was recorded as TEP expects to recover the full carrying value in Retail Rates.

• Long-Term Debt: UniSource Energy and TEP use quoted market prices, where available, or calculate 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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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 on the balance sheet (carrying value) and the estimated fair values of our financial instruments included the following:

		September 30,		September 30,		September 30,		September 30,
	December 31,
	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	-Millions of Dollars-
Assets:
TEP Investment in Lease Debt and Equity	$	66	$	50	$	105	$	111
Liabilities:
Long-Term Debt
TEP		1,080		1,061		1,004		862
UniSource Energy		1,517		1,543		1,353		1,238

TEP intends to hold the $29 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 EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the notes were converted to common shares.

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

		September 30,		September 30,		September 30,
	Years Ended December 31,
	2011		2010		2009
	-Thousands of Dollars-
Numerator:
Net Income	$	109,975	$	112,984	$	105,901
Income from Assumed Conversion of Convertible Senior Notes		4,390		4,390		4,390
Adjusted Numerator	$	114,365	$	117,374	$	110,291
	-Thousands of Shares-
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued		36,780		36,200		35,653
Fully Vested Deferred Stock Units		129		123		105
Participating Securities		53		92		100
Total Weighted Average Shares of Common Stock Outstanding and Participating Securities—Basic		36,962		36,415		35,858
Effect of Diluted Securities:
Convertible Senior Notes		4,281		4,178		4,093
Options and Stock Issuable under Share Based Compensation Plans		366		448		499
Total Shares—Diluted		41,609		41,041		40,450

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table shows the number of stock options excluded from the diluted EPS computation because the stock option’s exercise price was greater than the average market price of the Common Stock:

		September 30,		September 30,		September 30,
	Years Ended December 31,
	2011		2010		2009
	-Thousands of Shares-
Stock Options Excluded from the Diluted EPS Computation		153		212		395

In January 2012, holders of approximately $33 million of Convertible Senior Notes converted their interests into approximately 964,000 shares of UniSource Energy Common Stock. This conversion of convertible notes to common stock will have a minimal impact on diluted EPS as the dilutive effect of the convertible notes has been reflected in the diluted EPS computation.

NOTE 13. MILLENNIUM INVESTMENTS

In 2010, Millennium recorded impairment losses of $10 million reducing the book value of its unconsolidated equity and cost method investments to zero. 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 statements. Millennium also wrote off $3 million of Deferred Tax Assets related to its investments.

In 2009, Millennium sold an equity investment and recorded a $6 million gain on the sale which is included in Other Income on UniSource Energy's income statements. Millennium received an upfront payment of $5 million in 2009 and a $15 million, three-year, 6%, secured note receivable due in June 2012. 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 Current Asset – Other on UniSource Energy’s balance sheet.

NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The following recently issued accounting standards are not yet reflected in the financial statements:

• The Financial Accounting Standards Board (FASB) issued authoritative guidance that will eliminate the current option to report other comprehensive income in the statement of changes in equity. An entity can elect to present items of net income and other comprehensive income in one continuous statement, or in two separate but consecutive statements. We will be required to comply in the first quarter of 2012 and plan to present a separate statement of other comprehensive income.

• The FASB issued authoritative guidance that changed some fair value measurement principles and disclosure requirements. The most significant disclosure change is expansion of required information for unobservable inputs. We will be required to comply in the first quarter of 2012, and we do not expect this pronouncement to have a material impact on the valuation techniques used to estimate the fair value of assets and liabilities.

• The FASB issued authoritative guidance that will require entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting arrangements. We will be required to comply in the first quarter of 2013.

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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:

		September 30,			September 30,			September 30,
	UniSource Energy
	Years Ended December 31,
	2011			2010			2009
	-Thousands of Dollars-
Net Income	$	109,975		$	112,984		$	105,901
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense		133,832			128,215			144,960
Amortization Expense		30,983			28,094			31,058
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		6,140			5,432			4,929
Amortization of Deferred Debt-Related Costs included in Interest Expense		3,985			3,753			4,171
Provision for Retail Customer Bad Debts		2,072			3,724			3,583
Use of Renewable Energy Credits for Compliance		5,695			4,745			—
California Power Exchange Provision for Wholesale Revenue Refunds Refunds		—			—			4,172
Deferred Income Taxes		75,588			28,142			57,452
Deferred Tax Valuation Allowance		(73	)		7,510			—
Pension and Postretirement Expense		21,202			19,688			23,594
Pension and Postretirement Funding		(28,775	)		(27,742	)		(30,078	)
Share Based Compensation Expense		2,599			2,751			2,779
Excess Tax Benefit from Stock Options Exercised		—			(3,338	)		(3,256	)
Allowance for Equity Funds Used During Construction		(4,496	)		(4,232	)		(4,113	)
CTC Revenue Refunded		(35,958	)		(10,095	)		(12,726	)
Decrease to Reflect PPFAC/PGA Recovery		(4,932	)		(29,622	)		(14,553	)
Gain on Settlement of El Paso Electric Dispute		(7,391	)		—			—
Loss/(Gain) on Millennium’s Investments		—			9,936			(4,730	)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		2,743			(8,851	)		6,458
Materials and Fuel Inventory		(20,864	)		21,744			(24,621	)
Accounts Payable		7,397			2,661			(8,243	)
Income Taxes		(2,739	)		24,470			11,443
Interest Accrued		14,344			14,354			15,956
Current Regulatory Liabilities		2,644			2,788			10,009
Taxes Other Than Income Taxes		2,857			2,442			(48	)
Other		20,492			7,367			23,213
Net Cash Flows – Operating Activities	$	337,320		$	346,920		$	347,310

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,			September 30,			September 30,
	TEP
	Years Ended December 31,
	2011			2010			2009
	-Thousands of Dollars-
Net Income	$	85,334		$	108,260		$	90,688
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense		104,894			99,510			116,970
Amortization Expense		34,650			32,196			35,931
Depreciation and Amortization Recorded to Fuel and Other O&M Expense		4,509			3,855			3,439
Amortization of Deferred Debt-Related Costs included in Interest Expense		2,378			2,146			2,364
Provision for Retail Customer Bad Debts		1,447			2,506			2,342
Use of Renewable Energy Credits for Compliance		5,190			4,245			—
California Power Exchange Provision for Wholesale Revenue Refunds Refunds		—			—			4,172
Deferred Income Taxes		59,309			24,897			45,678
Pension and Postretirement Expense		18,816			17,454			21,294
Pension and Postretirement Funding		(25,878	)		(25,672	)		(28,330	)
Share Based Compensation Expense		2,027			2,131			2,121
Allowance for Equity Funds used During Construction		(3,842	)		(3,567	)		(3,516	)
CTC Revenue Refunded		(35,958	)		(10,095	)		(12,726	)
Decrease to Reflect PPFAC Recovery		(6,165	)		(21,541	)		(18,186	)
Gain on Settlement of El Paso Electric Dispute		(7,391	)		—			—
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		4,809			(5,156	)		(951	)
Materials and Fuel Inventory		(19,789	)		20,920			(23,794	)
Accounts Payable		13,166			(447	)		(10,456	)
Income Taxes		(5,582	)		20,203			(2,714	)
Interest Accrued		14,268			14,431			16,142
Current Regulatory Liabilities		303			2,500			10,555
Taxes Other Than Income Taxes		2,282			1,469			725
Other		19,517			12,238			16,316
Net Cash Flows – Operating Activities	$	268,294		$	302,483		$	268,064

Proceeds from the issuance of the 2010 Coconino Bonds were deposited with a trustee and were used in 2010 to redeem $37 million of pollution control bonds. TEP had no cash receipts or payments as a result of this transaction.

Proceeds from the issuance of $100 million of Pima County tax-exempt IDBs 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. TEP drew down the remaining funds in the construction fund by March 2011.

Proceeds from the issuance of $95 million of unsecured fixed rate IDBs in 2009 were deposited with a trustee and were used in 2009, to redeem approximately $95 million of unsecured fixed rate IDBs. TEP had no cash receipts or payments as a result of this transaction.

Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		September 30,			September 30,			September 30,
	Years Ended December 31,
	2011			2010			2009
	-Thousands of Dollars-
(Decrease)/Increase to Utility Plant Accruals(1)	$	(2,154	)	$	8,514		$	1,082
Net Cost of Removal of Interim Retirements(2)		31,626			4,592			43,381
Capital Lease Obligations(3)		15,162			16,630			17,984
Asset Retirement Obligations(4)		7,638			(1,872	)		—
UED Secured Term Loan Prepayments(5)		—			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 additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

(5) The non-cash UED Secured Term Loan prepayment represents deposits applied to $30 million of loan principal.

NOTE 16. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

FINANCIAL IMPACT OF DERIVATIVES

Cash Flow Hedges

At December 31, 2011, UniSource Energy and TEP had liabilities related to their cash flow hedges of $14 million and $12 million at December 31, 2010.

The net after-tax unrealized gains and losses on derivative activities reported in AOCI were as follows:

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	UniSource Energy						TEP
	Years Ended December 31,
	2011		2010		2009		2011		2010		2009
	-Millions of Dollars-
Net After-Tax Unrealized Losses	$	4	$	6	$	—	$	4	$	6	$	—

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 statements.

		September 30,		September 30,		September 30,			September 30,		September 30,			September 30,
	UniSource Energy							TEP
	Years Ended December 31,
	2011		2010		2009			2011		2010			2009
	-Millions of Dollars-
Increase (Decrease) to Regulatory Assets	$	2	$	—	$	(29	)	$	2	$	(4	)	$	(11	)

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The fair value of derivative assets and liabilities were as follows:

		September 30,			September 30,			September 30,			September 30,
	UniSource Energy						TEP
	December 31, 2011			December 31, 2010			December 31, 2011			December 31, 2010
	-Millions of Dollars-
Assets	$	14		$	15		$	3		$	3
Liabilities		(43	)		(42	)		(9	)		(7	)
Net Assets (Liabilities)	$	(29	)	$	(27	)	$	(6	)	$	(4	)

The realized losses on settled gas swaps that are fully recoverable through the PPFAC or PGA were as follows:

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	UniSource Energy						TEP
	Years Ended December 31,
	2011		2010		2009		2011		2010		2009
	-Millions of Dollars-
Realized Losses on Gas Swaps	$	19	$	23	$	51	$	7	$	9	$	29

At December 31, 2011, UniSource Energy and TEP had contracts that will settle through the third quarter of 2015.

Other Commodity Derivatives

The settlement of forward purchased power and sales contracts that do not result in physical delivery were reflected in the financial statements of UniSource Energy and TEP as follows:

		September 30,			September 30,			September 30,
	2011			2010			2009
	-Millions of Dollars-
Recorded in Wholesale Sales:
Forward Power Sales	$	10		$	27		$	20
Forward Power Purchases		(15	)		(34	)		(18	)
Total Sales and Purchases Not Resulting in Physical Delivery	$	(5	)	$	(7	)	$	2

DERIVATIVE VOLUMES

At December 31, 2011, UniSource Energy had gas swaps totaling 14,856 Billion British thermal units (GBtu) and power contracts totaling 3,147 Gigawatt-hours (GWh) while TEP had gas swaps totaling 6,855 GBtu and power contracts totaling 815 GWh. At December 31, 2010, UniSource Energy had gas swaps totaling 14,973 GBtu and power contracts totaling 4,807 GWh while TEP had gas swaps totaling 6,424 GBtu and power contracts totaling 1,144 GWh. We account for gas swaps and power contracts 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 also consider the impact of our own credit risk on instruments that are in a net liability position. The impact of counterparty credit risk and our own credit risk on the fair value of derivative asset contracts was less than $0.5 million at December 31, 2011, and December 31, 2010.

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. We 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.

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, we would have to provide certain credit enhancements in the form of cash or letters of credit to fully collateralize our exposure to these counterparties.

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, 2011. It also shows cash collateral and letters of credit posted, and additional collateral to be posted if credit-risk related contingent features were triggered.

		September 30,		September 30,
	TEP		UniSource Energy
	December 31, 2011
	-Millions of Dollars-
Net Liability Position	$	16	$	64
Cash Collateral Posted		—		—
Letters of Credit		1		6
Additional Collateral to Post if Contingent Features Triggered		16		61

As of December 31, 2011, TEP had $17 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities; and UNS Electric had $1 million of such exposure related to its supply and hedging contracts. TEP had four counterparties which individually comprise greater than 10% of the total credit exposure and UNS Electric had one. At December 31, 2011, UNS Gas had no 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.

		September 30,		September 30,		September 30,		September 30,
	UniSource Energy
	First		Second		Third		Fourth
	-Thousands of Dollars- (Except Per Share Amounts)
2011
Operating Revenue	$	344,766	$	369,673	$	450,948	$	344,128
Operating Income		44,820		71,289		123,760		41,803
Net Income		13,472		28,604		59,712		8,187
Basic EPS		0.37		0.77		1.61		0.22
Diluted EPS		0.35		0.71		1.46		0.22
2010
Operating Revenue	$	318,849	$	339,114	$	438,830	$	357,173
Operating Income		52,955		72,301		123,524		48,334
Net Income		20,178		25,889		55,665		11,252
Basic EPS		0.56		0.71		1.52		0.31
Diluted EPS		0.52		0.66		1.38		0.30

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.

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

		September 30,		September 30,		September 30,		September 30,
	TEP
	First		Second		Third		Fourth
	-Thousands of Dollars-
2011
Operating Revenue	$	239,588	$	295,233	$	369,846	$	251,719
Operating Income		27,792		62,497		111,479		27,613
Net Income		4,704		25,157		53,912		1,561
2010
Operating Revenue	$	231,083	$	274,694	$	354,638	$	264,852
Operating Income		38,248		63,901		116,055		35,827
Net Income		10,490		27,941		59,704		10,125

The following tables reflect the quarterly impact of revisions recorded in the second and third quarters of 2011 (See Note 1):

		Sept		Sept		Sept		Sept		Sept		Sept		Sept		Sept
	2010 Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	As Reported		As Revised		As Reported		As Revised		As Reported		As Revised		As Reported		As Revised
	-Thousands of Dollars- (Except Per Share Amounts)
	UniSource Energy
Income Statement
Net Income	$	19,972	$	20,178	$	25,886	$	25,889	$	54,883	$	55,665	$	11,082	$	11,252
Basic EPS		0.55		0.56		0.71		0.71		1.50		1.52		0.30		0.31
Diluted EPS		0.52		0.52		0.66		0.66		1.36		1.38		0.29		0.30
	TEP
Income Statement
Net Income	$	10,349	$	10,490	$	27,938	$	27,941	$	58,993	$	59,704	$	9,999	$	10,125

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Schedule Valuation and Qualifying Accounts

Schedule II—Valuation and Qualifying Accounts – UniSource Energy

		September 30,		September 30,		September 30,		September 30,
Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
Year Ended December 31,	-Millions of Dollars-
Reserve for Uncollectible Accounts(1)
2011	$	13	$	5	$	2	$	16
2010	$	13	$	4	$	4	$	13
2009	$	27	$	4	$	18	$	13
Deferred Tax Assets Valuation Allowance(2)
2011	$	8	$	—	$	1	$	7
2010	$	—	$	8	$	—	$	8
2009	$	—	$	—	$	—	$	—
Other(3)
2011	$	4					$	6
2010	$	2					$	4
2009	$	4					$	2

⁽¹⁾  TEP, UNS Gas and UNS Electric record additions to the Reserve for Uncollectible Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesale sales and in-kind transmission imbalances.

⁽²⁾ 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.

⁽³⁾ Principally reserves for sales tax audits, litigation and damages billable to third parties.

Schedule II—Valuation and Qualifying Accounts—TEP

		September 30,		September 30,		September 30,		September 30,
Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
Year Ended December 31,	-Millions of Dollars-
Reserve for Uncollectible Accounts(1)
2011	$	11	$	4	$	1	$	14
2010	$	11	$	3	$	3	$	11
2009	$	24	$	2	$	15	$	11
Other(2)
2011	$	3					$	4
2010	$	—					$	3
2009	$	4					$	—

⁽¹⁾  TEP records additions to the Reserve for Uncollectible Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales and in-kind transmission imbalances.

⁽²⁾ Principally reserves for sales tax audits, litigation and damages billable to third parties.

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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, 2011. 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 2011, 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 2011 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

	September 30,	September 30,	September 30,
Name	Age	Board Committee*	Director Since
Paul J. Bonavia	60	None	2009
Lawrence J. Aldrich	59	2,3,5	2000
Barbara M. Baumann	56	1,2,4	2005
Larry W. Bickle	66	3,4,5	1998
Harold W. Burlingame	71	2,3,5	1998
Robert A. Elliott	56	1,2,3,4,5	2003
Daniel W.L. Fessler	70	1,3,5	2005
Louise L. Francesconi	59	1,2,4	2008
Warren Y. Jobe	71	1,2,4	2001
Ramiro G. Peru	56	1,2,4	2008
Gregory A. Pivirotto	59	1,3,4	2008
Joaquin Ruiz	59	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 has served as Chairman and Chief Executive Officer of UniSource Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. 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.

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

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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.

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 Swift Corporation, a trucking company, from June 2007 to December 2007; 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

		September 30,		September 30,
Name	Age		Director Since
Paul J. Bonavia		60		2009
Michael J. DeConcini		47		2009
David G. Hutchens		45		2011
Kevin P. Larson		55		2009

Paul J. Bonavia Mr. Bonavia has served as Chairman and Chief Executive Officer of UniSource Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. 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 from May

K-156

2009 to December 2011 when his title at TEP was changed to Senior Vice President, Operations. 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.

David G. Hutchens Mr. Hutchens has served as President of UniSource Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UniSource Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UniSource Energy and TEP. Mr. Hutchens joined TEP in 1995.

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.

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 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, 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 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, which information is incorporated herein by reference.

ITEM 12. – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

General

At February 21, 2012, UniSource Energy had outstanding 38.0 million shares of Common Stock. At February 21, 2012, 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 21, 2012, 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 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, 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 will be contained in UniSource Energy’s Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, 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 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, 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 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, 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 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, which information is incorporated herein by reference.

PART IV

ITEM 15. – EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

		September 30,
	Page
(a) (1). Consolidated Financial Statements as of December 31, 2011 and 2010 and for Each of the Three Years in the Period Ended December 31, 2011
UniSource Energy Corporation
Report of Independent Registered Public Accounting Firm		78
Consolidated Statements of Income		80
Consolidated Statements of Cash Flows		81
Consolidated Balance Sheets		82
Consolidated Statements of Capitalization		84
Consolidated Statements of Changes in Stockholders’ Equity		85
Notes to Consolidated Financial Statements		92
Tucson Electric Power Company
Report of Independent Registered Public Accounting Firm		79
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 Stockholder’s Equity		91
Notes to Consolidated Financial Statements		92
(2). Financial Statement Schedules
Schedule II
Valuation and Qualifying Accounts		153
(3). Exhibits
Reference is made to the Exhibit Index commencing on page 162.

K-158

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	UNISOURCE ENERGY CORPORATION
Date: February 27, 2012	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Principal
		Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: February 27, 2012	/s/ Paul J. Bonavia*
	Paul J. Bonavia
	Chairman of the Board and
	Principal Executive Officer
Date: February 27, 2012	/s/ Kevin P. Larson
	Kevin P. Larson
	Principal Financial Officer
Date: February 27, 2012	/s/ Karen G. Kissinger*
	Karen G. Kissinger
	Principal Accounting Officer
Date: February 27, 2012	/s/ Lawrence J. Aldrich*
	Lawrence J. Aldrich
	Director
Date: February 27, 2012	/s/ Barbara M. Baumann*
	Barbara M. Baumann
	Director
Date: February 27, 2012	/s/ Larry W. Bickle*
	Larry W. Bickle
	Director
Date: February 27, 2012	/s/ Harold W. Burlingame*
	Harold W. Burlingame
	Director
Date: February 27, 2012	/s/ Robert A. Elliott*
	Robert A. Elliott
	Director

K-159

Date: February 27, 2012		/s/ Daniel W.L. Fessler*
		Daniel W.L. Fessler
		Director
Date: February 27, 2012		/s/ Louise L. Francesconi*
		Louise L. Francesconi
		Director
Date: February 27, 2012		/s/ Warren Y. Jobe*
		Warren Y. Jobe
		Director
Date: February 27, 2012		/s/ Ramiro Peru*
		Ramiro Peru
		Director
Date: February 27, 2012		/s/ Gregory A. Pivirotto*
		Gregory A. Pivirotto
		Director
Date: February 27, 2012		/s/ Joaquin Ruiz*
		Joaquin Ruiz
		Director
Date: February 27, 2012	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each
		of the persons indicated

K-160

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TUCSON ELECTRIC POWER COMPANY
Date: February 27, 2012	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Principal
		Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: February 27, 2012		/s/ Paul J. Bonavia*
		Paul J. Bonavia
		Chairman of the Board and
		Principal Executive Officer
Date: February 27, 2012		/s/ Kevin P. Larson
		Kevin P. Larson
		Principal Financial Officer and Director
Date: February 27, 2012		/s/ Karen G. Kissinger*
		Karen G. Kissinger
		Principal Accounting Officer
Date: February 27, 2012		/s/ Michael J. DeConcini*
		Michael J. DeConcini
		Director
Date: February 27, 2012		/s/ David G. Hutchens*
		David G. Hutchens
		Director
Date: February 27, 2012	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

K-161

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. (Form 10-K for the year ended December 31, 1996, File No. 1-5924-Exhibit No 3(a)).
*3(a)(1)	—	TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-1379 – Exhibit 3(a))
*3(b)	—	Bylaws of TEP, as amended as of August 31, 2009 (Form 10-Q for the quarter ended September 30, 2009, File No. 13739 – Exhibit 3.1).
*3(c)	—	Amended and Restated Articles of Incorporation of UniSource Energy. (Form 8-A/A, dated January 30, 1998, File No. 1-13739 – Exhibit 2(a)).
*3(d)	—	Revised and restated bylaws of UniSource Energy, as revised and restated December 14, 2011 (Form 8-K, dated December 15, 2011, File No. 13739 – Exhibit 3.1)
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)).

K-162

*4(c)(4)	—	First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 — Exhibit 4(i)(4)).
*4(d)(1)	—	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — Exhibit 4(I)(1)).
*4(d)(2)	—	Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File no. 1-5924 — Exhibit 4(I)(2)).
*4(d)(3)	—	First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 — Exhibit 4(k)(3)).
*4(d)(4)	—	First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 — Exhibit 4(k)(4)).
*4(d)(5)	—	Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(k)(5)).
*4(d)(6)	—	Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(k)(6)).
*4(e)(1)	—	Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — Exhibit 4(m)(1)).
*4(e)(2)	—	Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds. 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — Exhibit 4(m)(2)).
*4(e)(3)	—	First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Developmental Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 — Exhibit 4(I)(3)).
*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-163

*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(e)(7)	—	Third Supplemental Indenture of Trust, dated as of December 7, 2011, between the Apache County Authority and U.S. Bank Trust National Association, as successor trustee, relating to Industrial Development Bonds 1983 Series B (Tucson Electric Power Company Springerville Project)
*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(f)(7)	—	Third Supplemental Indenture of Trust, dated as of December 7, 2011, between the Apache County Authority and U.S. Bank Trust National Association, as successor trustee, relating to Industrial Development Bonds 1983 Series C (Tucson Electric Power Company Springerville Project)
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)).

K-164

*4(h)(3)	—	First Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(o)(3)).
*4(h)(4)	—	First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(o)(4)).
*4(i)(1)	—	Indenture of Mortgage and Deed of Trust dated as of December 1, 1992, to Bank of Montreal Trust Company, Trustee. (Form S-1, Registration No. 33-55732 — Exhibit 4(r)(1)).
*4(i)(2)	—	Supplemental Indenture No. 1 creating a series of bonds designated Second Mortgage Bonds, Collateral Series A, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732 — Exhibit 4(r)(2)).
*4(i)(3)	—	Supplemental Indenture No. 2 creating a series of bonds designated Second Mortgage Bonds, Collateral Series B, dated as of December 1, 1997. (Form 10-K for year ended December 31, 1997, File No. 1-5924 — Exhibit 4(m)(3)).
*4(i)(4)	—	Supplemental Indenture No. 3 creating a series of bonds designated Second Mortgage Bonds, Collateral Series, dated as of August 1, 1998. (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 — Exhibit 4(c)).
*4(i)(5)	—	Supplemental Indenture No. 4 creating a series of bonds designated Second Mortgage Bonds, Collateral Series C, dated as of November 1, 2002. (Form 8-K dated November 27, 2002, File Nos. 1-05924 and 1-13739 — Exhibit 99.2).
*4(i)(6)	—	Supplemental Indenture No. 5 creating a series of bonds designated Second Mortgage Bonds, Collateral Series D, dated as of March 1, 2004. (Form 8-K dated March 31, 2004, File Nos. 1-05924 and 1-13739 — Exhibit 10 (b)).
*4(i)(7)	—	Supplemental Indenture No. 6 creating a series of bonds designated Second Mortgage Bonds, Collateral Series E, dated as of May 1, 2005. (Form 10-Q for the quarter ended March 31, 2005, File Nos. 1-5924 and 1-13739 – Exhibit 4(b)).
*4(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. (Form 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)).

K-165

4(i)(14)	—	Supplemental Indenture No.13, dated as of November 1, 2011, between Tucson Electric Power Company and The Bank of New York Mellon, amending terms of bonds designated First Mortgage Bonds, Collateral Series I.
*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. Bank 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 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(l)(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(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 B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(c)).
*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 B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(d)).
*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 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(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 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(o)(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. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.3).
4(o)(2)	–	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among Tucson Electric Power Company, Union Bank, N.A., as Administrative Agent, and a group of lenders.

K-166

*4(p)(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(p)(2)	—	Note Purchase Agreement, dated as of May 4, 2011, among UNS Gas, Inc., UniSource Energy Services, Inc., and a group of purchasers, (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.1).
*4(q)(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(r)(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(s)(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. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.1).
4(s)(2)	—	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among UniSource Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders.
*4(t)(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. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.4).
4(t)(2)	—	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among UNS Electric, Inc., UNS Gas, Inc., UniSource Energy Services, Inc., Union Bank, N.A., as Administrative Agent, and a group of lenders.
*4(u)(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(v)(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(w)(1)	—	Indenture of Trust, dated as of March 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Bank 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(w)(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(x)(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)).

K-167

*4(x)(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(x)(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(x)(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(y)(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(y)(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)).
*4(z)(1)	—	Credit Agreement, dated as of August 10, 2011, among UNS Electric, Inc., UniSource Energy Services, Inc., and Union Bank, N.A., as Administrative Agent (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.2).
*4(aa)(1)	—	Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank National Association, as trustee, authorizing 5.15% Notes due 2021 (Form 8-K dated November 8, 2011, File 1-13739 — Exhibit 4.1).
*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)).

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*10(a)(6)	—	Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(6)).
*10(a)(7)	—	Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(7)).
*10(a)(8)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(8)).
*10(a)(9)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(9)).
*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)).

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*10(a)(16)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(12)).
*10(a)(17)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(13)).
*10(a)(18)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(14)).
*10(a)(19)	—	Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(19)).
*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)).

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*10(b)(8)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(8)).
*10(b)(9)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(9)).
*10(b)(10)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(10)).
*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)).

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*10(b)(17)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(d)).
*10(b)(18)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit, LLC as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(e)).
*10(b)(19)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(f)).
*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).

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*10(d)	—	Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1. (Form S-1, Registration No. 33-55732 — Exhibit 10(u)).
*10(e)	—	Lease Agreement, dated as of December 15, 1992, between TEP, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 — Exhibit 10(v)).
*10(f)	—	Tax Indemnity Agreements, dated as of December 15, 1992, between the various Owner Participants parties thereto and TEP, as Lessee. (Form S-1, Registration No. 33-55732 — Exhibit 10(w)).
+*10(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)	—	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)	—	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).
+*10(v)	—	UniSource Energy Corporation 2011 Omnibus Stock and Incentive Plan. (Form 8-K dated May 10, 2011, File 1-13739 – Exhibit 10.1).

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12(a)	—	Computation of Ratio of Earnings to Fixed Charges – UniSource Energy.
12(b)	—	Computation of Ratio of Earnings to Fixed Charges – TEP.
21	—	Subsidiaries of the Registrants.
23(a)	—	Consent of Independent Registered Public Accounting Firm – UniSource Energy.
23(b)	—	Consent of Independent Registered Public Accounting Firm – TEP.
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).
#*101	—	The following materials from UniSource Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, formatted in XBRL (Extensible Business Reporting Language):

(a) UniSource Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Cash Flows, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Capitalization, (v) Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income; and

(b) Notes to Consolidated Financial Statements.

# These exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

(*) 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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