Edgar Filing: TUCSON ELECTRIC POWER CO

Registrant

Title of Each Class

Name of Each Exchange

on Which Registered

UNS Energy Corporation

Common Stock, no par value

New York Stock Exchange

10-K

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, 2012

¨	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	UNS 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:

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

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


UNS 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).


UNS 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.


UNS 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 website, 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).


UNS 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):


UNS 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).


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

The aggregate market value of UNS Energy Corporation voting Common Stock held by non-affiliates of the registrant was $1,574,040,179 based on the last reported sale price thereof on the consolidated tape on June 30, 2012.

At February 13, 2013, 41,386,469 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At February 13, 2013, 32,139,434 shares of Tucson Electric Power Company’s Common Stock, no par value, were outstanding, all of which were held by UNS 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 UNS Energy Corporation’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders are incorporated by reference into Part III.

Table of Contents


Definitions			vi
— 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			16
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 UNS Energy’s Website			21

Item 1A. – Risk Factors			22
Item 1B. – Unresolved Staff Comments			27
Item 2. – Properties			27
TEP Properties			27
UES Properties			28
Item 3. – Legal Proceedings			29
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			30

Item 6. – Selected Consolidated Financial Data			32
UNS Energy			32
TEP			33

Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations			34
UNS Energy Consolidated			34
Outlook and Strategies			34
Results of Operations			35
Liquidity and Capital Resources			37
Tucson Electric Power Company			41
Results of Operations			41
Factors Affecting Results of Operations			48
Liquidity and Capital Resources			51

iii


UNS Gas			57
Results of Operations			57
Factors Affecting Results of Operations			58
Liquidity and Capital Resources			59
UNS Electric			61
Results of Operations			61
Factors Affecting Results of Operations			63
Liquidity and Capital Resources			64
Other Non-Reportable Business Segments			66
Results of Operations			66
Factors Affecting Results of Operations			67
Critical Accounting Policies			67
Recently Issued Accounting Pronouncements			71
Safe Harbor for Forward-Looking Statements			72

Item 7A. – Quantitative and Qualitative Disclosures about Market Risk			72

Item 8. – Consolidated Financial Statements and Supplementary Data			78
Management’s Reports on Internal Controls Over Financial Reporting			78
Reports of Independent Registered Public Accounting Firm			80
UNS Energy Corporation
Consolidated Statements of Income			82
Consolidated Statements of Comprehensive Income			83
Consolidated Statements of Cash Flows			84
Consolidated Balance Sheets			85
Consolidated Statements of Capitalization			87
Consolidated Statements of Changes in Stockholders’ Equity			88
Tucson Electric Power Company
Consolidated Statements of Income			89
Consolidated Statements of Comprehensive Income			90
Consolidated Statements of Cash Flows			91
Consolidated Balance Sheets			92
Consolidated Statements of Capitalization			94
Consolidated Statements of Changes in Stockholder’s Equity			95
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies			96
Note 2. Regulatory Matters			104
Note 3. Segment and Related Information			112
Note 4. Commitments, Contingencies, and Environmental Matters			115
Note 5. Utility Plant and Jointly-Owned Facilities			122
Note 6. Debt, Credit Facilities, and Capital Lease Obligations			123
Note 7. Stockholders’ Equity			130
Note 8. Income Taxes			131
Note 9. Employee Benefit Plans			134
Note 10. Share-Based Compensation Plan			142
Note 11. Fair Value Measurements			144
Note 12. UNS Energy Earnings Per Share			149
Note 13. Millennium Investments			150
Note 14. Recently Issued Accounting Pronouncements			151
Note 15. Supplemental Cash Flow Information			152
Note 16. Accounting for Derivative Instruments and Hedging Activities			154
Note 17. Quarterly Financial Data (Unaudited)			157

Schedule II – Valuation and Qualifying Accounts			158

Item 9. – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			159

Item 9A. – Controls and Procedures			159


Item 9B. – Other Information			159
— PART III —

Item 10. – Directors, Executive Officers and Corporate Governance of the Registrants			160

Item 11. – Executive Compensation			162

Item 12. – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			162

Item 13. – Certain Relationships and Related Transactions and Director Independence			163

Item 14. – Principal Accountant Fees and Services			163

— PART IV —

Item 15. – Exhibits and Financial Statement Schedule			163
Signatures			164
Exhibit Index			167

DEFINITIONS

The abbreviations and acronyms used in the 2012 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
2010 TEP Reimbursement Agreement		Reimbursement Agreement dated December 14, 2010 among TEP as borrower and a financial institution
ACC		Arizona Corporation Commission
AFUDC		Allowance for Funds Used During Construction
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 UNS Gas’ delivery costs and customer charge. Base Rates exclude costs that are passed through to customers for fuel and purchased energy costs.
BHP		BHP Minerals International, Inc.
BMGS		Black Mountain Generating Station
Btu		British thermal unit(s)
Capacity		The ability to produce power; the most power a unit can produce or the maximum that can be taken under a contract; measured in megawatts
CC&N		Certificate of Convenience and Necessity
CCRs		Coal Combustion Residuals
Circuit Court		United States Court of Appeals
CO₂		Carbon Dioxide
Common Stock		UNS Energy’s common stock, without par value
Company or UNS Energy		UNS Energy Corporation and its subsidiaries
Convertible Senior Notes		UNS Energy Corporation’s 4.5% Convertible Senior Notes
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
ECA		Environmental Compliance Adjustor
EEIP		Energy Efficiency Implementation Plan
Electric EE Standards		Electric Energy Efficiency Standards
Emission Allowance(s)		An allowance issued by the Environmental Protection Agency which permits emission of one ton of sulfur dioxide or one ton of nitrogen oxide; allowances can be bought and sold
Energy		The amount of power produced over a given period of time; measured in megawatt-hours
EPA		Environmental Protection Agency
EL Paso		El Paso Electric Company
EPNG		El Paso Natural Gas Company
EPS		Earnings Per Share
ESP		Electric Service Provider
FAA		Federal Arbitration Act
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 Transition Recovery Asset; approximately $58 million was 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)
Heating Degree Days		An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65
IDBs		Industrial development revenue or pollution control revenue bonds
IRS		Internal Revenue Service
kV		Kilovolt(s)
kWh		Kilowatt-hour(s)
LFCR		Lost Fixed Cost Recovery Mechanism
LIBOR		London Interbank Offered Rate
LOC		Letter of Credit
Long-Term Wholesale Margin Revenues		A non-GAAP measure that demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts
Luna		Luna Generating Station
Mark-to-Market Adjustments		Adjustments to 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
MATS		Mercury and Air Toxics Standards
Millennium		Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy
MMBtu		Million British Thermal Units
Mortgage Bonds		Mortgage Bonds issued under the 1992 Mortgage
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Navajo		Navajo Generating Station
NERC		North American Electric Reliability Corporation
NO_x		Nitrogen oxide
NSP		Negotiated Sales Program
NTUA		Navajo Tribal Utility Authority
O&M		Operations and Maintenance
PBI		Performance Based Incentives
PGA		Purchased Gas Adjuster
PNM		Public Service Company of New Mexico
PNMR		PNM Resources, Incorporated, PNM’s parent company
PPA		Power Purchase Agreement
PPFAC		Purchased Power and Fuel Adjustment Clause
PV		Photovoltaic
RCRA		Resource Conservation and Recovery Act
REC		Renewable Energy Credit
RES		Renewable Energy Standard and Tariff
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. Retail Rates include the recovery of fuel and purchased power costs, as well as other surcharges and adjustor mechanisms charged to retail customers.
Rules		Retail Electric Competition Rules established by the ACC in 1999
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

vii


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 by all four Springerville units
Springerville Common Facilities Leases		Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1		Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases		Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2		Unit 2 of the Springerville Generating Station
Springerville Unit 3		Unit 3 of the Springerville Generating Station
Springerville Unit 4		Unit 4 of the Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sundt		H. Wilson Sundt Generating Station
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 UNS Energy Corporation
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 Btus
Transwestern		Transwestern Pipeline Company
Tri-State		Tri-State Generation and Transmission Association, Inc.
UED		UniSource Energy Development Company, a wholly-owned subsidiary of UNS Energy Corporation
UES		UniSource Energy Services, Inc., an intermediate holding company established to own UNS Gas and UNS Electric
UNS Credit Agreement		Second Amended and Restated Credit Agreement between UNS Energy and a syndicate of banks, dated as of November 9, 2010 (as amended)
UNS Energy		UNS Energy Corporation (formerly known as 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

viii

PART I

This combined Form 10-K is being filed separately by UNS Energy Corporation (UNS Energy) and Tucson Electric Power Company (TEP) (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 UNS 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 (See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Safe Harbor for Forward-Looking Statements). Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions. Forward-looking statements are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs, or projections will be achieved or accomplished. In addition, UNS 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

UNS Energy Corporation (UNS Energy), formerly UniSource Energy Corporation, is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS 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 UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of December 31, 2012. TEP generates, transmits and distributes electricity to approximately 406,000 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 United States. In addition, TEP operates Springerville Generating Station (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 149,000 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 92,000 retail customers in Mohave and Santa Cruz counties.

UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2012.

K-1

BUSINESS SEGMENT CONTRIBUTIONS

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


	2012		2011			2010
	-Millions of Dollars-
TEP	$	65	$	85		$	108
UNS Gas		9		10			9
UNS Electric		17		18			15
Other Non-Reportable Segments and Adjustments⁽¹⁾		—		(3	)		(19	)

Consolidated Net Income	$	91	$	110		$	113

⁽¹⁾	Includes: UNS Energy parent company expenses, Millennium, UED, and intercompany eliminations.

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

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

Rates and Regulation of TEP, UNS Gas, and UNS Electric

The Arizona Corporation Commission (ACC) regulates portions of TEP, UNS Gas, and UNS Electric’s utility accounting practices and energy rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. Our regulated utility rates for retail electric and natural gas service are determined on a “cost of service” basis. 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.

The rates charged to retail customers 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 UNS Energy. In 2012, TEP’s electric utility operations contributed 78% of UNS Energy’s operating revenues and comprised 84% of its assets.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to approximately 406,000 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 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 the 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. In 2013, the retail energy consumption by customer class is expected to be similar to the historical distribution.


	2012			2011			2010
Residential		41	%		42	%		42	%
Commercial		21	%		21	%		21	%
Non-mining Industrial		23	%		23	%		23	%
Mining		12	%		11	%		12	%
Public Authority		3	%		3	%		2	%

Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. In 2012, 2011, and 2010, TEP’s average number of retail customers increased by less than 1% in each year.

We expect the number of TEP’s retail customers to increase at a rate of less than 1% in 2013 and 2014.

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 electricity 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 0.9% in 2012 and 0.3% in 2011 as a result of increased production due to high copper prices.

Retail Sales Volumes

During the past three years, economic conditions and state requirements for energy efficiency and distributed generation have negatively affected retail electricity sales. TEP’s retail sales volumes in 2012 were approximately 9,265 Gigawatt-hours (GWh) or 1.1% below 2009.

Energy Service Providers

Although the Retail Electric Competition Rules established by the ACC in 1999 (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. See Rates 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. See Generating 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. TEP’s 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’s long-term contracts are described below:

•

From January 1, 2012 through the end of the contract in May 2016, Salt River Project Agriculture Improvement and Power District (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

•

TEP’s contract with the 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 2012, approximately 13% 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.

•

TEP’s 2 MW contract with the Tohono O’odham Utility Authority 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’s retail customers. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. See Rates 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, 2012, TEP owned or leased 2,267 MW of net generating capability, as set forth in the following table:


					Net
	Unit		Date	Resource	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 Generating Station	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 Tucson Solar Projects		Springerville, AZ Tucson, AZ	2002-2010 2010-2012	Solar Solar		6 12	TEP TEP		100.0 100.0		6 12

Total TEP Capacity ⁽²⁾											2,267

⁽¹⁾	Leased asset as of December 31, 2012.

⁽²⁾	Excludes 683 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2012, total owned capacity was 1,866 MW and leased capacity was 401 MW.

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Springerville Generating Station

TEP currently owns a 14% undivided interest in Unit 1 of the Springerville Generating Station (Springerville Unit 1) and the remainder is leased by TEP. Unit 2 of the Springerville Generating Station (Springerville Unit 2) is owned by San Carlos Resources, Inc. (San Carlos), a wholly-owned subsidiary of TEP. TEP’s other interests in the Springerville Generating Station (Springerville) include leasehold interests in the Springerville Coal Handling Facilities and the facilities at Springerville used in common by all four Springerville units (Springerville Common Facilities).

Springerville Unit 1 Leases

The terms of the leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities (Springerville Unit 1 Leases), 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, based on a continuous capacity rating of 387 MW. TEP has until September 1, 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. 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. See Item 3. – Legal Proceedings, Springerville Unit 1 Appraisal.

Springerville Common Facilities Leases

The leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities (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.

Springerville Coal Handling Facilities Lease

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 April 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 H. Wilson Sundt Generating Station (Sundt) 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, 2012, TEP owned 18 MW of photovoltaic (PV) solar generating capacity. The Springerville solar system, which is located near the Springerville Generating Station, has a total capacity of 6 MW. TEP’s remaining 12 MW of PV solar generating capacity is located in the City of Tucson.

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Power Purchase Agreements

In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 125 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, 2012, approximately 74 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. See Rates and Regulation, Renewable Energy Standard and Tariff below for more information.

Purchases and Interconnections

TEP purchases power from other utilities and power marketers. TEP may enter into contracts: (a) to purchase energy under long-term contracts to serve retail load and long-term wholesale contracts, (b) to purchase capacity or energy during periods of planned outages or for peak summer load conditions, and (c) to purchase energy for resale to certain wholesale customers under load and resource management agreements.

TEP typically uses generation from its gas-fired units, supplemented by power purchases, 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 Springerville 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. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4.

Peak Demand and Resources


Peak Demand	2012			2011			2010			2009			2008
	-MW-
Retail Customers		2,290			2,334			2,333			2,354			2,376
Firm Sales to Other Utilities		286			322			340			385			394

Coincident Peak Demand (A)		2,576			2,656			2,673			2,739			2,770

Total Generating Resources		2,267			2,262			2,245			2,229			2,204
Other Resources ⁽¹⁾		683			1,009			799			781			966

Total TEP Resources (B)		2,950			3,271			3,044			3,010			3,170

Total Margin (B) – (A)		374			615			371			271			400
Reserve Margin (% of Coincident Peak Demand)		15	%		23	%		14	%		10	%		14	%

⁽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.

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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 over the period of 2008 to 2012 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 the reserve margin is the ratio of margin to coincident peak demand. TEP’s reserve margin in 2012 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.

Forecasted retail peak demand for 2013 is 2,243 MW, compared with actual peak demand of 2,290 MW in 2012 when Cooling Degree Days exceeded the ten-year average by 4.9%. TEP’s 2013 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 2013.

Future Generating Resources

TEP will add generating resources and/or transmission import capability to meet forecasted retail and firm wholesale load. TEP expects to add approximately 65 MW of new solar PV resources in 2013.

FUEL SUPPLY

Fuel Summary

Fuel cost and usage information is provided below:


	Average Cost per MMBtu						Percentage of Total Btu
	Consumed						Consumed
	2012		2011		2010		2012			2011			2010
Coal	$	2.44	$	2.42	$	2.23		88	%		92	%		90	%
Gas	$	3.92	$	5.20	$	4.69		12	%		8	%		10	%
All Fuels	$	2.63	$	2.65	$	2.47		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, was $45.84 in 2012, $46.64 in 2011, and $41.99 in 2010.


Station	Coal Supplier	2012 Coal Consumption (tons in 000’s)		Contract Expiration		Avg. Sulfur Content			Coal Obtained From⁽¹⁾
Springerville	Peabody Coalsales		3,287		2020		0.9	%	Lee Ranch Coal Co.
Four Corners	BHP Billiton		400		2016		0.8	%	Navajo Indian Tribe
San Juan	San Juan Coal Co.		1,098		2017		0.8	%	Federal and State Agencies
Navajo	Peabody Coalsales		475		2019		0.4	%	Navajo and Hopi Indian Tribes

⁽¹⁾	Substantially all of the suppliers’ mining leases extend at least as long as coal is being mined in economic quantities.

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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 Unit 4 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 2013, TEP expects to fuel Sundt Unit 4 with coal from inventory. See Note 4 for more information.

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 Public Service Company of New Mexico (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 MW 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 Generating Station (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.

TRANSMISSION ACCESS

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 has obtained ACC approval 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 2016. As a result of these high-voltage transmission additions, TEP expects that its ability to import energy into its service territory would increase by at least 250 MW.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP had previously capitalized $11 million related to the project, including $2 million to secure land and land rights. UNS Electric had previously capitalized $0.4 million related to the project.

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TEP and UNS Electric expect to abandon the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting the elimination of this project. In TEP’s pending rate case proceeding before the ACC, TEP entered into a proposed settlement agreement in which it agrees to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. In the fourth quarter of 2012, TEP and UNS Electric wrote off a portion of the capitalized costs believed not probable of recovery and recorded a regulatory asset for the balance deemed probable of recovery. TEP and UNS Electric believe it is probable that we will recover at least $5 million and $0.2 million, respectively, of costs incurred through 2012. See Note 4 and see Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, for more information.

RATES AND REGULATION

2012 TEP Rate Case

In July 2012, TEP filed an application for a base rate increase with the ACC. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, for more information.

Purchased Power and Fuel Adjustment Clause

The Purchased Power and Fuel Adjustment Clause (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.

•

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

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

In March 2012, the ACC approved a PPFAC rate of 0.77 cents per kWh effective April 2012 to recover $77 million of under-collected fuel and purchased power costs. At December 31, 2012, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $12 million.

A proposed settlement agreement in TEP’s pending rate case proceeding includes certain modifications to TEP’s PPFAC. In February 2013, TEP filed a request with the ACC to defer the effective date of resetting the PPFAC until the effective date of new rates in TEP’s pending rate case. This request is consistent with a provision of the settlement agreement. TEP cannot predict if or when the ACC will respond to its request. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, PPFAC Modifications, for more information.

Renewable Energy Standard and Tariff

The ACC’s Renewable Energy Standard (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 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.

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In 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 2012, TEP’s solar energy investments totaled $28 million. During 2012, TEP earned approximately $2 million pre-tax on its non-rate base investments in solar projects. In 2012, TEP spent $30 million on its 2012 RES implementation plan and met the 2012 renewable energy target of 3.5% of retail kWh sales.

In January 2013, the ACC approved TEP’s 2013 RES implementation plan. Under the plan, TEP expects to collect approximately $36 million from retail customers during 2013. The plan includes an investment of $28 million in 2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $4 million pre-tax in 2013 on solar investments made in 2010, 2011, and 2012. TEP expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales.

Electric Energy Efficiency Standards and Decoupling

In August 2010, the ACC approved new Electric Energy Efficiency Standards (Electric EE Standards) designed to require TEP, UNS Electric, and other affected electric utilities to implement cost-effective programs to reduce customers’ energy consumption. In 2012, the Electric EE Standards target total kWh savings of 3% of 2011 retail kWh sales; in 2013, the Electric EE Standards target total kWh savings of 5% of 2012 retail kWh sales. The Electric EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020. The cumulative annual energy savings from TEP’s energy efficiency and DSM programs equaled approximately 2.5% of its 2011 retail kWh sales.

New and existing DSM programs, direct load control programs, and energy efficient building codes are acceptable means to meet the Electric EE Standards as set forth by the ACC. The Electric EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s programs, and the rates charged to customers for such programs, are subject to annual review and approval by the ACC.

A proposed settlement agreement in TEP’s pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. See Item. 7—Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, Energy Efficiency Resource Plan.

Decoupling

In 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona’s Electric EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring utility rates to separate the recovery of fixed costs from the level of energy consumed. The policy statement allows affected utilities to file rate decoupling proposals in their next general rate case. A proposed settlement agreement in TEP’s pending rate case proceeding includes a partial decoupling mechanism. See Item. 7—Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, Lost Fixed Cost Recovery Mechanism.

Retail Electric Competition Rules

In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004. In 2008, the ACC opened an administrative proceeding to address the Rules but has since taken no action. During 2012, a small number of companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP’s service territory as an ESP. Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP’s retail customers to use an alternative ESP. We cannot predict what changes, if any, the ACC will make to the Rules or if the ACC will grant a CC&N to an ESP.

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TEP’S UTILITY OPERATING STATISTICS


	2012		2011		2010			2009			2008
Generation and Purchased Power – kWh (000)
Remote Generation		10,284,612		10,005,127		9,077,032			9,134,183			10,438,864
Local Tucson Generation (Oil, Gas, & Coal)		803,146		906,496		1,492,885			1,131,399			1,016,254
Renewable Generation		44,930		28,049		24,511			23,712			33,776
Purchased Power		2,328,420		2,686,918		2,846,005			3,809,890			3,358,577

Total Generation and Purchased Power		13,461,108		13,626,590		13,440,443			14,099,184			14,847,471
Less Losses and Company Use		789,613		822,220		879,423			936,206			953,036

Total Energy Sold		12,671,495		12,804,370		12,561,010			13,162,978			13,894,435

Sales – kWh (000)
Residential		3,820,637		3,888,011		3,869,540			3,905,696			3,852,707
Commercial		1,973,931		1,972,526		1,963,469			1,988,356			2,034,453
Industrial		2,132,214		2,145,163		2,138,749			2,160,946			2,263,706
Mining		1,092,518		1,083,071		1,079,327			1,064,830			1,095,962
Public Authorities		245,519		243,336		240,703			250,915			255,817

Total – Electric Retail Sales		9,264,819		9,332,107		9,291,788			9,370,743			9,502,645
Electric Wholesale Sales		3,406,676		3,472,263		3,269,222			3,792,235			4,391,790

Total Electric Sales		12,671,495		12,804,370		12,561,010			13,162,978			13,894,435

Operating Revenues (000)
Residential	$	387,840	$	383,908	$	372,212		$	377,761		$	351,079
Commercial		228,940		223,621		217,032			219,694			211,639
Industrial		166,739		164,024		159,937			163,720			164,849
Mining		66,158		65,720		62,112			61,033			55,619
Public Authorities		20,910		20,024		19,128			19,865			19,146
RES and DSM		45,292		46,633		37,767			25,443			2,781
Other		—		—		—			—			415

Total – Electric Retail Sales		915,879		903,930		868,188			867,516			805,528
CTC To Be Refunded		—		—		—			—			(58,092	)
Wholesale Revenue- Long-Term		24,910		41,056		55,653			48,249			57,493
Wholesale Revenue- Short-Term		71,257		72,798		71,435			84,410			197,754
California Power Exchange Provision for Wholesale Refunds		—		—		(2,970	)		(4,172	)		—
Transmission		15,793		16,392		20,863			18,974			17,173
Other Revenues		133,821		122,210		112,098			84,361			72,292

Total Operating Revenues	$	1,161,660	$	1,156,386	$	1,125,267		$	1,099,338		$	1,092,148

Customers (End of Period)
Residential		369,480		367,396		366,217			365,157			363,861
Commercial		36,214		36,203		35,877			35,759			35,432
Industrial		632		636		635			629			633
Mining		2		2		2			2			2
Public Authorities		62		62		62			61			61

Total Retail Customers		406,390		404,299		402,793			401,608			399,989

Average Retail Revenue per kWh Sold (cents)
Residential		10.2		9.9		9.6			9.7			9.1
Commercial		11.6		11.3		11.1			11.0			10.4
Industrial and Mining		7.2		7.1		6.9			7.0			6.6
Average Retail Revenue per kWh Sold (excludes RES and DSM)		9.4		9.2		8.9			9.0			8.4

Average Revenue per Residential Customer	$	1,050	$	1,045	$	1,016		$	1,035		$	965
Average kWh Sales per Residential Customer		10,341		10,583		10,566			10,696			10,588

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ENVIRONMENTAL MATTERS

Clean Air Act Requirements

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $2 million in 2012, $8 million in 2011, and $18 million in 2010 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan. TEP expects to capitalize environmental compliance costs of $10 million in 2013 and $27 million in 2014. In addition, TEP recorded Operations and Maintenance (O&M) expense of $15 million in 2012, $12 million in 2011, and $14 million in 2010 related to environmental compliance. TEP expects environmental O&M expenses to be $16 million in 2013.

TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its retail customers.

TEP has sufficient emission allowances to comply with acid rain SO₂ regulations.

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 February 2012, the EPA issued final rules called the Mercury and Air Toxics Standards (MATS) setting limits for mercury emissions and other hazardous air pollutants from power plants.

Navajo

Based on the EPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which includes the regional haze final Best Available Retrofit Technology (BART) rules.

San Juan

TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards.

Four Corners

Based on the EPA’s final standards, Four Corners may need mercury emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million. We expect TEP’s share of the annual operating cost of the mercury emission control equipment to be less than $1 million.

Springerville Generating Station

Based on the EPA’s final standards, Springerville Units 1 and 2 may need mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million.

Sundt Generating Station

TEP expects the final EPA standards will have little effect on capital expenditures at Sundt.

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Climate Change

In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al. v. EPA that carbon dioxide and other Greenhouse Gases (GHG) 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 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.

In March 2012, the EPA released its proposed new source performance standard for GHGs. TEP does not anticipate this standard will have any material impact on its existing facilities.

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 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. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight. The EPA oversees Regional Haze planning for these power plants.

Complying with the EPA’s BART findings, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.

Navajo

In January 2013, the EPA proposed an alternative BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. If SCR technology is ultimately required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant’s particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP’s share of annual operating costs are estimated at less than $1 million for each of the control technologies (SCR and baghouses).

San Juan

In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.

In 2011, PNM filed a petition for review of and a motion to stay the FIP with the Tenth Circuit United States Court of Appeals (Circuit Court). In addition, PNM filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA’s reconsideration and the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and the EPA. Several environmental groups were granted permission to join in opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP’s five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the Court’s decision.

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In February 2013, the State of New Mexico released a proposed plan that it presented to the EPA as an alternative to the FIP. The proposed plan includes: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction (SNCR) technology on San Juan Units 1 and 4 by January 31, 2016. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million.

TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At December 31, 2012, the book value of TEP’s share of San Juan Units 1 and 2 was $217 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals.

If the proposed plan is not accepted and agreed to by the EPA, New Mexico Environmental Department, the San Juan participants, and various other regulatory entities, TEP may begin making capital expenditures to install SCRs on San Juan Units 1 and 2 in 2013 to meet the FIP compliance deadline. TEP cannot predict the outcome of this matter.

Four Corners

In August 2012, the EPA finalized the Regional Haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. In either case, TEP’s estimated share of the capital costs to install SCR technology is about $35 million. TEP’s share of annual operating costs for SCR is estimated at $2 million.

Springerville

Regional Haze regulations requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018.

Sundt

In December 2012, the EPA issued a proposed rule on provisions, that had not been previously addressed, in the Arizona State Implementation Plan related to regional haze. Contrary to the Arizona plan the EPA disapproved, among other things, the determination that Sundt Unit 4 is not subject to the BART provisions of the regional haze rule and is therefore subject to BART requirements. If the BART eligibility determination stands, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART rule which is likely to be completed in October 2013. The EPA is expected to release a proposed BART requirement for Sundt Unit 4 in March 2013.

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Environmental Investments and Expenses

The table below provides a summary of the estimated impact of pending environmental regulations on TEP’s annual O&M expense and capital expenditures.


Generating Station	Estimated Annual O&M Expense		Estimated Capital Expenditures		Regulation (Compliance Date)	Upgrades
	-Millions of Dollars-
San Juan Units 1 & 2	$	6	$	180 – $200	Regional Haze/BART (2016)	SCRs⁽¹⁾
Navajo Units 1-3	$	3	$	86	MATS (2015) Regional Haze/BART (2023)	Mercury Controls; SCRs; Baghouses
Four Corners Units 4 & 5	$	3	$	36	MATS (2015) Regional Haze/BART (2018)	Mercury Controls; SCRs
Springerville Units 1 & 2	$	3	$	5	MATS (2015)	Mercury Controls

⁽¹⁾	If SNCR technology is installed on San Juan Unit 1, TEP estimates its share of the cost would be approximately $25 million. See Regional Haze Rules, San Juan, above.

Coal Combustion Residuals

In 2010, the EPA proposed a rule to regulate 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 for both storage and handling at plants and transportation to 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. We expect the EPA to issue a final rule in 2013 or 2014. TEP cannot determine the financial impact of this rulemaking at this time.

UNS GAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 149,000 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 58% of total revenues in 2012.

UNS Gas’ annual retail customer growth rate was less than 1% from 2010 through 2012. In 2013, we expect UNS Gas’ retail customer base to increase by approximately 0.4%.

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.

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UNS Gas buys most of the gas it distributes from the San Juan Basin. 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 that expires in 2024. 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.

See Item 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

2012 UNS Gas Rate Order

In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a Lost Fixed Cost Recovery (LFCR) mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the Gas Energy Efficiency Standards (Gas EE Standards). The LFCR is expected to recover lost fixed cost revenues of less than $0.1 million in 2013, based on estimated lost retail therm sales from May through December 2012. The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills was offset by a temporary credit adjustment to the PGA. See Purchased Gas Adjustor, below, for more information.

2010 UNS Gas Rate Order

The ACC authorized a Base Rate increase of $3 million, or 2%, effective in April 2010.

Purchased Gas Adjustor

The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered or returned to customers through the PGA mechanism.

The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that calculates the 12-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 15 cents 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-customer basis, UNS Gas is required to make a filing with the ACC to determine how the over-collected balance should be returned to customers.

In April 2012, the ACC approved a temporary PGA credit adjustment of 4.5 cents per therm which became effective on May 1, 2012. At December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.

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Gas Energy Efficiency Standards and Decoupling

In 2010, the ACC approved Gas EE Standards which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2012, the Gas EE Standards targeted total retail therm savings equal to 1.2% of 2011 sales; in 2013, the Gas EE Standards target total therm savings of 1.8% of 2012 retail therm sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020. UNS Gas’ programs, during 2011 and 2012, saved cumulative energy equal to approximately 0.35% of its 2011 retail therm sales.

New and existing DSM programs, renewable energy technology that displaces gas, and certain energy efficient building codes are acceptable means to meet the Gas EE Standards. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas’ DSM programs and rates charged to retail customers for these programs are subject to ACC approval.

In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Energy Efficiency plan or the subsequent requests.

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. See Item. 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 92,000 retail customers in Mohave and Santa Cruz counties. These counties have a combined population of approximately 250,000. UNS Electric’s annual retail customer growth rate was less than 1% from 2010 through 2012. We estimate that UNS Electric’s retail customer base will increase by approximately 0.8% in 2013. UNS Electric’s customer base is primarily residential, with some commercial and industrial customers. Peak demand for 2012 was 437 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. See Rates 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 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 see Rates and Regulation, Renewable Energy Standard and Tariff below.

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Future Generating Resources

UNS Electric invested $5 million in 2012 in company-owned solar PV capacity and expects to invest approximately $5 million in 2013 and 2014 in company-owned solar PV capacity. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff for more information.

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 transmission service agreements with WAPA for its transmission capacity that expire in June 2016.

UNS Electric is upgrading its existing 115 kV transmission line serving Santa Cruz County to 138 kV to improve service reliability. This upgrade is expected to be completed by October 2014 and is included in UNS Electric’s current capital expenditures forecast. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resources for more information.

RATES AND REGULATION

2012 UNS Electric Rate Filing

In December 2012, UNS Electric filed an application for a base rate increase with the ACC. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Filing, for more information.

2010 UNS Electric Rate Order

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

The 2010 UNS Electric Rate Order approved UNS Electric’s purchase of BMGS from UED.

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.

In compliance with the 2010 Rate Order, UNS Electric filed a rate case application in December 2012. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Filing, for more information.

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.

At December 31, 2012, UNS Electric’s PPFAC bank balance was under-collected by $11 million on a billed-to-customer basis.

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.

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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 2013 and 2014 in solar photovoltaic projects.

In January 2013, the ACC approved UNS Electric’s 2013 RES implementation plan. UNS Electric will collect approximately $7 million from customers during 2013, a portion of which is expected to provide recovery of operating costs and a return on investment to UNS Electric for company-owned solar projects.

Energy Efficiency Standards and Decoupling

In 2010, the ACC approved Electric EE Standards designed to require UNS Electric, TEP, and other affected electric utilities to implement cost effective DSM programs. For more information, see TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling, above. UNS Electric’s programs, during 2011 and 2012, saved cumulative energy equal to approximately 2.5% of its 2011 retail kWh sales.

UNS Electric filed a general rate case in December 2012 which included a request for a partial decoupling mechanism. See Item. 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Case, Lost Fixed Cost Recovery Mechanism.

In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC will issue a final order in this matter.

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. See Item. 1 – Business, TEP, Environmental Matters, for more information.

OTHER NON-REPORTABLE SEGMENTS

Millennium

As of December 31, 2012, Millennium had assets of $7 million, including cash and cash equivalents of $4 million. In total, Millennium’s assets represented less than 1% of UNS Energy’s total consolidated assets. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other Non-Reportable Business Segments, for more information.

SES

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

EMPLOYEES (As of December 31, 2012)

TEP had 1,392 employees, of which approximately 49% are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A new collective bargaining agreement between the IBEW and TEP was entered into in January 2013 and expires in January 2016.

UNS Gas had 186 employees, of which 110 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 2015 and February 2014, respectively.

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UNS Electric had 148 employees, of which 30 employees were represented by the IBEW Local No. 387 and 88 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 253 employees, of which 226 are represented by IBEW Local No. 1116 and 16 by IBEW Local No. 570. These agreements expire in December 2014 and May 2013, respectively.

EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers – UNS Energy and TEP

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


Name	Age	Position(s) Held	Executive Officer Since
Paul J. Bonavia	61	Chairman and Chief Executive Officer	2009
David G. Hutchens	46	President	2007
Michael J. DeConcini	48	Senior Vice President, Operations	1999
Kevin P. Larson	56	Senior Vice President and Chief Financial Officer⁽¹⁾	2000
Philip J. Dion III	44	Vice President, Public Policy	2008
Kentton C. Grant	54	Vice President, Finance and Rates⁽²⁾	2007
Todd C. Hixon	46	Vice President and General Counsel	2011
Arie Hoekstra	65	Vice President, Generation	2007
Karen G. Kissinger	58	Vice President, Controller and Chief Compliance Officer	1998
Mark Mansfield	57	Vice President, Generation	2012
Thomas A. McKenna	64	Vice President, Engineering	2007
Catherine E. Ries	53	Vice President, Human Resources	2007
Herlinda H. Kennedy	51	Corporate Secretary	2006

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

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



*Paul J. Bonavia*		Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009. He also served as President from January 2009 to December 2011. Prior to joining UNS 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 UNS Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UNS 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 UNS Energy and TEP. Mr. Hutchens joined TEP in 1995.

*Michael J. DeConcini*		Mr. DeConcini has served as Senior Vice President, Operations of UNS 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 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 UNS Energy and TEP since September 2005. Mr. Larson is also Treasurer of UNS Energy. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He was elected Treasurer in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer.

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*Philip J. Dion III*		Mr. Dion has served as Vice President of Public Policy of UNS Energy and TEP since April 2010. Mr. Dion joined UNS Energy in February 2008 as Vice President of Legal and Environmental Services. Prior to joining UNS 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 the FERC.

*Kentton C. Grant*		Mr. Grant has served as Vice President of Finance and Rates of UNS 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 UNS 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 UNS 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 UNS 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.

*Mark Mansfield*		Mr. Mansfield is Vice President of Generation. He joined the company in 2008, most recently serving as Senior Director of Generation. Prior to joining TEP, Mr. Mansfield held various leadership positions at PacifiCorp Energy.

*Thomas A. McKenna*		Mr. McKenna has served as Vice President of Engineering of UNS 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 UNS Energy and TEP since June 2007. Prior to joining UNS 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 UNS Energy and TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999.

SEC REPORTS AVAILABLE ON UNS ENERGY’S WEBSITE

UNS 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 UNS Energy’s website address: http://www.uns.com. A link from UNS Energy’s website to these SEC reports is accessible as follows: At the UNS 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. UNS Energy’s code of ethics, which applies to the Board of Directors and all officers and employees of UNS Energy and its subsidiaries, and any amendments or any waivers made to the code of ethics, is also available on UNS Energy’s website.

UNS Energy and TEP are providing the address of UNS Energy’s website solely for the information of investors and do not intend the address to be an active link. Information contained at UNS Energy’s website is not part of any report filed with the SEC by UNS Energy or TEP.

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ITEM 1A. – RISK FACTORS

The business and financial results of UNS Energy and TEP are subject to a number of risks and uncertainties, including those set forth below and in other documents we file with the SEC. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational.

REVENUES

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

Economic conditions have contributed significantly to a reduction in TEP’s retail customer growth and lower energy usage by the company’s residential, commercial, and industrial customers. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 0.4% in each year from 2008 through 2012 compared with average increases of approximately 2% in each year from 2003 to 2007. In 2012, total retail kWh sales were 0.7% below 2011 levels. TEP estimates that a 1% change in annual retail sales could impact pre-tax net income and pre-tax cash flows by approximately $6 million.

Similar impacts were felt at UNS Gas and UNS Electric. Annual average increases in the number of retail customers at both companies remained below 1% in 2008 through 2012 compared with average annual growth rates of 3% from 2003 to 2007. We estimate that a 1% change in annual retail sales at UNS Gas and UNS Electric could impact pre-tax net income and pre-tax cash flows by approximately $1 million.

New technological developments and the implementation of new Energy Efficiency Standards will continue to have a significant impact on retail sales, which could negatively impact UNS 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 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 the summer. 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% impact in annual retail sales would impact pre-tax net income and pre-tax cash flows by approximately $6 million. We estimate that a 1% change in annual retail sales at UNS Gas and UNS Electric would impact pre-tax net income and pre-tax cash flows by approximately $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. UNS 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

UNS 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 customers. 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 CO₂ and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. In 2012, 72% of TEP’s total energy resources came from its coal-fueled generating facilities.

Reductions in CO₂ emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. Any future legislation or regulation addressing climate change could produce a number of other results including costly modifications to, or reexamination of the economic viability of, our existing coal plants; changes in the overall fuel mix of our generating fleet; or additional costs to fund energy efficiency activities. The impact of legislation or regulation to address global climate change would depend on the specific terms of those measures and cannot be determined at this time.

K-23

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 retiree plans and may increase the amount and accelerate the timing of required future funding contributions.

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

As of February 13, 2013, 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 0.06% to 0.26% in 2012. 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.

UNS 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 London Interbank Offer Rate (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 UNS 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 we contract for such resources include requirements to post credit enhancement in the form of cash or letters of credit (LOCs) 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 LOCs under their revolving credit agreements.

The maximum amount TEP may use under its revolving credit facility is $200 million. As of February 13, 2013, TEP had $169 million available to borrow under its revolving credit facility. The maximum amount UNS Gas or UNS Electric may borrow is $70 million, so long as the combined amount drawn by both companies does not exceed $100 million (the size of their combined borrowing capacity under the revolving credit facility). As of February 13, 2013, UNS Gas had $70 million and UNS Electric had $70 million, available 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, 2012, TEP and UNS Electric each had posted less than $1 million with counterparties in the form of cash or LOCs.

K-24

UNS Energy and its subsidiaries have debt which could adversely affect their business and results of operations.

UNS Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. At December 31, 2012, the ratio of total debt (including capital lease obligations net of investments in lease debt) to total capitalization for UNS Energy and its subsidiaries was 63%. This debt level:

•

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

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

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


Leased Asset	Expiration	Purchase Option
Springerville Unit 1	2015	Fair market value purchase option 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 owner participants of Springerville Unit 1 have disputed the appraisal price; however, TEP believes that the appraisal procedure was properly conducted in accordance with the lease agreements and that the results are final and binding.

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 could limit the ability of TEP, UNS Gas, and UNS Electric to make distributions to UNS Energy.

As a holding company, UNS 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 states that an electric utility’s dividends shall not be paid out of funds properly included in capital accounts. 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

•

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

K-25

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

The UNS 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.

The nature of our gas operations presents inherent risks of loss that could adversely affect our results of operations.

The operation of UNS Gas’ transmission and distribution systems involves certain risks, including gas leaks, fires, natural disasters, catastrophic accidents, explosions, pipeline ruptures, and other hazards and risks that may cause unforeseen interruptions, personal injury, or property damage. Any such incident could have an adverse effect on UNS Gas.

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.

K-26

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:

•

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 (see Item 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, 2012, TEP owned or participated in an overhead electric transmission and distribution system consisting of:

•

564 circuit-miles of 500-kV lines;

•

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

•

405 circuit-miles of 138-kV lines;

•

481 circuit-miles of 46-kV lines; and

•

2,612 circuit-miles of lower voltage primary lines.

TEP’s underground electric distribution system includes 4,410 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 13,269,950 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, a wholly-owned subsidiary of TEP, 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.

K-27

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

Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Nation. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired land rights, easements and leases for the plant, 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 American Indian Reservations. TEP, in conjunction with PNM and Freeport McMoRan, holds an undivided ownership interest in the property on which Luna is located.

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

•

possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs (BIA) 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, 2012, UNS Gas’ transmission and distribution system consisted of approximately 31 miles of steel transmission mains, 4,229 miles of steel and plastic distribution piping, and 137,705 customer service lines.

UNS Electric

As of December 31, 2012, 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 3,648 circuit-miles of underground and overhead distribution lines. UNS Electric also owns the 62 MW Valencia plant, the 90 MW BMGS, as well as 40 substations having a total installed capacity of 1,504,000 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.

K-28

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 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.

Springerville Unit 1 Appraisal

Springerville Unit 1 is leased by TEP under leases which expire in 2015 and which provide TEP with an option to purchase the lease interests upon the lease expiration at fair market value. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure with three appraisers in accordance with the lease agreements to determine the fair market value purchase price. The lease agreements provide that the purchase price determined through the appraisal procedure will be final and binding upon the parties. The aggregate purchase price for the owner participants’ lease interests was determined to be $159 million.

On April 26, 2012, TEP filed a petition to confirm the appraisal in the United States District Court for the District of Arizona naming the owner participants (Daimler Capital Services LLC, LDVFI TEP LLC, Alterna Springerville LLC, MWR Capital Inc., and Pacific Harbor Capital Inc.) and the owner trustee and co-trustee (Wilmington Trust Company and William J. Wade) as respondents. The petition states that TEP filed the petition since neither the owner participants nor the owner trustee and co-trustee have acknowledged that the purchase price determined by the appraisal procedure in December 2011 is final and binding and that TEP seeks an order from the court confirming the appraisal as an arbitration award under the Federal Arbitration Act (FAA).

On June 1, 2012, the owner participants filed a response in opposition to TEP’s petition. In their response, the owner participants allege that the appraisal procedure failed to yield a legitimate purchase price for the lease interests, stating, among other things, that not all of the three appraisers performed their appraisals in accordance with required standards. The owner participants requested that the court dismiss the action and deny TEP’s petition on the grounds that there is not a present controversy for the court to decide, since, among other things, TEP has not exercised the purchase option. The owner participants also dispute TEP’s position that the appraisal procedure should be treated as an arbitration award for purposes of judicial review. In January 2013, the court denied TEP’s petition on the grounds that the court is without jurisdiction under the FAA to confirm the appraisal.

On February 12, 2013, TEP appealed the matter to the United States Court of Appeals for the Ninth Circuit.

TEP believes that the appraisal procedure was properly conducted in accordance with the lease agreements and that the results are final and binding. TEP intends to continue vigorously pursuing its legal remedies to confirm the results of the appraisal procedure.

In addition, see legal proceedings described in Note 4.

ITEM 4. – MINE SAFETY DISCLOSURES

Not applicable.

K-29

PART II

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

Stock Trading

UNS Energy’s Common Stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On February 13, 2013, the closing price was $46.42 with 7,881 shareholders of record.

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

Dividends

UNS Energy

UNS 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 25, 2013, UNS Energy declared a first quarter cash dividend of $0.435 per share of Common Stock. The first quarter dividend, totaling approximately $18 million, will be paid March 25, 2013 to shareholders of record at the close of business March 13, 2013. The table below summarizes UNS Energy’s dividends paid in 2010 through 2012.


	2012		2011		2010
Quarterly Dividend Per Common Share	$	0.43	$	0.42	$	0.39
Annual Dividend Per Common Share	$	1.72	$	1.68	$	1.56
Common Stock Dividends Paid	$	70 million	$	62 million	$	57 million

UNS Energy relies on dividends from its subsidiaries, primarily TEP, to declare and pay dividends.

TEP

TEP paid $30 million of dividends to UNS Energy in 2012. TEP did not pay any dividends to UNS Energy in 2011. TEP paid $60 million of dividends to UNS Energy in 2010.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2012, 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. TEP has an accumulated deficit rather than positive retained earnings. 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

UNS Gas paid dividends to UNS Energy of $20 million in 2012, and $10 million in both 2011 and 2010. 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, 2012, UNS Gas was in compliance with the terms of its note purchase agreement.

UNS Electric

UNS Electric paid dividends to UNS Energy of $10 million in 2012. UNS Electric did not pay any dividends to UNS Energy in 2011 or 2010. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

K-30

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, 2012, UNS Electric was in compliance with the terms of its note purchase agreement.

Other Non-Reportable Segments

In 2012, Millennium paid dividends of $14 million to UNS Energy. In 2011 and 2010, Millennium paid dividends of $3 million and $8 million to UNS Energy, respectively.

UED did not pay any dividends to UNS Energy in 2012. In 2011 and 2010 UED paid dividends to UNS Energy of $39 million and $9 million, respectively. Of those dividends paid by UED, the portions representing a return of capital were $28 million in 2011 and $4 million in 2010.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Dividends on Common Stock.

Common Stock Dividends and Price Ranges


	2012						2011
Quarter:	Market Price per						Market Price per
	Share of Common				Dividends		Share of Common				Dividends
	Stock ⁽¹⁾				Declared		Stock ⁽¹⁾				Declared
	High		Low				High		Low
First	$	38.66	$	36.31	$	0.43	$	37.74	$	34.84	$	0.42
Second		38.86		35.66		0.43		38.71		35.47		0.42
Third		42.71		39.08		0.43		38.55		34.36		0.42
Fourth		43.56		39.02		0.43		39.25		34.28		0.42

Total					$	1.72					$	1.68

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

Convertible Senior Notes

In March 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. In 2012, holders of approximately $147 million of the Convertible Senior Notes outstanding converted their interests into approximately 4.3 million shares of Common Stock. The remaining $3 million of outstanding Convertible Senior Notes were redeemed at par for cash. See Item 7.- Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Convertible Senior Notes, below, for more information.

Issuer Purchases of Common Equity

UNS Energy did not purchase any shares of Common Stock during 2012, 2011, or 2010.

K-31

ITEM 6. – SELECTED CONSOLIDATED FINANCIAL DATA

UNS Energy


	2012			2011			2010			2009			2008
	- In Thousands - (Except per Share Data)
Summary of Operations⁽¹⁾
Operating Revenues	$	1,461,766		$	1,478,702		$	1,425,947		$	1,396,606		$	1,410,407

Net Income	$	90,919		$	109,975		$	112,984		$	105,901		$	16,955

Basic Earnings per Share:
Net Income	$	2.25		$	2.98		$	3.10		$	2.95		$	0.47

Diluted Earnings per Share:
Net Income	$	2.20		$	2.75		$	2.86		$	2.73		$	0.53

Shares of Common Stock Outstanding:
Weighted Average		40,362			36,962			36,415			35,858			35,632
End of Year		41,344			36,918			36,542			35,851			35,458

Year-end Book Value per Share	$	25.77		$	24.07		$	22.73		$	21.18		$	19.35
Cash Dividends Declared per Share	$	1.72		$	1.68		$	1.56		$	1.16		$	0.96

Financial Position
Total Utility Plant – Net	$	3,300,363		$	3,182,263		$	2,961,498		$	2,785,714		$	2,617,693
Total Investments in Lease Debt and Equity	$	45,457		$	65,829		$	103,844		$	132,168		$	126,672
Other Investments and Other Property	$	36,537		$	34,205		$	61,676		$	60,239		$	64,096
Total Assets	$	4,140,429		$	3,989,279		$	3,796,246		$	3,615,211		$	3,510,608

Long-Term Debt	$	1,498,442		$	1,517,373		$	1,352,977		$	1,307,795		$	1,313,615
Non-Current Capital Lease Obligations		262,138			352,720			429,074			488,349			513,517
Common Stock Equity		1,065,465			888,474			830,756			759,329			686,090

Total Capitalization	$	2,826,045		$	2,758,567		$	2,612,807		$	2,555,473		$	2,513,222

Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	348,109		$	337,320		$	346,920		$	347,310		$	273,767

Capital Expenditures	$	(307,277	)	$	(374,122	)	$	(330,629	)	$	(294,020	)	$	(354,080	)
Other Investing Cash Flows ⁽²⁾		44,378			47,034			25,569			(2,624	)		(95,493	)

Net Cash Flows From Investing Activities	$	(262,899	)	$	(327,088	)	$	(305,060	)	$	(296,644	)	$	(449,573	)

Net Cash Flows From Financing Activities	$	(37,682	)	$	(1,441	)	$	(51,183	)	$	(28,916	)	$	140,605

Ratio of Earnings to Fixed Charges ⁽³⁾		2.32			2.46			2.64			2.48			1.28

K-32

TEP


	2012			2011			2010			2009			2008
	-Thousands of Dollars-
Summary of Operations
Operating Revenues	$	1,161,660		$	1,156,386		$	1,125,267		$	1,099,338		$	1,092,148
Net Income	$	65,470		$	85,334		$	108,260		$	90,688		$	7,206

Financial Position
Total Utility Plant – Net	$	2,750,421		$	2,650,652		$	2,410,077		$	2,261,325		$	2,120,619
Total Investments in Lease Debt and Equity		45,457			65,829			103,844			132,168			126,672
Other Investments and Other Property		35,091			32,313			43,588			31,813			31,291
Total Assets	$	3,461,046		$	3,277,661		$	3,078,411		$	2,924,108		$	2,852,195

Long-Term Debt	$	1,223,442		$	1,080,373		$	1,003,615		$	903,615		$	903,615
Non-Current Capital Lease Obligations		262,138			352,720			429,074			488,311			513,370
Common Stock Equity		860,927			824,943			709,884			650,591			589,613

Total Capitalization	$	2,346,507		$	2,258,036		$	2,142,573		$	2,042,517		$	2,006,598

Selected Cash Flow Data
Net Cash Flows From Operating Activities	$	267,919		$	268,294		$	302,483		$	268,064		$	265,756

Capital Expenditures	$	(252,782	)	$	(351,890	)	$	(277,309	)	$	(240,079	)	$	(291,990	)
Other Investing Cash Flows ⁽²⁾		24,901			39,879			24,273			(9,522	)		(95,814	)

Net Cash Flows From Investing Activities	$	(227,881	)	$	(312,011	)	$	(253,036	)	$	(249,601	)	$	(387,804	)

Net Cash Flows From Financing Activities	$	11,987		$	51,452		$	(51,882	)	$	(29,320	)	$	128,713

Ratio of Earnings to Fixed Charges ⁽³⁾		2.12			2.42			2.76			2.58			1.18

⁽¹⁾	See Note 1 for revisions to prior period financial statements.

⁽²⁾	Other Investing Cash Flows in 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds.

⁽³⁾

For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount, interest on operating lease payments, and expense on indebtedness.

See Item 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 UNS Energy and its three primary business segments and includes the following:

•

outlook and strategies;

•

operating results during 2012 compared with 2011, and 2011 compared with 2010;

•

factors which affect our results and outlook;

•

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

•

dividends; and

•

critical accounting policies.

UNS Energy is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS 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 UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of December 31, 2012. TEP generates, transmits and distributes electricity to approximately 406,000 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 Generating Station (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 149,000 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 92,000 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 UNS Energy’s consolidated financial statements.

Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2012.

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

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

UNS ENERGY CONSOLIDATED

OUTLOOK AND STRATEGIES

Our financial prospects and outlook are affected by many factors including: the outcome of TEP’s pending rate proceeding before the ACC; national, regional, and local 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, and maintaining a strong community presence.

•

Strengthening the underlying financial condition of our utility subsidiaries by achieving constructive regulatory outcomes, evaluating our capital structure, improving our credit ratings, and promoting economic development in our service territories.

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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 protect the financial stability of our utility businesses.

•

Developing a long-term diversification strategy for our generating portfolio. We are evaluating several energy resource options including coal, natural gas, and renewable generating resources. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.

•

Expanding TEP’s and UNS Electric’s portfolio of renewable energy resources and programs to meet Arizona’s Renewable Energy Standard (RES) 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.


	2012		2011			2010
	-Millions of Dollars-
TEP	$	65	$	85		$	108
UNS Gas		9		10			9
UNS Electric		17		18			15
Other Non-Reportable Segments and Adjustments⁽¹⁾		—		(3	)		(19	)

Consolidated Net Income	$	91	$	110		$	113

⁽¹⁾	Includes: UNS Energy parent company expenses, Millennium, and UED.

Revision for Prior Period Financial Statements

In the fourth quarter of 2012, we identified that we had incorrectly reported UNS Electric’s sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis during the first three quarters of 2012, as well as the calendar years 2011 and 2010. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $31 million in 2011, and $28 million in 2010. This error had no impact to operating income, net income, retained earnings, or cash flows. We assessed the impact of these errors on prior period financial statements and concluded they were not material to any period. However, the errors were significant to the individual line items. As a result, in accordance with Staff Accounting Bulletin 108, we have revised the 2011 and 2010 financial statements included herein to correct these errors. See Note 1.

Executive Overview

2012 Compared with 2011

TEP

TEP reported net income of $65 million in 2012 compared with $85 million in 2011. The decrease in net income was due primarily to: a decrease in retail kWh sales and margin revenues due in part to fewer Cooling Degree Days during the summer months compared with 2011, as well as the effects of the ACC’s energy efficiency and distributed generation requirements; a decrease in long-term wholesale margin revenues related to a change in the price of energy sold under TEP’s largest wholesale sales contract; higher depreciation and amortization expense due to an increase in plant-in-service; and a partial write-off of transmission-related assets. These factors were partially offset by a decrease in TEP’s Base O&M, resulting primarily from fewer planned generating plant outages. Net income in 2011 included the recognition of a gain related to the settlement of a dispute with El Paso Electric. See Tucson Electric Power, Results of Operations, below, for more information.

UNS Gas and UNS Electric

UNS Gas reported net income of $9 million in 2012 compared with net income of $10 million in 2011. See UNS Gas, Results of Operations, below, for more information.

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UNS Electric reported net income of $17 million in 2012 compared with net income of $18 million in 2011. See UNS Electric, Results of Operations, below, for more information.

Other Non-Reportable Segments

Millennium’s financial results are included in UNS Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in both 2012 and 2011. See Other Non-Reportable Segments, Results of Operations, below, for more information.

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 due to a change in the price of energy sold under TEP’s largest wholesale sales contract; a decrease in wholesale transmission revenues due in part to a temporary increase in wholesale transmission revenues in 2010; an increase in Base O&M due in part to an increase in planned generating plant outages; higher depreciation expense related to an increase in plant-in-service; and an increase in interest expense. Those factors were partially offset by the recognition of a gain in 2011 related to the settlement of a dispute with El Paso Electric. See Tucson Electric Power, Results of Operations, below, for more information.

UNS Gas and UNS Electric

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

Other Non-Reportable Segments

Millennium’s financial results are included in UNS 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. See Other Non-Reportable Segments, Results of Operations, below, for more information.

O&M

The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense.


	2012		2011		2010
	-Millions of Dollars-
UNS Energy Base O&M (non-GAAP)⁽¹⁾	$	266	$	271	$	265
Reimbursed Expenses Related to Springerville Units 3 & 4		72		63		65
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management Programs		46		45		40

Total UNS Energy O&M (GAAP)⁽²⁾	$	384	$	379	$	370

⁽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 generally accepted accounting principles (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 UNS Energy stand-alone O&M, and inter-company eliminations.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Dividends from UNS Energy’s subsidiaries represent the parent company’s primary source of liquidity. Under UNS Energy’s tax sharing agreement, subsidiaries make income tax payments to UNS Energy, which makes payments on behalf of the consolidated group to taxing authorities. See Income Tax Position, below, for more information.

The table below provides a summary of the liquidity position of UNS Energy and each of its segments:


Balances as of February 13, 2013	Cash and Cash Equivalents			Borrowings under Revolving Credit Facility⁽¹⁾		Amount Available under Revolving Credit Facility
	-Millions of Dollars-
UNS Energy Stand-Alone	$	1		$	45	$	80
TEP		44			31		169
UNS Gas		43			—		70	²⁾
UNS Electric		9			—		70	⁽²⁾
Other		4	⁽³⁾		N/A		N/A

Total	$	101

⁽¹⁾	Includes Letters of Credit (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

UNS 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, 2012, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the Balance Sheet.

Access to Revolving Credit Facilities

We 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 LOCs. TEP, UNS Gas, and UNS Electric each issue LOCs from time to time to provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs 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 support, as necessary, under energy procurement and hedging agreements. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

UNS Energy Consolidated Cash Flows


	2012			2011			2010
	-Millions of Dollars-
Operating Activities	$	348		$	337		$	347
Investing Activities		(263	)		(327	)		(305	)
Financing Activities		(38	)		(1	)		(51	)

UNS 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 energy. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer-peaking load. UNS 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.

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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 UNS Energy to its shareholders.

Operating Activities

In 2012, net cash flows from operating activities were $11 million higher than they were in 2011. The following items impacted the year-over-year change in operating cash flows: an increase in cash receipts from electric and gas sales, net of fuel and purchased energy costs, due in part to lower purchased power costs at TEP and UNS Electric, and the collection of under-recovered fuel and purchased energy costs at TEP and UNS Gas; and a decrease in capital lease interest paid due to lower capital lease obligation balances.

These increases in cash were partially offset by: a decrease in income tax refunds received due to overestimated payments made in 2010 and refunded in 2011; lower interest received due to lower balances in investments in lease debt; and an increase in property tax payments due to higher rates and property values.

Investing Activities

Net cash flows used for investing activities decreased by $64 million in 2012. Capital expenditures during 2012 were $307 million compared with $374 million in 2011. TEP’s capital expenditures in 2011 included $85 million related to construction of a new administrative headquarters.

Capital Expenditures Forecast


	Actual		Estimated
	2012		2013		2014		2015		2016		2017
	-Millions of Dollars-
TEP	$	253	$	323	$	296	$	331	$	287	$	278
UNS Gas		16		12		14		14		15		17
UNS Electric		38		58		29		34		31		38

UNS Energy Consolidated	$	307	$	393	$	339	$	379	$	333	$	333

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 2015.

TEP’s estimated capital expenditures include approximately $25 million for TEP’s share of potential environmental expenditures related to the installation of SNCR at San Juan Unit 1. TEP estimates its share of capital expenditures would be approximately $200 million if SCR technology were to be installed at San Juan Units 1 and 2 instead of SNCR at San Juan Unit 1. See Item. 1 Business, TEP, Environmental Matters, Regional Haze Rules, San Juan, for more information.

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, see Tucson Electric Power Company, Liquidity and Capital Resources, Investing Activities, Capital Expenditures, below.

Financing Activities

Net cash flows used for financing activities were $36 million higher in 2012 compared with 2011 due to a decrease in borrowings (net of repayments) under revolving credit facilities, an increase in scheduled payments on capital lease obligations, and an increase in Common Stock dividends paid due to an increased number of shares outstanding from the conversion of the Convertible Senior Notes. These cash outflows were partially offset by an increase in proceeds from the issuance of long-term debt (net of long-term debt repayments and issuance/retirement costs) at TEP.

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Capital Contributions

UNS Energy made no capital contributions to its subsidiaries in 2012.

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

In December 2011, UNS Energy contributed $30 million in capital to TEP to help fund the purchase of TEP’s headquarters building.

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

See Other Non-Reportable Business Segments, UED and Tucson Electric Power Company, Liquidity and Capital Resources, below, for more information.

UNS Credit Agreement

The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. As of December 31, 2012, there was $45 million outstanding at a weighted average interest rate of 1.96%.

The UNS Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UNS Credit Agreement also requires UNS Energy to meet a minimum cash flow to interest coverage ratio determined on a UNS Energy stand-alone basis. Additionally, UNS Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UNS Credit Agreement, UNS Energy may pay dividends so long as it maintains compliance with the agreement. UNS Energy’s obligations under the agreement are secured by a pledge of the common stock of Millennium, UES, and UED. As of December 31, 2012, we were in compliance with the terms of the UNS Credit Agreement.

Interest Rate Risk

UNS 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. UNS Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if the London Interbank Offered Rate (LIBOR) and other benchmark interest rates increase. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.

Convertible Senior Notes

In March 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. Between December 2011 and May 2012, UNS Energy issued a series of separate notices of partial redemption of the Convertible Senior Notes by calling all $150 million outstanding. Holders of the called Convertible Senior Notes had the option of converting their interests to Common Stock or receiving the redemption price of par plus accrued interest for the Convertible Senior Notes. The notes were convertible into shares of Common Stock at a conversion rate applicable at the time of each notice. During the first half of 2012, holders of approximately $147 million of the Convertible Senior Notes outstanding converted their interests into approximately 4.3 million shares of Common Stock. The remaining $3 million of outstanding Convertible Senior Notes were redeemed for cash.

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Contractual Obligations

The following chart displays UNS Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2012:


UNS Energy’s Contractual Obligations - Millions of Dollars -
Payment Due in Years Ending December 31,	2013		2014		2015		2016		2017		2018 and after		Other		Total
Long-Term Debt
Principal⁽¹⁾	$	—	$	37	$	130	$	223	$	—	$	1,109	$	—	$	1,499
Interest⁽²⁾		68		68		67		61		58		538		—		860
Capital Lease Obligations⁽³⁾		121		194		23		17		18		42		—		415
Operating Leases		2		2		2		1		1		10		—		18
Purchase Obligations:
Fuel⁽⁴⁾		91		78		58		53		43		77		—		400
Purchased Power⁽⁵⁾		105		91		43		34		33		466		—		772
Transmission		7		5		5		4		3		22		—		46
RES Performance-Based Incentives⁽⁶⁾		4		4		4		4		4		42		—		62

Solar Equipment⁽⁷⁾		12		—		—		—		—		—		—		12
Solar Project⁽⁸⁾		4		4		—		—		—		—		—		8
Service Agreement		2		2		—		—		—		—		—		4
Other Long-Term Liabilities⁽⁹⁾:
Pension & Other Post Retirement Obligations⁽¹⁰⁾		31		6		6		6		6		33		—		88
Acquisition of Springerville Coal Handling and Common Facilities⁽¹¹⁾		—		—		120		—		38		68		—		226

Unrecognized Tax Benefits		—		—		—		—		—		—		30		30

Total Contractual Cash Obligations	$	447	$	491	$	458	$	403	$	204	$	2,407	$	30	$	4,440

⁽¹⁾

TEP’s variable rate industrial development revenue or pollution control revenue bonds (IDBs) are secured by LOCs issued pursuant to the TEP Credit Agreement, which expires in 2016, and the 2010 TEP Reimbursement Agreement, which expires in 2014. Although the $215 million of variable rate IDBs mature between 2018 and 2032, the above maturity reflects a redemption or repurchase of such bonds as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement in 2016 (that supports $178 million of IDBs) and the 2010 TEP Reimbursement Agreement in 2014 (that supports $37 million of IDBs).

⁽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 Navajo, San Juan and Four Corners generating stations as the timing of payment has not been determined. See Note 4.

⁽⁵⁾

Purchased Power includes TEP’s six long-term Purchase Power Agreements (PPAs) and UNS Electric’s two long-term PPAs with renewable energy generation producers to meet compliance under the RES tariff. The facilities achieved commercial operation in 2011 and 2012. TEP and UNS Electric are 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 2032. TEP and UNS Electric have entered into additional long-term renewable PPAs to comply with the RES; however, TEP’s and UNS Electric’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.

⁽⁶⁾

TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance Based Incentives (PBIs) and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2.

⁽⁷⁾	TEP committed to purchase 9 MW of photovoltaic equipment through December 2013. The ACC approved this purchase under TEP’s RES Implementation Plan.

⁽⁸⁾

In December 2012, UNS Electric entered into an agreement for the construction of a 7.182 MW solar photovoltaic power plant that will be constructed in two phases. The first phase will result in a 4.2 MW plant that UNS Electric expects to be operational in June of 2013. The balance of the project will be completed in 2014. UNS Electric invested $5 million in this project in 2012. The contract requires additional investments of $4 million in each of 2013 and 2014. This is an approved project under UNS Electric’s RES implementation plan. See Note 2.

⁽⁹⁾	Excludes asset retirement obligations expected to occur through 2066.

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⁽¹⁰⁾

These obligations represent TEP’s and UES’ expected contributions to pension plans in 2013, TEP’s expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP) and TEP’s expected retiree 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 2013 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 retiree benefit plan on a pay-as-you-go basis. In 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA) Trust to partially fund expected future benefits for union employees. Disbursements from the VEBA Trust began in 2012. The 2013 obligation includes expected VEBA contributions. VEBA contributions for periods beyond 2013 cannot be determined at this time.

⁽¹¹⁾

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.

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


	2012		2011		2010
Quarterly Dividend Per Common Share	$	0.43	$	0.42	$	0.39
Annual Dividend Per Common Share	$	1.72	$	1.68	$	1.56
Common Stock Dividends Paid	$	70 million	$	62 million	$	57 million

Income Tax Position

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. The American Taxpayer Relief Act of 2012 extended 50% bonus depreciation for tax purposes on qualified property placed in service during 2013. This is an acceleration of tax benefits UNS Energy otherwise would have received over 20 years. As a result of these provisions, UNS Energy did not pay any federal income taxes for tax years 2011 and 2012, and does not expect to pay any federal income taxes through 2015. See Note 8 for additional information.

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 UNS Energy. The following discussion relates to TEP’s utility operations, unless otherwise noted.

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2012 Compared with 2011

TEP recorded net income of $65 million in 2012 compared with $85 million in 2011. The following factors contributed to the decrease in TEP’s net income:

•

a $7 million decline in retail margin revenues resulting from lower retail kWh sales due to milder summer weather than 2011, as well as the effects of the ACC’s energy efficiency and distributed generation requirements;

•

an $8 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 $3 million decrease in pre-tax income related to an unplanned outage at Springerville Unit 3;

•

a $7 million pre-tax gain recorded in 2011 related to the settlement of a dispute with El Paso Electric;

•

an $11 million increase in depreciation and amortization expense as a result of an increase in utility plant-in-service; and

•

a $5 million decrease in pre-tax income as a result of the write-off of a portion of the planned Tucson to Nogales transmission line;

partially offset by

•

a $4 million decrease in Base O&M primarily due to lower planned generating plant maintenance expense at San Juan.

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:

•

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;

•

a $10 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 utility 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.

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Utility Sales and Revenues

Customer growth, weather, economic conditions, energy efficiency, distributed generation, 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.


Energy Sales, kWh (in millions)	2012	2011	2012 vs. 2011 % Change*	2010	2011 vs. 2010 % Change*
Electric Retail Sales:
Residential	3,821	3,888	(1.7%)	3,870	0.5%
Commercial	1,974	1,973	0.1%	1,963	0.5%
Industrial	2,132	2,145	(0.6%)	2,139	0.3%
Mining	1,093	1,083	0.9%	1,079	0.3%
Public Authorities	245	243	0.9%	241	1.1%

Total Electric Retail Sales	9,265	9,332	(0.7%)	9,292	0.4%

Retail Margin Revenues (in millions):
Residential	$248	$252	(1.4%)	$252	0.2%
Commercial	160	160	0.1%	159	0.6%
Industrial	93	95	(2.5%)	97	(2.1%)
Mining	30	32	(3.8%)	31	1.9%
Public Authorities	13	12	2.4%	12	0.8%

Total Retail Margin Revenues (Non-GAAP)⁽¹⁾	$544	$551	(1.2%)	$551	0.0%
PPFAC Revenues	327	307	6.5%	279	9.6%
RES and DSM Revenues	45	46	(2.6%)	38	23.3%

Total Retail Revenues (GAAP)	$916	$904	1.3%	$868	4.1%

Avg. Retail Margin Revenue (cents / kWh):
Residential	6.50	6.48	0.3%	6.50	(0.3%)
Commercial	8.12	8.11	0.1%	8.10	0.1%
Industrial	4.33	4.42	(2.0%)	4.53	(2.4%)
Mining	2.78	2.92	(4.8%)	2.87	1.7%
Public Authorities	5.13	5.05	1.6%	5.07	(0.4%)

Avg. Retail Margin Revenue / kWh	5.87	5.90	(0.5%)	5.93	(0.5%)
Avg. PPFAC Revenue / kWh	3.52	3.29	7.0%	3.01	9.3%
Avg. RES & DSM Revenue / kWh	0.49	0.50	(2.0%)	0.41	22.0%

Total Avg. Retail Revenue / kWh	9.88	9.69	2.0%	9.35	3.7%

Cooling Degree Days
Actual	1,556	1,528	1.8%	1,543	(1.0%)
10-Year Average	1,484	1,473	NM	1,468	NM

Heating Degree Days
Actual	1,201	1,597	(24.8%)	1,469	8.7%
10-Year Average	1,394	1,417	NM	1,430	NM

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

⁽¹⁾

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 exclude: (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.

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Residential

In 2012, residential kWh sales decreased by 1.7% compared with 2011 due in part to a decrease in the number of Cooling Degree Days during the summer months of 2012 compared with 2011. Other factors affecting TEP’s 2012 retail sales volumes included the ACC’s Electric EE Standards and distributed generation requirements, as well as the pace of economic recovery. Residential margin revenues in 2012 decreased by $4 million when compared with 2011.

Commercial

Commercial kWh sales increased by 0.1% compared with 2011 due primarily to a 0.4% increase in the number of commercial customers. Commercial margin revenues increased by less than $1 million, or 0.1%, compared with 2011.

Industrial

Industrial kWh sales decreased by 0.6% in 2012 compared with 2011, while margin revenues declined by 2.5%. The decline in margin revenues 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 0.9% increase in sales volumes in 2012 compared with 2011. However, margin revenues from mining customers decreased by 3.8% compared with 2011, due to changing usage patterns which resulted in lower demand charges paid to TEP.

2011 Compared with 2010

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.

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.

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Wholesale Sales and Transmission Revenues


	2012		2011		2010
	-Millions of Dollars-
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)*	$	5	$	13	$	28
Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues		20		28		28

Total Long-Term Wholesale Revenues	$	25	$	41	$	56
Transmission Revenues		16		16		21
Short-Term Wholesale Revenues		70		73		64

Electric Wholesale Sales (GAAP)	$	111	$	130	$	141

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.

In 2012, long-term wholesale margin revenues from long-term wholesale contracts were $8 million lower than in 2011. The decrease was due primarily to a change in the pricing of energy sold under the SRP contract. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River Project, below, for more information.

Wholesale transmission revenues in 2012 were the same as 2011. Unlike 2012 and 2011, 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 Purchased Power and Fuel Adjustment Clause (PPFAC). There was no wholesale trading activity in 2010, 2011, and 2012.

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.

Other Revenues


	2012		2011		2010
	-Millions of Dollars-
Revenue related to Springerville Units 3 and 4⁽¹⁾	$	101	$	97	$	97
Other Revenue		33		26		22

Total Other Revenue	$	134	$	123	$	119

⁽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.

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Operating Expenses

2012 Compared with 2011

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for 2012, 2011, and 2010 are detailed below:


TEP	Generation and Purchased Power									Fuel and Purchased Power Expense
	2012			2011			2010			2012		2011			2010
	-Millions of kWh-									-Millions of Dollars-
Coal-Fired Generation		9,702			9,946			9,481		$	247	$	254		$	217
Gas-Fired Generation		1,435			929			1,078			65		55			60
Renewable Generation		45			28			25			—		—			—

Total Generation		11,182			10,903			10,584			312		309			277
Purchased Power		2,328			2,687			2,846			80		106			119
Reimbursed Fuel Expense		—			—			—			7		8			7
Transmission		—			—			—			6		(1	)		3
Increase (Decrease) to Reflect PPFAC Treatment		—			—			—			31		(6	)		(21	)

Total Resources		13,510			13,590			13,430		$	436	$	416		$	385

Less Line Losses and Company Use		(839	)		(786	)		(869	)

Total Energy Sold		12,671			12,804			12,561

Generation

Total generating output increased during 2012 compared with 2011. The higher output was due primarily to increased gas usage at Sundt Unit 4, a dual-fuel unit capable of using either coal or natural gas.

Purchased Power

Purchased power volumes decreased in 2012 compared with 2011. The lower volume of power purchases was primarily due to the increased usage of TEP’s gas-fired generating resources.

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


	2012		2011		2010
	-Cents Per kWh Generated-
Coal		2.54		2.56		2.29
Gas		4.54		5.99		5.58
Purchased Power		3.44		3.94		4.17
All Sources		3.19		3.30		3.24

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 2013. The table below shows the average wholesale market price for power and natural gas.

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Average Market Price for Around-the-Clock Energy (Dow Jones Palo Verde Index)	$/MWh
2012	$	26
2011	$	30
2010	$	34


Average Market Price for Natural Gas (Permian Basin)	$/MMBtu
2012	$	2.67
2011	$	3.89
2010	$	4.18

O&M

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


	2012			2011			2010
	-Millions of Dollars-
Base O&M (Non-GAAP)⁽¹⁾	$	234		$	238		$	228
O&M recorded in Other Expense		(6	)		(8	)		(7	)
Reimbursed expenses related to Springerville Units 3 and 4		72			63			65
Expenses related to customer funded renewable energy and DSM programs		35			38			31

Total O&M (GAAP)	$	335		$	331		$	317

⁽¹⁾

Base O&M, a non-GAAP financial measure, should not be considered as an alternative to 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 2012 was $4 million lower than 2011 primarily due to fewer scheduled generating plant outages.

Income Tax Expense

In 2012, TEP’s effective tax rate was 37% compared with 38% in 2011. See Note 8 for more information.

2011 Compared with 2010

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.

O&M

TEP’s Base O&M expense in 2011 was $238 million, or $10 million above 2010. The increase is due primarily to unplanned outages at San Juan in 2011.

K-47

FACTORS AFFECTING RESULTS OF OPERATIONS

2012 TEP Rate Case

In February 2013, TEP, ACC Staff, and other parties to TEP’s pending rate case proceeding entered into a settlement agreement (2013 Settlement Agreement). The 2013 Settlement Agreement requires the approval of the ACC before new rates can become effective.

The terms of the 2013 Settlement Agreement include, but are not limited to:

•

an increase in non-fuel retail Base Rates of approximately $76 million over adjusted test year revenues;

•

an Original Cost Rate Base (OCRB) of approximately $1.5 billion and a Fair Value Rate Base (FVRB) of approximately $2.3 billion;

•

a return on equity of 10.0%, a long-term cost of debt of 5.18%, and a short-term cost of debt of 1.42%, resulting in a weighted average cost of capital of 7.26%;

•

a 0.68% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million);

•

a capital structure of approximately 43.5% equity, 56.0% long-term debt, and 0.5% short-term debt; and

•

an agreement by TEP to seek recovery of costs related to the Nogales transmission line from the Federal Energy Regulatory Commission before seeking rate recovery from the ACC.

The 2013 Settlement Agreement also includes cost adjustment mechanisms, an energy efficiency resource plan and modifications to TEP’s PPFAC, which are described below.

Lost Fixed Cost Recovery Mechanism

A Lost Fixed Cost Recovery mechanism (LFCR) would allow TEP to recover certain non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to compliance with the ACC’s Electric EE Standards and distributed generation requirements under the RES. The LFCR rate would be adjusted annually and be subject to ACC approval and a year-over-year cap of 1% of TEP’s total retail revenues.

Environmental Compliance Adjustor

An Environmental Compliance Adjustor (ECA) mechanism would allow TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA would be adjusted annually to recover environmental compliances costs, subject to a cap equal to 0.25% of TEP’s total retail revenues.

Energy Efficiency Resource Plan

The Energy Efficiency Resource Plan (EERP) would allow TEP to invest in cost-effective energy efficiency programs approved by the ACC. Investments under the EERP would be considered regulatory assets and amortized over five-years. If certain thresholds are met as established in the EE implementation plans and approved by the ACC, TEP would recover its costs associated with the EERP, including a return on and a return of its investments, through TEP’s existing demand-side management surcharge.

Purchased Power and Fuel Adjustment Clause

A new PPFAC rate, which includes a one-time credit of approximately $3 million related to sulfur credits and a $9.7 million deferral of certain costs, will be effective at the same time new Base Rates are approved by the ACC. TEP’s existing PPFAC mechanism will continue with certain modifications, including the recovery of the following costs and/or credits: lime costs; sulfur credits; broker fees; and 100% of the proceeds from the sale of SO₂ allowances.

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Procedural Schedule

Hearings before the ACC administrative law judge assigned to TEP’s rate case proceeding are scheduled to begin on March 6, 2013. The judge will issue a recommended opinion and order following the conclusion of hearings. That recommendation is then subject to approval by the ACC.

The parties to the 2013 Settlement Agreement agreed to ask the ACC (1) to find that the terms and conditions of the 2013 Settlement Agreement are just and reasonable and in the public interest, along with any and all other necessary findings, and (2) to approve the 2013 Settlement Agreement such that it and the rates contained therein may become effective on July 1, 2013.

TEP cannot predict if the 2013 Settlement Agreement will be approved or modified by the ACC.

Purchased Power and Fuel Adjustment Clause

See Item 1. Business, TEP, Rates and Regulation, Purchased Power and Fuel Adjustment Clause.

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 Unit 4 on behalf of SRP.

In 2012, the annual impact to TEP’s pre-tax income resulting from operating Springerville Units 3 and 4 was approximately $21 million compared with $24 million in 2011. The decrease is related to an unplanned outage that occurred at Springerville Unit 3 in 2012. TEP recorded a pre-tax loss of $2 million in 2012 because the outage prevented TEP from meeting certain availability requirements under the terms of TEP’s operating agreement with Tri-State.

The table below summarizes the income statement line items in which TEP records revenues and expenses related to Springerville Units 3 and 4:


	2012			2011			2010
	-Millions of Dollars-
Other Revenues	$	101		$	97		$	97
Fuel Expense		(7	)		(8	)		(7	)
O&M		(72	)		(63	)		(65	)
Taxes Other Than Income Taxes		(1	)		(2	)		(1	)

Total Pre-Tax Income	$	21		$	24		$	24

Tucson to Nogales Transmission Line

See Item 1. Business, TEP, Transmission Access, Tucson to Nogales Transmission Line.

Pension and Retiree Benefit Expense

The table below summarizes TEP’s pension and other retiree benefit expenses charged to O&M in 2012, 2011, and 2010. See Note 9 for more information.


	2012		2011		2010
	-Millions of Dollars-
Pension Expense Charged to O&M	$	10	$	10	$	9
Other Retiree Benefit Expense Charged to O&M		5		4		4

Total	$	15	$	14	$	13

In 2013, TEP expects to charge $10 million of pension and $5 million of other retiree benefit expense to O&M.

K-49

Long-Term Wholesale Sales

TEP’s margin on long-term wholesale sales was $5 million in 2012 and $13 million in 2011. TEP’s two primary long-term wholesale contracts are with SRP and the Navajo Tribal Utility Authority (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 the Palo Verde Market Index. As of February 13, 2013, the average forward price of on-peak power on the Palo Verde Market Index for the calendar year 2013 was $36 per MWh. In 2012, the average on-peak price of power on the Palo Verde Market Index was approximately $29 per 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 2012, approximately 13% 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 see Item. 1 Business, TEP, Service Area and Customers, Wholesale Business.

Electric Energy Efficiency Standards

See Item 1. Business, TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling.

Renewable Energy Standard and Tariff

See Item 1. Business, TEP, Rates and Regulation, Renewable Energy Standard and Tariff.

Retail Electric Competition Rules

See Item 1. Business, TEP, Rates and Regulation, Retail Electric Competition Rules.

Competition

New technological developments and the implementation of Electric 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. See Item 1. Business, TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling for more information.

Sales to Mining Customers

Continued pricing of copper above $3 per pound triggered an increase in 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 2012, sales to TEP’s mining customers increased 0.9% compared with 2011 and represented 12% of TEP’s total retail kWh sales and 6% of total retail margin revenues.

K-50

In addition to the mining customers that TEP currently serves, Augusta Resources Corporation filed a plan of operations with the United States Forest Service in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona. The Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line for the construction and ongoing operation of the mine. A certificate of environmental compatibility (CEC) from the state line siting committee was approved in 2011 for the 138 kV transmission line. In 2012, the ACC finalized the CEC. If the Rosemont Copper Mine were to reach full production, it would be expected to become TEP’s largest retail customer, with TEP serving approximately 90 MW of the mine’s total estimated load of approximately 100 MW.

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

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, 2012, 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 20% on $178 million of bonds and 10% on the other $37 million. During 2012, the average rates paid ranged from 0.06% to 0.26%. At February 13, 2013, the average rate on the debt was 0.12%.

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.

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 accumulated other comprehensive income (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:


	2012			2011			2010
Net Cash Flows – Operating Activities (GAAP)	$	268		$	268		$	302
Amounts from Statements of Cash Flows:
Less: Capital Expenditures⁽¹⁾		(253	)		(352	)		(277	)

Net Cash Flows after Capital Expenditures (Non-GAAP)⁽²⁾		15			(84	)		25
Amounts From Statements of Cash Flows:
Less: Retirement of Capital Lease Obligations		(89	)		(74	)		(56	)
Plus: Proceeds from Investment in Lease Debt		19			38			26

Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)⁽²⁾	$	(55	)	$	(120	)	$	(5	)

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

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	2012			2011			2010
Net Cash Flows – Operating Activities (GAAP)	$	268		$	268		$	302
Net Cash Flows – Investing Activities (GAAP)		(228	)		(312	)		(253	)
Net Cash Flows – Financing Activities (GAAP)		12			51			(52	)
Net Cash Flows after Capital Expenditures (Non-GAAP)⁽²⁾		15			(84	)		25
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)⁽²⁾		(55	)		(120	)		(5	)

⁽²⁾

Net Cash Flows after Capital Expenditures and Net Cash Flows 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 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 UNS Energy.

Liquidity Outlook

During 2013, 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 2012, net cash flows from operating activities were the same when compared with 2011. Net operating cash flows in 2012 were impacted by: the collection of under-recovered fuel and purchased power costs; a decrease in purchased power costs due in part to lower market prices for power; lower O&M costs due in part to fewer scheduled outages at TEP’s generating facilities; a decrease in income tax refunds received due to overestimated payments made in 2010 and refunded in 2011; higher fuel costs paid due in part to an increase in coal inventory at Sundt Unit 4 and an increase in the output of gas-fired generating units; an increase in property tax payments due to higher rates and property values; and a decrease in interest received due to the declining balance of TEP’s investment in lease debt.

Investing Activities

Net cash flows used for investing activities decreased by $84 million in 2012 compared with 2011. A decrease in capital expenditures of $99 million was partially offset by a $19 million decrease in proceeds from the return of investment in Springerville lease debt.

Capital Expenditures

TEP’s forecasted capital expenditures are summarized below:


	2013		2014		2015		2016		2017
	-Millions of Dollars-
Transmission and Distribution	$	156	$	116	$	161	$	108	$	89
Generation Facilities		88		83		68		56		82
Renewable Energy Generation		35		36		35		36		36
Environmental		5		23		35		50		38
General and Other		39		38		32		37		33

Total	$	323	$	296	$	331	$	287	$	278

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 2015. See Capital Lease Obligations, below, for more information.

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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.

Financing Activities

In 2012, net cash from financing activities was $39 million lower than in 2011 due to: higher dividends paid to, and lower capital contributions from, UNS Energy; lower borrowings (net of repayments) made under TEP’s Revolving Credit Facility; and an increase in scheduled payments on TEP’s capital lease obligations. These cash outflows were partially offset by an increase in proceeds from the issuance of long-term debt (net of repayments).

TEP Credit Agreement

The TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $186 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016 and is secured by $386 million of Mortgage Bonds. As of December 31, 2012, there were no outstanding borrowings and less than $1 million of LOCs issued under the TEP Revolving Credit Facility.

In 2011, TEP reduced its LOC 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. See 2011 Bond Issuances, Purchase and Redemptions, below.

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 UNS Energy. As of December 31, 2012, TEP was in compliance with the terms of the TEP Credit Agreement.

2010 TEP Reimbursement Agreement

In 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt pollution control bonds that were issued on behalf of TEP in 2010.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of December 31, 2012, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

Capital Contribution from UNS Energy

In 2011, UNS Energy contributed $30 million of capital to TEP. TEP used the proceeds to partially fund the purchase of its headquarters building.

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

2012 Bond Issuances and Redemptions

In March 2012, $177 million of unsecured tax-exempt pollution control bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in March 2030 and may be redeemed at par on or after March 1, 2022. In April 2012, the proceeds of the bond issuance, as well as $7 million of internal cash, were used to redeem $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 6.

In June 2012, approximately $16 million of unsecured tax-exempt IDBs were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in June 2030 and may be redeemed at par on or after June 1, 2022.

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In July 2012, the proceeds of the bond issuance were used to redeem approximately $16 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 6.

In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the revolving credit facility, with the remaining proceeds used for general corporate purposes. See Note 6.

2011 Bond Issuances, Purchases, and Redemptions

In November 2011, TEP issued $250 million of 5.15% Notes due November 2021. TEP may call the debt anytime before August 15, 2021, with a make-whole premium plus accrued interest. After August 15, 2021, the debt is callable at par plus accrued interest. TEP used the net proceeds from the sale to: repurchase $150 million of variable rate bonds; redeem $22 million of 6.1% fixed rate bonds; and repay $78 million of outstanding revolving credit facility balances.

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. See Note 6.

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 $130 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 and of interest on the tax-exempt bonds to be paid when due. Of the $824 million of tax-exempt bonds outstanding as of December 31, 2012, $609 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 LOCs, with TEP being required to reimburse the LOC banks for drawings on the LOCs. See TEP Credit Agreement and TEP Reimbursement Agreement for 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 a percentage of net utility property additions and/or 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, 2012, 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, 2012, TEP had $353 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:


Leases	Capital Lease Obligation Balance		Expiration	Renewal/Purchase Option
	-Millions of Dollars-
Springerville Unit 1⁽¹⁾	$	197	2015	Fair market value purchase option of $159 million⁽²⁾
Springerville Coal Handling Facilities		48	2015	Fixed price purchase option of $120 million⁽³⁾
Springerville Common Facilities⁽³⁾		108	2017 and 2021	Fixed price purchase option of $106 million⁽⁴⁾

Total Capital Lease Obligations	$	353

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

⁽²⁾	See Item 3. – Legal Proceedings, Springerville Unit 1 Appraisal for information on a dispute related to the purchase option.

⁽³⁾

TEP agreed with Tri-State, the lessee 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.

⁽⁴⁾	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.

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Contractual Obligations

The following chart displays TEP’s contractual obligations as of December 31, 2012 by maturity and by type of obligation:



TEP’s Contractual Obligations - Millions of Dollars -
Payment Due in Years Ending December 31,	2013		2014		2015		2016		2017		2018 and after		Other		Total
Long-Term Debt
Principal	$	—	$	37	$	—	$	178	$	—	$	1,009	$	—	$	1,224
Interest		55		55		54		54		51		493		—		762
Capital Lease Obligations		121		194		23		17		18		42		—		415
Operating Leases		2		2		2		1		1		10		—		18
Purchase Obligations:
Fuel (including Transportation)		65		65		50		47		39		60		—		326
Purchased Power		50		41		29		28		28		386		—		562
Transmission		3		3		3		3		3		22		—		37
RES Performance-Based Incentives		4		4		4		4		4		42				62
Solar Equipment		12		—		—		—		—		—		—		12
Service Agreement		2		2		—		—		—		—		—		4
Other Long-Term Liabilities:
Pension & Other Post- Retirement Obligations		29		6		6		6		6		33		—		86
Acquisition of Springerville Coal Handling and Common Facilities		—		—		120		—		38		68		—		226
Unrecognized Tax Benefits		—		—		—		—		—		—		23		23

Total Contractual Cash Obligations	$	343	$	409	$	291	$	338	$	188	$	2,165	$	23	$	3,757

See UNS 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 LOCs 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, 2012, TEP was in compliance with these covenants. See TEP Credit Agreement, above.

•

TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC 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, 2012, TEP had posted less than $1 million in LOCs as collateral with counterparties for credit enhancement.

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Dividends on Common Stock

TEP paid $30 million of dividends to UNS Energy in 2012. TEP did not pay any dividends to UNS Energy in 2011. TEP paid $60 million of dividends to UNS Energy in 2010.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement, and certain financial covenants. As of December 31, 2012, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement.

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported net income of $9 million in 2012, $10 million in 2011, and $9 million in 2010. 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:


	2012		2011		2010
	-Millions of Dollars-
Gas Revenues	$	128	$	148	$	146
Other Revenues		5		3		4

Total Operating Revenues		133		151		150

Purchased Gas Expense		74		90		91
O&M		25		25		26
Depreciation and Amortization		9		8		8
Taxes Other Than Income Taxes		4		4		3

Total Other Operating Expenses		112		127		128

Operating Income		21		24		22
Interest Expense		6		7		7
Income Tax Expense		6		7		6

Net Income	$	9	$	10	$	9

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The table below shows UNS Gas’ therm sales and revenues:


					Increase (Decrease)
	2012		2011		Amount			Percent(1)			2010
Energy Sales, Therms (in millions):
Gas Retail Sales:
Residential		67		74		(7	)		(9.1	%)		73
Commercial		29		31		(2	)		(5.7	%)		30
Industrial		2		2		—			(15.1	%)		2
Public Authorities		6		7		(1	)		(13.0	%)		7

Total Gas Retail Sales		104		114		(10	)		(8.5	%)		112
Negotiated Sales Program (NSP)		32		26		6			21.2	%		28

Total Gas Sales		136		140		(4	)		(3.02	%)		140

Gas Revenues (in millions):
Retail Margin Revenues:
Residential	$	38	$	40	$	(2	)		(3.5	%)	$	39
Commercial		11		11		—			0.9	%		10
Public Authorities		2		2		—			(4.5	%)		2

Total Retail Margin Revenues (Non-GAAP)⁽²⁾		51		53		(2	)		(2.7	%)		51
Transport and NSP		16		17		(1	)		(4.2	%)		17
DSM		1		1		—			—	%		1
Retail Fuel Revenues		60		77		(17	)		(22.5	%)		77

Total Gas Revenues (GAAP)	$	128	$	148	$	(20	)		(13.2	%)	$	146

Weather Data:
Heating Degree Days
Year Ended December 31,		19,026		21,484		(2,458	)		(11.4	%)		21,188
10-Year Average		20,567		20,759		NM			NM			20,704

⁽¹⁾	Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

⁽²⁾

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 2012 decreased by 8.5% compared with 2011 due in part to an 11.4% decrease in Heating Degree Days. Retail margin revenues decreased by 2.7%, or $2 million. UNS Gas had approximately 149,000 retail customers, which represents an increase of less than 1% compared with the end of 2011.

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 Purchase Gas Adjustor (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. See Item 1. Business, UNS Gas, Rates and Regulation, Gas Energy Efficiency Standards and Decoupling, above, for more information.

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Rates

2012 UNS Gas Rate Order

In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a LFCR mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the Gas EE Standards. The LFCR is expected to recover lost fixed cost revenues of less than $0.1 million in 2013, based on estimated lost retail therm sales from May through December 2012.

The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills is offset by a temporary credit adjustment to the PGA. See Item 1. Business, UNS Gas, Rates and Regulation, Purchased Gas Adjustor.

Purchased Gas Adjustor

See Item 1. Business, UNS Gas, Rates and Regulation, Purchased Gas Adjustor.

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. See Item 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 2012, capital expenditures were $16 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 UNS Energy.

Operating Cash Flow

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


	2012			2011			2010
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	28		$	32		$	18
Investing Activities		(15	)		(12	)		(9	)
Financing Activities		(20	)		(11	)		(11	)

Net Increase (Decrease) in Cash		(7	)		9			(2	)
Beginning Cash		38			29			31

Ending Cash	$	31		$	38		$	29

Operating Activities

Operating cash flows decreased by $4 million in 2012 when compared with 2011 due in part to a $4 million decrease in total gas revenues.

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Investing Activities

UNS Gas incurred capital expenditures of $16 million in 2012 compared with $13 million in 2011.

Financing Activities

Cash used for financing activities at UNS Gas was $9 million higher in 2012 than in 2011 due in part to an increase of $10 million in dividends paid to UNS Energy.

UNS Gas/UNS Electric Revolver

The UNS Gas/UNS Electric 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 UNS Gas/UNS Electric Revolver expires in 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. 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 LOCs to provide credit enhancement for its natural gas procurement and hedging activities. As of December 31, 2012, UNS Gas had no outstanding borrowings or LOCs under the UNS Gas/UNS Electric Revolver.

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, 2012, UNS Gas and UNS Electric each were in compliance with the terms of 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, 2012, 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 2013 and 2024. 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 55% of its expected monthly consumption for the 2012/2013 winter season (November through March). Additionally, UNS Gas has approximately 37% of its expected gas consumption hedged for April through October 2013, and 30% hedged for the 2013/2014 winter season.

K-60

The following table displays UNS Gas’ contractual obligations as of December 31, 2012 by maturity and by type of obligation:


	UNS Gas Contractual Obligations -Millions of Dollars-
Payment Due in Years Ending December 31,	2013		2014		2015		2016		2017		2018 and after		Other		Total
Long Term Debt
Principal	$	—	$	—	$	50	$	—	$	—	$	50	$	—	$	100
Interest		6		6		6		3		3		24		—		48
Purchase Obligations—Fuel		26		13		8		6		4		17		—		74
Pension & Other Postretirement Obligations		1		—		—		—		—		—		—		1

Total Contractual Cash Obligations	$	33	$	19	$	64	$	9	$	7	$	91	$	—	$	223

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, 2012, UNS Gas had not posted any such credit enhancements.

Dividends on Common Stock

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (i) no default or event of default exists and (ii) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Gas was in compliance with the terms of its note purchase agreement. See Senior Unsecured Notes, above.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric had net income of $17 million in 2012, compared with net income of $18 million in 2011.

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

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The table below provides summary financial information for UNS Electric:


	2012		2011		2010
	-Millions of Dollars-
Retail Electric Revenues	$	171	$	182	$	183
Wholesale Electric Revenues		17		6		2
Other Revenues		2		2		2

Total Operating Revenues		190		190		187
Fuel and Purchased Energy Expense		101		106		109
O&M		31		27		29
Depreciation and Amortization		18		17		16
Taxes Other Than Income Taxes		4		4		4

Total Other Operating Expenses		154		154		158

Operating Income		36		36		29
Other Income		—		—		3
Interest Expense		8		7		7
Income Tax Expense		11		11		10

Net Income	$	17	$	18	$	15

The table below summarizes UNS Electric’s kWh sales and margin revenues:


					Increase (Decrease)
	2012		2011		Amount			Percent⁽¹⁾			2010
Energy Sales, kWh (in millions)
Electric Retail Sales:
Residential		836		828		8			1.0	%		820
Commercial		614		602		12			2.0	%		606
Industrial		213		221		(8	)		(3.5	%)		219
Mining		91		200		(109	)		(54.8	%)		210
Public Authorities		2		2		—			(1.7	%)		2

Total Electric Retail Sales		1,756		1,853		(97	)		(5.3	%)		1,857

Electric Retail Revenues (in millions):
Retail Margin Revenues:
Residential	$	32	$	31	$	1			2.6	%	$	27
Commercial		29		29		—			—	%		27
Industrial		9		9		—			—	%		9
Mining		7		7		—			(1.5	%)		6
Public Authorities		—		—		—			(33.3	%)		—

Total Retail Margin Revenues (Non-GAAP)⁽²⁾	$	77	$	76	$	1			0.8	%	$	69
Retail Fuel Revenues		83		99		(16	)		(15.9	%)		105
DSM and RES Revenues		11		7		4			71.2	%		9

Total Retail Revenues (GAAP)	$	171	$	182	$	(11	)		(5.8	%)	$	183

Weather Data:
Cooling Degree Days
Year Ended December 31,		9,639		9,092		547			6.0	%		8,821
10-Year Average		9,052		8,994		NM			NM			9,031

⁽¹⁾	Percent change calculated on unrounded data and may not correspond exactly to data shown in table.

⁽²⁾

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.

K-62

In 2012, retail kWh sales decreased by 5.3% compared with 2011 due to a large customer generating a portion of its own electricity needs.

As of December 31, 2012, UNS Electric had approximately 92,000 retail customers, which was an increase of less than 1% compared with 2011.

Wholesale revenues increased by $11 million in 2012 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

2012 UNS Electric Rate Case

In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric’s 2010 Rate Order.

The key provisions of UNS Electric’s rate request include:

•

an increase in non-fuel retail Base Rates of $7.5 million, or 4.6%, over adjusted test year revenues;

•

an original cost rate base of approximately $217 million, which includes approximately $13 million of post test year adjustments for utility plant that is expected to be in service by June 30, 2013;

•

a capital structure of approximately 47% debt and 53% equity; and

•

a cost of long-term debt of 5.97% and return on equity of 10.50%.

Lost Fixed Cost Recovery Mechanism

UNS Electric proposed a LFCR mechanism that would allow UNS Electric to recover non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to compliance with the ACC’s Electric EE Standards and distributed generation requirements under the ACC’s RES. The LFCR is not a full decoupling mechanism and is not intended to recover lost fixed costs attributable to weather or economic conditions.

Transmission Cost Adjustment Mechanism

UNS Electric proposed a Transmission Cost Adjustment Mechanism (TCA) that would allow UNS Electric to recover, on a more timely basis, transmission costs associated with serving retail customers. UNS Electric’s proposed retail Base Rates include a transmission cost reflective of the current FERC rate. As the FERC rate changes, the TCA will result in a corresponding adjustment to the transmission component of retail Base Rates.

Energy Efficiency Resource Plan

UNS Electric proposed a three-year pilot program that would allow it to invest in energy efficiency programs in order to meet the ACC’s Electric EE Standards in the most cost-effective manner. Electric EE Standards investments would be considered regulatory assets and amortized over a four-year period. UNS Electric would earn a return on its investments and recover the return and amortization expense through the existing demand-side management surcharge.

UNS Electric requested new rates be effective no later than January 1, 2014. We cannot predict the outcome of this proceeding or whether UNS Electric’s rate request will be adopted by the ACC in whole or in part.

Competition

New technological developments and the implementation of Electric 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. See Item 1. Business, UNS Electric, Rates and Regulation, Energy Efficiency Standards and Decoupling, above, for more information.

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Rates

See Item 1. Business, UNS Electric, Rates and Regulation, 2010 UNS Electric Rate Order.

Large Customers

One of UNS Electric’s largest retail customers began generating a portion of its own electricity needs in 2011. Due to UNS Electric’s retail rate structure and the customer’s peak electric demand, the margin revenues from this customer in 2012 were near the same level as 2011. Another large retail customer shut down its operations in UNS Electric’s service territory. As a result of these two events, we estimate UNS Electric’s non-residential retail margin revenues will be approximately $4 million lower in 2013 than in 2012.

Renewable Energy Standard and Tariff

See Item 1. Business, UNS Electric, Rates and Regulation, 2010 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. See Item 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 2012, UNS Electric’s capital expenditures were $38 million. In 2011, UNS Electric had capital expenditures of $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 UNS Energy.

Operating Cash Flow

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


	2012			2011			2010
	-Millions of Dollars-
Cash Provided By (Used In):
Operating Activities	$	50		$	43		$	34
Investing Activities		(37	)		(93	)		(23	)
Financing Activities		(10	)		44			(10	)

Net Increase (Decrease) in Cash		3			(6	)		1
Beginning Cash		5			11			10

Ending Cash	$	8		$	5		$	11

Operating Activities

Cash provided by operating activities increased by $7 million in 2012 compared with 2011 due primarily to higher cash receipts from electric sales (net of fuel and purchased energy costs paid) partially offset by higher operations and maintenance costs.

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Investing Activities

UNS Electric had capital expenditures of $38 million in 2012 compared with $96 million in 2011. Capital expenditures in 2011 included $63 million related to the acquisition of BMGS from UED.

Financing Activities

Cash provided by financing activities at UNS Electric in 2012 decreased by $54 million compared with 2011. Financing activities in 2012 included $10 million in dividends paid to UNS Energy. Financing activities in 2011 included the following items related to the acquisition of BMGS: the issuance of $30 million of long-term debt; a $20 million equity investment from UNS Energy; and a $6 million payment to UED.

UNS Gas/UNS Electric Revolver

See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver, above, for a 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 LOCs to provide credit enhancement for its energy procurement and hedging activities. At December 31, 2012, UNS Electric had less than $1 million of outstanding LOCs 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 in 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, 2012, UNS Electric was in compliance with the terms of its note purchase agreement.

Under the 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 1.125%. 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 in August 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. As of December 31, 2012, 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.

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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, 2012, UNS Electric had posted less than $1 million of such credit enhancements in the form of LOCs.

UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. See Item 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, 2012 by maturity and by type of obligation:


	UNS Electric Contractual Obligations -Millions of Dollars-
Payment Due in Years Ending December 31,	2013		2014		2015		2016		2017		2018 and after		Other		Total
Long Term Debt:
Principal	$	—	$	—	$	80	$	—	$	—	$	50	$	—	$	130
Interest		7		7		7		4		4		21		—		50
Purchase Obligations:
Purchased Power		55		50		14		6		5		80		—		210
Transmission		4		2		2		1		—		—		—		9
Solar Project		4		4		—		—		—		—		—		8
Pension & Other Postretirement Obligations		1		—		—		—		—		—		—		1
Unrecognized Tax Benefits		—		—		—		—		—		—		6		6

Total Contractual Cash Obligations	$	71	$	63	$	103	$	11	$	9	$	151	$	6	$	414

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

Dividends on Common Stock

UNS Electric paid $10 million of dividends to UNS Energy in 2012. UNS Electric’s ability to pay future 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 (i) no default or event of default exists and (ii) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Electric was in compliance with the terms of its note purchase agreement. See Senior 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:


	2012			2011			2010
	- Millions of Dollars -
Millennium	$	2		$	2		$	(13	)
Other ⁽¹⁾		(2	)		(5	)		(6	)

Total Other Net Loss	$	—		$	(3	)	$	(19	)

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

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Millennium

Millennium’s net loss in 2010 resulted primarily from the write-off of deferred tax assets and impairment losses on certain investments.

UNS Energy Parent Company

UNS Energy parent company expenses in 2012, 2011, and 2010 primarily include interest expense (net of tax) related to the UNS Energy Convertible Senior Notes and the UNS Credit Agreement. During the first six months of 2012, UNS Energy converted or redeemed all $150 million of outstanding Convertible Senior Notes.

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. The FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for $63 million in July 2011.

UED did not pay any dividends to UNS Energy in 2012. In 2011, UED paid a $39 million dividend to UNS Energy, of which $28 million represented a return of capital. In 2010, UED paid a $9 million dividend to UNS Energy, of which $4 million represented a return of capital.

FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

At December 31, 2012, Millennium had assets of $7 million including a cash balance of $4 million.

In July 2011, Millennium sold a building for $3 million resulting in an after-tax gain of approximately $1 million.

Note Receivable

In 2009, Millennium sold an equity investment, receiving an upfront payment of $5 million in 2009 and a $15 million promissory note. Millennium received the remaining principal amount of $15 million in 2012.

Dividends on Common Stock

Millennium made $14 million in dividend payments to UNS Energy in 2012, $3 million in 2011, and $8 million in 2010. All of these dividends represented return of capital distributions.

CRITICAL ACCOUNTING POLICIES

The preparation of the financial statements in accordance with GAAP requires management to apply accounting policies and make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. UNS 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 UNS 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 customers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until the rates charged to retail customers are reduced. We evaluate regulatory assets each period and believe recovery is probable.

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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 in the income statement or in AOCI.

At December 31, 2012, regulatory liabilities net of regulatory assets totaled $50 million at TEP and $35 million at UNS Gas. Regulatory assets net of regulatory liabilities totaled $5 million at UNS Electric. 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 a long-lived tangible 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 a legal 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 the useful life of related tangible assets, or when applicable the terms of a lease subject to ARO requirements. 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 ground lease agreements with certain land owners for the installation of photovoltaic (PV) assets. The provisions of the PV ground leases require TEP to remove the PV facilities upon expiration of the leases. The ARO related to the PV assets is estimated to be approximately $9 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 $159 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 restorative clauses. TEP operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As such, there are no AROs for these assets. However, TEP has identified in its distribution equipment certain AROs for which the accrual amount is less than $1 million at December 31, 2012.

The total net present value of the ARO accrual was $14 million and reported in Deferred Credits and Other Liabilities—Other on the balance sheets at December 31, 2012.

Nevertheless, included in the revenue requirement underlying TEP’s retail electric service rates is a component of depreciation expense intended to enable TEP to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balance of $231 million at December 31, 2012 representing non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, was included in Deferred Credits and Other Liabilities, Regulatory Liabilities – Noncurrent on TEP’s balance sheet See Note 2 for details regarding net cost of removal for interim retirements.

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UNS Gas and UNS Electric

UNS Gas and UNS Electric have various transmission and distribution lines that operate under land leases and rights-of-way that contain end dates and restorative clauses. UNS Gas and UNS Electric operate their transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, UNS Gas and UNS Electric are not recognizing the cost of final removal of the transmission and distribution lines in the financial statements.

The net present value of AROs related to the Generation and PV assets of UNS Electric was included in the Deferred Credits and Other Liabilities, Other on UNS Energy’s consolidated balance sheet on December 31, 2012. Both UNS Electric and UNS Gas accrue the future costs of retiring assets, for which no legal obligation exist through their own rate recovery mechanisms. The total accumulated balance of $36 million including UNS Electric’s and UNS Gas’ non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, was reported in Deferred Credits and Other Liabilities, Regulatory Liabilities – Noncurrent on UNS Energy’s consolidated balance sheet on December 31, 2012. See Note 2.

Pension and Other Retiree Benefit Plan Assumptions

TEP, UNS Gas, and UNS Electric record plan assets, obligations, and expenses related to pension and other retiree 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 retiree plan obligations for TEP, UNS Gas, and UNS Electric.

TEP is required to recognize the underfunded status of its defined benefit pension and other retiree 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 retiree benefit obligation for other retiree 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 retiree obligations as a liability and a regulatory asset to reflect expected recovery of pension and other retiree obligations through the rates charged to retail customers.

At December 31, 2012, TEP discounted its future pension plan obligations at 4.1% and its other retiree plan obligations at a rate of 3.8%. The discount rate for future pension plan and other retiree 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 $12 million and the 2013 plan expense by $1 million. For TEP’s other retiree 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 $1 million.

TEP calculates the market-related value of pension plan assets using the fair value of the assets on the measurement date. TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7% at December 31, 2012. 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 2013 by $1 million.

TEP used a current year health care cost trend rate of 6.9% in valuing its retiree benefit obligation at December 31, 2012. 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 retiree benefit obligation by approximately $5 million and the related plan expense in 2013 by $1 million.

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In 2013, TEP will incur pension costs of approximately $14 million and other retiree benefit costs of approximately $6 million. TEP expects to charge approximately $15 million of these costs to O&M expense, $4 million to capital, and $1 million to Other Expense. TEP expects to make pension plan contributions of $22 million in 2013. In 2009, TEP established a VEBA trust to fund its other retiree benefit plan. In 2013, TEP expects to make benefit payments to retirees under the retiree benefit plan of approximately $4 million and contributions to the VEBA trust of $3 million.

UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 4.3% at December 31, 2012. For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2013 pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2013, of which less than $1 million will be capitalized. UNS Gas and UNS Electric expect to make combined pension plan contributions of $2 million in 2013.

UNS Gas and UNS Electric discounted their other retiree plan obligations using a rate of 3.8% at December 31, 2012. UNS Gas and UNS Electric will record retiree medical benefit expense and make benefit payments to retirees under the retiree benefit plan of less than $0.5 million in 2013.

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’s, UNS Gas’, and UNS Electric’s derivative instruments at December 31, 2012, 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 tied to LIBOR on the Springerville Common Facilities Lease. As of December 31, 2012, approximately $25 million of variable rate lease debt for the Springerville Common Facilities Lease had been hedged through an interest rate swap agreement through July 1, 2014, and $34 million had been hedged through January 2, 2020. In August 2009, TEP entered into a swap that had the effect of converting $50 million of variable-rate IDBs 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.

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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. See Item 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 our 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. We 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 O&M expense.

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 in the income statements. The ACC approves depreciation rates for all generation and distribution assets. Depreciation rates for such assets cannot be changed without ACC approval. For current approved ACC depreciation rates see Note 1. TEP and UNS Electric transmission assets are subject to 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, 2012, UNS 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 UNS 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 Financial Accounting Standards Board (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 and do not expect this pronouncement to have a material impact on our disclosures.

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The FASB issued authoritative guidance which amends the guidance for impairment testing of indefinite-lived intangible assets. An entity will have the option to perform qualitative analysis to determine whether an indefinite-lived intangible asset may be impaired. If the qualitative assessment does not result in likely impairment, an entity will not be required to perform the quantitative impairment test. We will be required to comply in the first quarter of 2013; however, we do not expect this pronouncement to have a material impact on our financial statements as our indefinite-lived intangible assets, RECs, are currently recoverable under the RES as we use RECs to comply with renewable resources requirements.

The FASB decided to require new disclosures on items reclassified from AOCI. Companies will be required to disclose, in a single location, amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. This information can be presented parenthetically on the face of the financial statements or in the footnotes. We plan to present this information in a footnote. We will be required to comply in the first quarter of 2013 and do not expect this decision to have a material impact on our financial statements.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UNS 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 UNS 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 UNS Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UNS 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 retiree 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, see Safe Harbor for Forward-Looking Statements, above.

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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 UNS Energy. To limit TEP, UNS Gas, and UNS Electric’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP, UNS Gas, and UNS Electric’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.

Interest Rate Risk

Long-Term Debt

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. TEP had $215 million at December 31, 2012 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 0.17% in 2012 and 0.18% in 2011. The average weekly interest rate ranged from 0.06% to 0.26% in 2012 and 0.05% to 0.34% during 2011. Although short-term interest rates have been relatively low and stable in 2012 and 2011, 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 $59 million of Springerville Common Facilities lease debt and $50 million of its variable rate IDBs. TEP also entered into the following transactions to change its mix of fixed and floating rate debt.

•

TEP issued $250 million of 5.15% fixed-rate unsecured notes in 2011, and used a portion of the proceeds to repurchase $150 million of variable rate IDBs to hold in treasury.

•

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

As a result of these transactions, TEP’s un-hedged variable rate debt comprised approximately 13% of its total long-term debt at December 31, 2012 and 15% at December 31, 2011.

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 cash flow hedges, to fair value in Other Comprehensive Income (Loss), TEP recorded the following net unrealized gains (losses):


	2012			2011			2010
	-In Millions-
Unrealized Gains (Losses)	$	(2	)	$	(5	)	$	(8	)

K-73

Revolving Credit Facilities

UNS 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. As a result, UNS 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

UNS Energy has a short-term investment policy which governs the investment of excess cash balances by UNS 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, 2012, UNS Energy’s short-term investments consisted of liquid, highly-rated money market funds and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the balance sheet.

TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $32 million at December 31, 2012, and $50 million at December 31, 2011. At December 31, 2012, the carrying value exceeded fair value by $13 million. No impairment was recorded as TEP expects to recover the full carrying value of its lease equity investment in future rates charged to retail customers. At December 31, 2011, the fair value exceeded the carrying value by $16 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 geographical 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.

K-74

TEP enters into forward contracts 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. TEP also 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

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


	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, 2012, 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, 2012.

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):


	2012		2011			2010
	-Millions of Dollars-
Unrealized Gains (Losses)	$	6	$	(2	)	$	4

K-75

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


	Unrealized Gain (Loss) of TEP’s Hedging Activities
	- Millions of Dollars -
Source of Fair Value at Dec. 31, 2012	Maturity 0 – 6 months			Maturity 6 – 12 months			Maturity over 1 yr.		Total Unrealized Gain (Loss)
Prices Actively Quoted	$	(2	)	$	(2	)	$	—	$	(4	)
Prices Based on Models and Other Valuation Methods		1			1			—		2

Total	$	(1	)	$	(1	)	$	—	$	(2	)

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%.


	- Millions of Dollars -
Change in Market Price As of December 31, 2012	10% Increase		10% Decrease
Non-Cash Flow Hedges
Forward Power Sales and Purchase Contracts	$	1	$	(1	)
Forward Gas Swaps and Collars Contracts		2		(2	)

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 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 was relieved of a $4 million obligation recognized under this contract in December 2010. TEP reversed a $4 million regulatory asset.

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, UNS 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.

K-76

As required by fair value accounting rules, for the year ended December 31, 2012, 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, 2012.

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):


	2012		2011		2010
	-Millions of Dollars-
Unrealized Gains (Losses)	$	6	$	1	$	(2	)

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

For UNS Electric’s forward power sales and purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $5 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 $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 45% of this aggregate summer exposure hedged for the summer of 2013. 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.

As required by fair value accounting rules, for the year ended December 31, 2012, 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, 2012.

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):


	2012		2011			2010
	-Millions of Dollars-
Unrealized Gains (Losses)	$	9	$	(1	)	$	(2	)

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

K-77

Credit Risk

UNS Energy is exposed to credit risk in its energy-related marketing activities related to potential non-performance 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 LOCs.

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. As of December 31, 2012, the combined credit exposure to TEP, UNS Gas, and UNS Electric from financial institution counterparties was approximately $3 million.

As of December 31, 2012, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $15 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit exposure, totaling approximately $3 million. TEP’s total exposure to non-investment grade counterparties was $3 million.

At December 31, 2012, TEP posted no cash collateral and less than $1 million in LOCs 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, 2012, UNS Gas had purchased under fixed price contracts approximately 30% of its expected consumption for the 2013/2014 winter season. At December 31, 2012, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts. As of December 31, 2012, UNS Gas had posted no cash collateral and no LOCs 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, 2012, UNS Electric had less than $1 million in credit exposure under such contracts. As of December 31, 2012, UNS Electric had posted less than $1 million in LOCs 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

UNS Energy—Management’s Report on Internal Controls Over Financial Reporting

UNS 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 UNS Energy’s internal control over financial reporting as of December 31, 2012. 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, 2012, UNS Energy’s internal control over financial reporting was effective.

K-78

The effectiveness of UNS Energy’s internal control over financial reporting as of December 31, 2012, 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

TEP’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 TEP’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the COSO Internal Control – Integrated Framework.

Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2012, TEP’s internal control over financial reporting was effective.

K-79

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

UNS 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 UNS Energy Corporation and its subsidiaries at December 31, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal 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 Control 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 26, 2013

K-80

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, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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 26, 2013

K-81

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2012			2011			2010
	- Thousands of Dollars -
	(Except Per Share Amounts)
Operating Revenues
Electric Retail Sales	$	1,087,279		$	1,085,822		$	1,051,002
Electric Wholesale Sales		125,414			132,346			123,943
California Power Exchange (CPX) Provision for Wholesale Refunds		—			—			(2,970	)
Gas Revenue		123,133			145,053			141,036
Other Revenues		125,940			115,481			112,936

Total Operating Revenues		1,461,766			1,478,702			1,425,947

Operating Expenses
Fuel		327,832			324,520			295,652
Purchased Energy		224,696			276,610			279,269
Transmission		14,540			7,334			10,945
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment		32,246			(4,932	)		(29,622	)

Total Fuel and Purchased Energy		599,314			603,532			556,244
Operations and Maintenance		383,689			379,220			370,037
Depreciation		141,303			133,832			128,215
Amortization		35,784			30,983			28,094
Taxes Other Than Income Taxes		49,881			49,428			46,243

Total Operating Expenses		1,209,971			1,196,995			1,128,833

Operating Income		251,795			281,707			297,114

Other Income (Deductions)
Interest Income		1,106			4,568			7,779
Other Income		7,085			8,288			11,038
Other Expense		(7,988	)		(5,279	)		(15,202	)

Total Other Income (Deductions)		203			7,577			3,615

Interest Expense
Long-Term Debt		71,909			73,217			65,020
Capital Leases		33,613			40,359			46,740
Other Interest Expense		1,983			2,535			1,651
Interest Capitalized		(2,153	)		(3,753	)		(2,587	)

Total Interest Expense		105,352			112,358			110,824

Income Before Income Taxes		146,646			176,926			189,905
Income Tax Expense		55,727			66,951			76,921

Net Income	$	90,919		$	109,975		$	112,984

Weighted-Average Shares of Common Stock Outstanding (000)
Basic		40,362			36,962			36,415

Diluted		41,755			41,609			41,041

Earnings per Share
Basic	$	2.25		$	2.98		$	3.10

Diluted	$	2.20		$	2.75		$	2.86

Dividends Declared per Share	$	1.72		$	1.68		$	1.56

See Notes to Consolidated Financial Statements.

K-82

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Years Ended December 31,
	2012			2011			2010
	-Thousands of Dollars-
Comprehensive Income
Net Income	$	90,919		$	109,975		$	112,984

Other Comprehensive Income (Loss)

Unrealized Loss on Cash Flow Hedges, net of $1,119, $2,376, and $4,216 income taxes		(1,710	)		(3,626	)		(6,431	)

Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(1,862), $(1,412), and $(2,140) income taxes		2,844			2,153			3,264

SERP Benefit Adjustments, net of $608, $(804) and $523 income taxes		(840	)		1,158			(800	)

Total Other Comprehensive Income (Loss), Net of Income Taxes		294			(315	)		(3,967	)

Total Comprehensive Income	$	91,213		$	109,660		$	109,017

See Notes to Consolidated Financial Statements.

K-83

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2012			2011			2010
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,197,390		$	1,163,537		$	1,142,364
Cash Receipts from Electric Wholesale Sales		149,722			183,151			194,580
Cash Receipts from Gas Sales		141,590			159,529			157,397
Cash Receipts from Operating Springerville Units 3 & 4		107,927			104,754			102,563
Cash Receipts from Wholesale Gas Sales		5,233			12,404			422
Interest Received		2,947			6,334			10,026
Income Tax Refunds Received		1,821			4,672			341
Performance Deposits Received		200			7,050			18,470
Other Cash Receipts		24,105			23,937			32,011
Fuel Costs Paid		(321,355	)		(277,386	)		(243,639	)
Payment of Operations and Maintenance Costs		(291,512	)		(295,662	)		(259,833	)
Purchased Energy Costs Paid		(250,231	)		(328,713	)		(364,132	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(187,257	)		(179,766	)		(163,037	)
Wages Paid, Net of Amounts Capitalized		(127,176	)		(122,370	)		(125,893	)
Interest Paid, Net of Amounts Capitalized		(69,478	)		(68,027	)		(59,749	)
Capital Lease Interest Paid		(28,788	)		(32,103	)		(38,646	)
Wholesale Gas Costs Paid		—			(11,822	)		—
Performance Deposits Paid		(200	)		(4,550	)		(19,220	)
Income Taxes Paid		—			(700	)		(22,797	)
Other Cash Payments		(6,829	)		(6,949	)		(14,308	)

Net Cash Flows—Operating Activities		348,109			337,320			346,920

Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt		19,278			38,353			25,615
Proceeds from Note Receivable		15,000			—			—
Other Cash Receipts		22,094			15,251			12,958
Capital Expenditures		(307,277	)		(374,122	)		(279,240	)
Purchase of Intangibles—Renewable Energy Credits		(10,317	)		(5,992	)		(7,514	)
Deposit—San Juan Mine Reclamation Trust		(1,445	)		—			—
Purchase of Sundt Unit 4 Lease Asset		—			—			(51,389	)
Other Cash Payments		(232	)		(578	)		(5,490	)

Net Cash Flows—Investing Activities		(262,899	)		(327,088	)		(305,060	)

Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities		359,000			391,000			239,000
Proceeds from Issuance of Long-Term Debt		149,513			340,285			127,815
Proceeds from Stock Options Exercised		3,570			8,115			13,391
Other Cash Receipts		4,865			4,743			12,406
Repayments of Borrowings Under Revolving Credit Facilities		(381,000	)		(351,000	)		(268,500	)
Payments of Capital Lease Obligations		(89,452	)		(74,381	)		(55,997	)
Common Stock Dividends Paid		(69,648	)		(61,904	)		(56,590	)
Repayments of Long-Term Debt		(9,341	)		(252,125	)		(51,592	)
Payments of Debt Issue/Retirement Costs		(3,547	)		(4,361	)		(8,341	)
Other Cash Payments		(1,642	)		(1,813	)		(2,775	)

Net Cash Flows—Financing Activities		(37,682	)		(1,441	)		(51,183	)

Net Increase (Decrease) in Cash and Cash Equivalents		47,528			8,791			(9,323	)
Cash and Cash Equivalents, Beginning of Year		76,390			67,599			76,922

Cash and Cash Equivalents, End of Year	$	123,918		$	76,390		$	67,599

Non-Cash Financing Activity
Repayment of UED Short-Term Debt	$	—		$	—		$	(3,188	)

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-84

UNS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012			2011
	-Thousands of Dollars-
ASSETS
Utility Plant
Plant in Service	$	5,005,768		$	4,856,108
Utility Plant Under Capital Leases		582,669			582,669
Construction Work in Progress		128,621			89,749

Total Utility Plant		5,717,058			5,528,526
Less Accumulated Depreciation and Amortization		(1,921,733	)		(1,869,300	)
Less Accumulated Amortization of Capital Lease Assets		(494,962	)		(476,963	)

Total Utility Plant—Net		3,300,363			3,182,263

Investments and Other Property
Investments in Lease Debt and Equity		36,339			65,829
Other		36,537			34,205

Total Investments and Other Property		72,876			100,034

Current Assets
Cash and Cash Equivalents		123,918			76,390
Accounts Receivable—Customer		93,742			98,633
Unbilled Accounts Receivable		53,568			51,464
Allowance for Doubtful Accounts		(6,545	)		(5,572	)
Materials and Supplies		93,322			82,649
Fuel Inventory		62,019			33,263
Regulatory Assets—Current		51,619			97,056
Deferred Income Taxes—Current		34,260			23,158
Investments in Lease Debt		9,118			—
Derivative Instruments		3,165			11,966
Other		33,567			32,577

Total Current Assets		551,753			501,584

Regulatory and Other Assets
Regulatory Assets—Noncurrent		191,077			173,199
Other Assets		24,360			32,199

Total Regulatory and Other Assets		215,437			205,398

Total Assets	$	4,140,429		$	3,989,279

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-85

UNS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012		2011
	-Thousands of Dollars-
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,065,465	$	888,474
Capital Lease Obligations		262,138		352,720
Long-Term Debt		1,498,442		1,517,373

Total Capitalization		2,826,045		2,758,567

Current Liabilities
Current Obligations Under Capital Leases		90,583		77,482
Borrowing Under Revolving Credit Facilities		—		10,000
Accounts Payable—Trade		107,740		109,760
Accrued Taxes Other than Income Taxes		41,939		41,997
Interest Accrued		31,950		38,302
Accrued Employee Expenses		24,094		25,660
Regulatory Liabilities—Current		43,516		41,911
Customer Deposits		34,048		32,485
Derivative Instruments		14,742		36,467
Other		10,517		8,455

Total Current Liabilities		399,129		422,519

Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent		364,756		300,326
Regulatory Liabilities—Noncurrent		279,111		234,945
Pension and Other Retiree Benefits		159,401		139,356
Derivative Instruments		12,709		20,403
Other		99,278		113,163

Total Deferred Credits and Other Liabilities		915,255		808,193

Commitments, Contingencies, and Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	4,140,429	$	3,989,279

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-86

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31,

2012

2011

- Thousands of Dollars -

COMMON STOCK EQUITY

Common Stock-No Par Value

882,138

725,903

2012

2011

Shares Authorized

75,000,000

75,000,000

Shares Outstanding

41,343,851

36,918,024

Accumulated Earnings

193,117

172,655

Accumulated Other Comprehensive Loss

(9,790

)

(10,084

)

Total Common Stock Equity

1,065,465

888,474

PREFERRED STOCK

No Par Value, 1,000,000 Shares Authorized, None Outstanding

—

CAPITAL LEASE OBLIGATIONS

Springerville Unit 1

196,843

253,481

Springerville Coal Handling Facilities

48,038

65,022

Springerville Common Facilities

107,840

111,699

Total Capital Lease Obligations

352,721

430,202

Less Current Maturities

(90,583

)

(77,482

)

Total Long-Term Capital Lease Obligations

262,138

352,720

LONG-TERM DEBT

Issue

Maturity

Interest Rate

UNS Energy:

Convertible Senior Notes

2035

4.50%

—

150,000

Credit Agreement

2016

Variable

45,000

57,000

Tucson Electric Power Company:

Variable Rate Tax-Exempt Bonds

2014 – 2016

Variable

215,300

215,300

Unsecured Fixed Rate Bonds

2020 – 2040

4.50% – 6.38%

609,320

615,855

Unsecured Notes

2021 – 2023

3.85% – 5.15%

398,822

249,218

UNS Gas and UNS Electric:

Senior Unsecured Notes

2015 – 2026

5.39% – 7.10%

200,000

200,000

UNS Electric:

Unsecured Term Loan

2015

Variable

30,000

30,000

Total Long-Term Debt

1,498,442

1,517,373

Total Capitalization

2,826,045

2,758,567

See Notes to Consolidated Financial Statements.

K-87

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY


								Accumulated
	Common							Other			Total
	Shares		Common		Accumulated			Comprehensive			Stockholders’
	Outstanding*		Stock		Earnings			Loss			Equity
	- Thousands of Dollars -
Balances at December 31, 2009		35,851	$	696,206	$	68,925		$	(5,802	)	$	759,329

Comprehensive Income:
2010 Net Income						112,984						112,984
Other Comprehensive Loss, net of $2,599 income taxes									(3,967	)		(3,967	)

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 Performance Share Awards		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
Other Comprehensive Loss, net of $160 income taxes									(315	)		(315	)

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 Performance Share Awards		57		—								—
Other				2,040								2,040

Balances at December 31, 2011		36,918		725,903		172,655			(10,084	)		888,474

Comprehensive Income:
2012 Net Income						90,919						90,919

Other Comprehensive Income, net of $(135) income taxes									294			294

Total Comprehensive Income												91,213
Dividends, Including Non-Cash Dividend Equivalents						(70,457	)					(70,457	)
Shares Issued on Conversion of Notes and Related Tax
Effect		4,262		149,805								149,805
Shares Issued for Stock Options		133		3,511								3,511
Shares Issued Under Performance Share Awards		31		—								—
Other				2,919								2,919

Balances at December 31, 2012		41,344	$	882,138	$	193,117		$	(9,790	)	$	1,065,465

*	UNS 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-88

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2012			2011			2010
	- Thousands of Dollars -
Operating Revenues
Electric Retail Sales	$	915,879		$	903,930		$	868,188
Electric Wholesale Sales		111,194			129,861			141,103
California Power Exchange (CPX) Provision for Wholesale Refunds		—			—			(2,970	)
Other Revenues		134,587			122,595			118,946

Total Operating Revenues		1,161,660			1,156,386			1,125,267

Operating Expenses
Fuel		318,901			318,268			284,744
Purchased Power		80,137			105,766			118,716
Transmission		5,722			(1,435	)		3,254
Increase (Decrease) to Reflect PPFAC Recovery Treatment		31,113			(6,165	)		(21,541	)

Total Fuel and Purchased Energy		435,873			416,434			385,173
Operations and Maintenance		334,553			330,801			316,625
Depreciation		110,931			104,894			99,510
Amortization		39,493			34,650			32,196
Taxes Other Than Income Taxes		40,323			40,199			37,732

Total Operating Expenses		961,173			926,978			871,236

Operating Income		200,487			229,408			254,031

Other Income (Deductions)
Interest Income		136			3,567			6,707
Other Income		6,043			5,693			6,629
Other Expense		(13,772	)		(12,064	)		(11,506	)

Total Other Income (Deductions)		(7,593	)		(2,804	)		1,830

Interest Expense
Long-Term Debt		55,038			49,858			42,378
Capital Leases		33,613			40,358			46,734
Other Interest Expense		1,446			1,127			433
Interest Capitalized		(1,782	)		(2,073	)		(1,880	)

Total Interest Expense		88,315			89,270			87,665

Income Before Income Taxes		104,579			137,334			168,196
Income Tax Expense		39,109			52,000			59,936

Net Income	$	65,470		$	85,334		$	108,260

See Notes to Consolidated Financial Statements.

K-89

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Years Ended December 31,
	2012			2011			2010
	-Thousands of Dollars-
Comprehensive Income
Net Income	$	65,470		$	85,334		$	108,260

Other Comprehensive Income (Loss)

Unrealized Loss on Cash Flow Hedges, net of $913, $2,331, and $4,216 income taxes		(1,396	)		(3,555	)		(6,431	)

Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(1,800), $(1,390), and $(2,140) income taxes		2,750			2,122			3,264

SERP Benefit Adjustments, net of $608, $(804) and $523 income taxes		(840	)		1,158			(800	)

Total Other Comprehensive Income (Loss), Net of Income Taxes		514			(275	)		(3,967	)

Total Comprehensive Income	$	65,984		$	85,059		$	104,293

See Notes to Consolidated Financial Statements.

K-90

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2012			2011			2010
	- Thousands of Dollars -
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,006,926		$	963,247		$	947,498
Cash Receipts from Electric Wholesale Sales		124,594			152,618			190,779
Cash Receipts from Operating Springerville Units 3 & 4		107,927			104,754			102,563
Reimbursement of Affiliate Charges		20,926			18,448			18,356
Cash Receipts from Wholesale Gas Sales		4,652			11,825			—
Interest Received		2,025			5,367			8,998
Income Tax Refunds Received		493			7,492			3,369
Other Cash Receipts		18,850			19,611			23,429
Fuel Costs Paid		(313,742	)		(271,975	)		(232,591	)
Payment of Operations and Maintenance Costs		(282,752	)		(287,615	)		(248,895	)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized		(147,859	)		(139,728	)		(134,540	)
Wages Paid, Net of Amounts Capitalized		(104,955	)		(100,942	)		(101,815	)
Purchased Power Costs Paid		(81,328	)		(117,224	)		(169,658	)
Interest Paid, Net of Amounts Capitalized		(52,125	)		(45,433	)		(38,232	)
Capital Lease Interest Paid		(28,786	)		(32,103	)		(38,640	)
Income Taxes Paid		(1,796	)		(2,346	)		(19,663	)
Wholesale Gas Costs Paid		—			(11,822	)		—
Other Cash Payments		(5,131	)		(5,880	)		(8,475	)

Net Cash Flows—Operating Activities		267,919			268,294			302,483

Cash Flows from Investing Activities
Return of Investments in Springerville Lease Debt		19,278			38,353			25,615
Other Cash Receipts		15,957			7,195			8,044
Capital Expenditures		(252,782	)		(351,890	)		(225,920	)
Purchase of Intangibles—Renewable Energy Credits		(8,889	)		(5,111	)		(7,903	)
Deposit—San Juan Mine Reclamation Trust		(1,445	)		—			—
Purchase of Sundt Unit 4 Lease Asset		—			—			(51,389	)
Other Cash Payments		—			(558	)		(1,483	)

Net Cash Flows—Investing Activities		(227,881	)		(312,011	)		(253,036	)

Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility		189,000			220,000			177,000
Proceeds from Issuance of Long-Term Debt		149,513			260,285			118,245
Equity Investment from UNS Energy		—			30,000			15,000
Other Cash Receipts		3,132			2,458			3,241
Repayments of Borrowings Under Revolving Credit Facility		(199,000	)		(210,000	)		(212,000	)
Payments of Capital Lease Obligations		(89,452	)		(74,343	)		(55,889	)
Dividends Paid to UNS Energy		(30,000	)		—			(60,000	)
Repayments of Long-Term Debt		(6,535	)		(172,460	)		(30,000	)
Payments of Debt Issue/Retirement Costs		(3,547	)		(3,594	)		(5,988	)
Other Cash Payments		(1,124	)		(894	)		(1,491	)

Net Cash Flows—Financing Activities		11,987			51,452			(51,882	)

Net Increase (Decrease) in Cash and Cash Equivalents		52,025			7,735			(2,435	)
Cash and Cash Equivalents, Beginning of Year		27,718			19,983			22,418

Cash and Cash Equivalents, End of Year	$	79,743		$	27,718		$	19,983

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-91

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012			2011
	- Thousands of Dollars -
ASSETS
Utility Plant
Plant in Service	$	4,348,041		$	4,222,236
Utility Plant Under Capital Leases		582,669			582,669
Construction Work in Progress		98,460			76,517

Total Utility Plant		5,029,170			4,881,422
Less Accumulated Depreciation and Amortization		(1,783,787	)		(1,753,807	)
Less Accumulated Amortization of Capital Lease Assets		(494,962	)		(476,963	)

Total Utility Plant—Net		2,750,421			2,650,652


Investments and Other Property
Investments in Lease Debt and Equity		36,339			65,829
Other		35,091			32,313

Total Investments and Other Property		71,430			98,142

Current Assets
Cash and Cash Equivalents		79,743			27,718
Accounts Receivable—Customer		71,813			73,612
Unbilled Accounts Receivable		33,782			32,386
Allowance for Doubtful Accounts		(4,598	)		(3,766	)
Accounts Receivable—Due from Affiliates		5,720			4,049
Materials and Supplies		80,377			70,749
Fuel Inventory		61,737			32,981
Deferred Income Taxes—Current		37,212			21,678
Regulatory Assets—Current		34,345			71,747
Investments in Lease Debt		9,118			—
Other		34,393			15,192

Total Current Assets		443,642			346,346

Regulatory and Other Assets
Regulatory Assets—Noncurrent		178,330			157,386
Other Assets		17,223			25,135

Total Regulatory and Other Assets		195,553			182,521

Total Assets	$	3,461,046		$	3,277,661

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Continued)

K-92

TUCSON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012		2011
	- Thousands of Dollars -
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	860,927	$	824,943
Capital Lease Obligations		262,138		352,720
Long-Term Debt		1,223,442		1,080,373

Total Capitalization		2,346,507		2,258,036

Current Liabilities
Current Obligations Under Capital Leases		90,583		77,482
Borrowing Under Revolving Credit Facility		—		10,000
Accounts Payable—Trade		82,122		84,509
Accounts Payable—Due to Affiliates		3,134		4,827
Accrued Taxes Other than Income Taxes		33,060		32,155
Interest Accrued		26,965		30,877
Accrued Employee Expenses		20,715		22,099
Customer Deposits		24,846		23,743
Regulatory Liabilities—Current		20,822		23,702
Derivative Instruments		4,899		9,040
Other		7,085		5,957

Total Current Liabilities		314,231		324,391

Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent		319,216		263,225
Regulatory Liabilities—Noncurrent		241,189		200,599
Pension and Other Retiree Benefits		149,718		130,660
Derivative Instruments		10,565		14,142
Other		79,620		86,608

Total Deferred Credits and Other Liabilities		800,308		695,234

Commitments, Contingencies, and Environmental Matters (Note 4)
Total Capitalization and Other Liabilities	$	3,461,046	$	3,277,661

See Notes to Consolidated Financial Statements.

(Consolidated Balance Sheets Concluded)

K-93

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31,

2012

2011

- Thousands of Dollars -

COMMON STOCK EQUITY

Common Stock-No Par Value

888,971

888,971

2012

2011

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

(12,157

)

(47,627

)

Accumulated Other Comprehensive Loss

(9,530

)

(10,044

)

Total Common Stock Equity

860,927

824,943

PREFERRED STOCK

No Par Value, 1,000,000 Shares Authorized, None Outstanding

—

CAPITAL LEASE OBLIGATIONS

Springerville Unit 1

196,843

253,481

Springerville Coal Handling Facilities

48,038

65,022

Springerville Common Facilities

107,840

111,699

Total Capital Lease Obligations

352,721

430,202

Less Current Maturities

(90,583

)

(77,482

)

Total Long-Term Capital Lease Obligations

262,138

352,720

LONG-TERM DEBT

Issue

Maturity

Interest Rate

Variable Rate Tax-Exempt Bonds

2014 – 2016

Variable

215,300

215,300

Unsecured Fixed Rate Bonds

2020 – 2040

4.50% – 6.38%

609,320

615,855

Unsecured Notes

2021 – 2023

3.85% – 5.15%

398,822

249,218

Total Long-Term Debt

1,223,442

1,080,373

Total Capitalization

2,346,507

2,258,036

See Notes to Consolidated Financial Statements.

K-94

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY


									Accumulated
			Capital						Other			Total
	Common		Stock			Accumulated			Comprehensive			Stockholder’s
	Stock		Expense			Deficit			Loss			Equity
Balances at December 31, 2009	$	843,971	$	(6,357	)	$	(181,221	)	$	(5,802	)	$	650,591
Comprehensive Income:
2010 Net Income							108,260						108,260

Other Comprehensive Loss, net of $2,599 income taxes										(3,967	)		(3,967	)

Total Comprehensive Income													104,293
Capital Contribution from UNS 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

Other Comprehensive Loss, net of $137 income taxes										(275	)		(275	)

Total Comprehensive Income													85,059

Capital Contribution from UNS Energy		30,000											30,000

Balances at December 31, 2011		888,971		(6,357	)		(47,627	)		(10,044	)		824,943

Comprehensive Income:
2012 Net Income							65,470						65,470
Other Comprehensive Income, net of $(279) income taxes										514			514

Total Comprehensive Income													65,984

Dividends Paid							(30,000	)					(30,000	)

Balances at December 31, 2012	$	888,971	$	(6,357	)	$	(12,157	)	$	(9,530	)	$	860,927

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

See Notes to Consolidated Financial Statements.

K-95

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NATURE OF OPERATIONS

UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2012.

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

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

REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS

In the fourth quarter of 2012, we identified that we had incorrectly reported UNS Electric’s sales and purchase contracts, which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis during the first three quarters of 2012 as well as the calendar years 2011 and 2010. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $31 million in 2011 and $28 million in 2010. This error had no impact to operating income, net income, retained earnings, or cash flows. We assessed the impact of these errors on prior period financial statements and concluded they were not material to any period. However, the errors were significant to the individual line items. As a result, in accordance with Staff Accounting Bulletin 108, we have revised the 2011 and 2010 financial statements included herein to correct these errors. See Note 17 for the quarterly impact of the revisions on the years presented. The interim financial data is unaudited. The revisions noted above impacted UNS Energy’s statements of income as shown in the tables below:


	UNS Energy
	Year Ended				Year Ended
	December 31, 2011				December 31, 2010
	As Reported		As Revised		As Reported		As Revised
	-Thousands of Dollars-
Income Statement
Electric Wholesale Sales	$	163,159	$	132,346	$	151,962	$	123,943
Total Operating Revenues		1,509,515		1,478,702		1,453,966		1,425,947
Purchased Energy		307,423		276,610		307,288		279,269
Total Fuel and Purchased Energy		634,345		603,532		584,263		556,244
Total Operating Expenses		1,227,843		1,196,995		1,156,852		1,128,833

K-96

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	UNS Energy 2012 Three Months Ended
	March 31,				June 30,				September 30,
	As Reported		As Revised		As Reported		As Revised		As Reported		As Revised
	-Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	37,104	$	33,538	$	28,684	$	24,381	$	32,494	$	28,836
Purchased Energy		63,276		59,790		51,376		48,203		60,238		57,085
Total Fuel and Purchased Energy		134,276		130,790		151,328		148,155		175,687		172,534
Total Operating Expenses		284,479		280,984		299,112		295,932		330,852		327,700


	UNS Energy 2011 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
Income Statement
Electric Wholesale Sales	$	40,914	$	35,438	$	38,744	$	35,331	$	41,847	$	32,818	$	41,654	$	28,759
Purchased Energy		78,274		71,685		66,336		61,804		88,734		79,343		74,079		63,778
Total Fuel and Purchased Energy		146,579		139,990		155,539		151,007		182,766		173,376		149,461		139,159
Total Operating Expenses		299,946		293,357		298,383		293,852		327,187		317,796		302,327		291,990


	UNS Energy
	Six Month Period Ended								Nine Month Period Ended
	June 30, 2012				June 30, 2011				September 30, 2012				September 30, 2011
	As Reported		As Revised		As Reported		As Revised		As Reported		As Revised		As Reported		As Revised
	-Thousands of Dollars
Income Statement
Electric Wholesale Sales	$	65,787	$	57,919	$	79,658	$	70,769	$	98,282	$	86,755	$	121,506	$	103,587
Total Operating Revenues		686,044		679,384		714,439		703,318		1,123,305		1,113,492		1,165,387		1,144,875
Purchased Energy		114,653		107,993		144,610		133,489		174,891		165,078		233,344		212,832
Total Fuel and Purchased Energy		285,605		278,945		302,118		290,997		461,292		451,479		484,885		464,373
Total Operating Expenses		583,590		576,916		598,330		587,209		914,428		904,616		925,518		905,005
Operating Income⁽¹⁾		102,454		102,468		116,109		116,109		208,877		208,876		239,869		239,869

(1) Includes immaterial reclassifications from Operating Expense to Other Expense to conform with current year presentation.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board issued authoritative guidance that eliminated the option to report other comprehensive income in the statement of changes in equity. Rather, an entity must elect to present items of net income and other comprehensive income in one continuous statement or in two separate but consecutive statements. In 2012, we elected to include two separate but consecutive statements.

We implemented accounting guidance in 2012 which enhances our disclosures regarding unobservable inputs in calculating the fair market value of certain assets and liabilities. The guidance requires additional quantitative analysis of inputs when we use significant unobservable inputs to measure the fair value of our derivatives and financial instruments. See Note 11.

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 if recovery from ratepayers is probable. See Note 2.

K-97

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

USE OF ACCOUNTING ESTIMATES

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

•

Assets and liabilities on 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 results may differ from the estimates.

ACCOUNTING FOR RATE REGULATION

We generally use the same accounting policies and practices used by unregulated companies. However, sometimes GAAP 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 the rates charged to retail customers. Our Retail Rates are designed to allow TEP, UNS Gas, and UNS Electric an opportunity to recover reasonable operating and capital costs and earn a return on utility plant in service. 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 to current period earnings.

TEP, UNS Gas, and UNS Electric 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.

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.

As of December 31, 2012, we include $7 million of restricted cash in Investments and Other Property—Other on the balance sheets, of which $2 million has been legally restricted as to its use. At December 31, 2011, we included $9 million of restricted cash in Investments and Other Property – Other on the balance sheets, of which $3 million had been legally restricted as to its use.

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 (when applicable), and an Allowance for Funds Used During Construction (AFUDC).

We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statements as 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.

K-98

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 capitalized interest that relates to debt reduces Other Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.

The average AFUDC rates on regulated construction expenditures are included in the table below:


	2012			2011			2010
TEP		7.22	%		6.72	%		6.65	%
UNS Gas		7.95	%		8.32	%		8.19	%
UNS Electric		7.89	%		8.18	%		8.22	%

UNS Energy did not capitalize interest in 2012. UNS Energy capitalized interest at a rate of 3.30% for 2011 and 1.96% for 2010.

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 Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). 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 plant, which reflect immaterial adjustments in the calculation of rates in the years presented to exclude allocated depreciation (the adjustment did not affect Depreciation Expense recorded in the income statements).


	TEP			UNS Gas			UNS Electric
2012		3.22	%		2.69	%		3.99	%
2011		3.14	%		2.84	%		4.02	%
2010		3.16	%		2.83	%		4.35	%

Computer Software Costs

We capitalize costs incurred to purchase and develop internal use computer software 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 Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense—Capital Leases. The lease terms are described in Note 6.

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a one-half interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). 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 the equity holders.

TEP accounts for its equity interest in the Springerville Unit 1 Lease trust using the equity method.

K-99

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 based on our ownership percentage. See Note 5.

ASSET RETIREMENT OBLIGATIONS

TEP and UNS Electric record a liability for the estimated present value of a conditional Asset Retirement Obligation (ARO) 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 O&M expense, and the capitalized cost is depreciated in Depreciation and Amortization expense over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements.

Based on the decommissioning studies to estimate timing and amount of future retirement of certain generation assets, both TEP and UNS Electric record legal AROs for these assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases.

TEP and UNS Electric record cost of removal for generation assets that are recoverable through the rates charged to retail customers. See Note 2.

We record cost of removal for transmission and distribution assets through depreciation rates and recover those amounts in the rates charged to retail customers. There are no legal obligations associated with transmission and distribution 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 expected future cash flows (without discounting) 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.

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 usage by customer 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.

K-100

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The ACC authorized a rate-adjustment mechanism for TEP, UNS Gas, and UNS Electric 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 costs recovered through Retail Rates for any difference between the total amount collected under the mechanisms 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 compliance costs through a RES surcharge to customers. We charge customers a Demand Side Management (DSM) surcharge to recover the cost of ACC-approved Electric Energy Efficiency Programs (Electric EE Programs) or Gas Energy Efficiency Programs (Gas EE Programs). We defer differences between actual RES or DSM qualified costs incurred and the recovery of such costs from retail customers 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 typically 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 purchased power and wholesale sales contracts that are not settled with energy, TEP and UNS Electric net the sales contracts with the purchase power contracts and reflect 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/Power 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 earns and recognizes Other Revenues monthly as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Tri-State and SRP reimburse TEP for various operating expenses at Springerville, which are recorded in the respective line item of the income statements based on the nature of service or materials provided. 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.

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

TEP and UNS Electric record the actual fuel, transmission, and purchased power costs incurred on a monthly basis. Retail customers are billed monthly for the cost of fuel, transmission, and purchased power in Base Rates and via the current Purchased Power and Fuel Adjustment Clause (PPFAC) rate. The difference between the costs billed to customers (recoveries) and actual fuel costs incurred to provide retail electric service is deferred. Cost over-recoveries (excess of fuel cost recoveries) are deferred as regulatory liabilities and cost under-recoveries (excess of actual costs incurred over fuel costs recovered) are deferred as regulatory assets. See Note 2.

K-101

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Gas Purchased Gas Adjustor

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

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 purchases renewable energy, the premium paid above the market cost of conventional power is the REC cost and the remaining cost is recoverable through the PPFAC.

When RECs are purchased, TEP and UNS Electric record the cost of the unretired RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount, in the income statements. 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 for financial statement presentation purposes. 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 reduce deferred tax assets 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.

Tax benefits are recognized as reductions to Deferred Income Taxes – Noncurrent/Other Current Liabilities 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. Tax benefits taken on returns which do not meet these requirements are recorded in Deferred Income Taxes – Noncurrent/Other Liabilities – Noncurrent. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.

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 generated prior to 2012 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. Federal energy credits generated in 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated. 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.

K-102

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, on the balance sheet, 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 separate all derivatives into current and long-term portions on the balance sheet.

In 2010 through 2012, we did not engage in trading of derivative financial instruments.

Cash Flow Hedges

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements relating to the Springerville Unit 1 Leases and variable rate industrial development revenue or pollution control revenue bonds (IDBs). 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 effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed 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.

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.

K-103

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Subsequent Measurement at Fair Value

•

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 transactions subsequently measured at fair value. 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.

•

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 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 PPFAC mechanism allows recovery of the prudent costs of contracts for hedging fuel and purchased power costs.

Normal Purchases and Normal Sales

We enter into forward energy purchase and sales contracts, including call options, with counterparties for load serving requirements or counterparties with generating capacity to support our current load forecasts. These contracts are not required to be measured at fair value 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 purchases and normal sales scope exception.

PENSION AND OTHER RETIREE 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 (SERP) for upper management. TEP also provides limited health care and life insurance benefits for retirees. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) 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 the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers, 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 subject to IRS benefit or compensation limitations. Changes in SERP benefit obligations are recognized as a component of AOCI.

Pension and other retiree benefit expense are determined by actuarial valuations, based on assumptions that we evaluate annually. See Note 9.

K-104

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

RECLASSIFICATIONS

UNS Energy and TEP reclassified the following items in the 2011 and 2010 financial statements to be comparable to the presentation in the 2012 financial statements:

•

UNS Energy reclassified $4 million of 2011 trade receivables with credit balances from Accounts Receivable – Customer to Other Current Liabilities;

•

UNS Energy and TEP reclassified $4 million of 2011 and 2010 O&M costs paid from Fuel Costs Paid to Payment of Operations and Maintenance Costs in the statements of cash flows;

•

TEP reclassified $2 million of 2011 trade receivables with credit balances from Accounts Receivable – Customer to Other Current Liabilities;

•

UNS Energy and TEP reclassified $1 million of 2011 payroll withholding taxes from Other Current Liabilities to Accrued Employee Expenses; and

•

UNS Energy and TEP reclassified $35 thousand from Taxes Other Than Income Taxes to Other Expense in the 2011 income statement to conform to current year presentation.

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 Rates

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 (OCRB) of approximately $1 billion; a 5.6% rate of return on Fair Value Rate Base (FVRB) of approximately $1.5 billion, which did not include a return on the fair value increment of rate base (the fair value increment of rate base represents the difference between the OCRB and FVRB). The ACC authorized 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.

Pending TEP Rate Case

In July 2012, TEP filed a general rate case, on a cost-of-service basis, with the ACC requesting a Base Rate increase of approximately 15% to cover a revenue deficiency of $128 million. TEP requested a 7.74% return on an OCRB of $1.5 billion and a 5.68% return on FVRB of $2.3 billion. The return on FVRB includes a 1.56% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million).

TEP requested a Lost Fixed Cost Recovery (LFCR) mechanism to recover non-fuel costs that would go unrecovered due to lost kilowatt-hour (kWh) sales as a result of implementing the ACC’s Electric Energy Efficiency Standards (Electric EE Standards) and the RES. TEP also requested a mechanism, which would be adjusted annually, to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases.

TEP proposed a three-year pilot program allowing for investment in Electric EE Programs to meet the Electric EE Standards in the most cost effective manner. Under TEP’s proposal, energy efficiency investments would be considered regulatory assets and amortized over a four-year period. TEP would earn a return on investment and recover the return and amortization expense through the existing DSM surcharge.

K-105

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In February 2013, TEP, ACC Staff, and other parties to TEP’s pending rate case proceeding entered into a proposed settlement agreement. The proposed settlement agreement requires the approval of the ACC before new rates can become effective.

UNS Gas Rates

2012 UNS Gas Rate Order

In April 2012, the ACC approved a Base Rate increase of $2.7 million, or 1.8%, and a mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the ACC’s Gas Energy Efficiency Standards (Gas EE Standards). UNS Gas recognized less than $0.1 million of revenue under the LFCR in 2012.

The ACC approved an authorized rate of return of 8.3% on an OCRB of $183 million, and a 1.0% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million). The new rates became effective in May 2012.

UNS Electric Rates

2010 UNS Electric Rate Order

In September 2010, the ACC approved a base rate increase of $7 million, or 4%, including an 8.3% authorized rate of return on an OCRB of $169 million, and a 1.3% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $73 million). The order also authorized new depreciation rates, effective October 2010.

In July 2011, UNS Electric completed the ACC and the 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.

Pending UNS Electric Rate Case

In December 2012, as required in the 2010 UNS Electric Rate Order, UNS Electric filed with the ACC a general rate case, on a cost-of-service basis, requesting a non-fuel Base Rate increase of $7.5 million, or 4.6%. UNS Electric requested a rate of return of 8.4% on an OCRB of approximately $217 million and a 6.7% rate of return on a FVRB of $286 million. The return on FVRB includes a 1.6% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $69 million).

UNS Electric requested a LFCR mechanism to recover non-fuel costs that would go unrecovered due to lost kWh sales as a result of implementing Electric EE Standards and the RES. In addition to the LFCR mechanism, UNS Electric requested a Transmission Cost Adjustor (TCA). The TCA is designed to track changes to UNS Electric’s FERC approved Open Access Transmission Tariff (OATT) rate which is updated annually and would allow UNS Electric to recover transmission costs in a timely manner.

COST RECOVERY MECHANISMS

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

Purchased Power and Fuel Adjustment Clause

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.

K-106

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The PPFAC rate includes: 1) a forward component, under which TEP and UNS Electric recover or refund differences between, a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and, b) those embedded in the fuel rate and the current PPFAC rates; and 2) 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:


	2012									2011
	June - December			April - May			January - March			June - December			April - May			January - March
TEP
PPFAC		0.77			0.77			0.53			0.53			0.53			0.09
CTC ⁽¹⁾		0.00			0.00			(0.53	)		(0.53	)		(0.53	)		(0.09	)

Total PPFAC Rate		0.77			0.77			—			—			—			—
UNS Electric		(1.44	)		(0.88	)		(0.88	)		(0.88	)		0.08			0.08

⁽¹⁾	Competition Transition Charge

As part of the TEP 2008 Rate Order, TEP was required to credit previously collected revenues to customers through the PPFAC. As a result, the PPFAC charge had 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 was approved by the ACC in April 2012.

UNS Gas Purchased Gas Adjustor

The PGA mechanism allows UNS Gas to adjust 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-to-customer basis. In 2012, the ACC approved a PGA temporary surcredit of 4.5 cents per therm effective for the period from May 2012 through April 2014, or when the PGA balance reaches zero, whichever comes first. At December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis, an increase of $2 million from December 31, 2011.

The PGA rate ranged from $0.5202 to $0.6501 cents per therm in 2012, and ranged from $0.6593 to $0.7296 cents per therm in 2011.

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.

K-107

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table shows RES and DSM tariffs collected:


	TEP RES		UNS Electric RES		TEP DSM		UNS Gas DSM		UNS Electric DSM
	-Millions of Dollars-
2012	$	30	$	7	$	11	$	1	$	7
2011		35		7		11		1		2
2010		32		7		10		1		2

Renewable Energy Standard

The following table summarizes TEP’s authorized 2010-2012 RES programs:


	Years Ended December 31,
	2012⁽²⁾		2011		2010
	-Millions of Dollars-
Investment in Company-Owned Solar Projects	$	28	$	28	$	14
Return on Investment for Company-Owned Solar Projects		2		1		—
Program Budget⁽¹⁾		30		36		44

⁽¹⁾	The authorized program budget for 2010 includes $12 million in carryforward of 2008 and 2009 RES funds.

⁽²⁾	TEP met the 2012 renewable energy target of 3.5%.

The funding mechanism allows TEP 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.

The following table summarizes UNS Electric’s authorized 2010-2012 RES programs:


	Years Ended December 31,
	2012⁽¹⁾		2011		2010
	-Millions of Dollars-
Investment in Company-Owned Solar Projects	$	5	$	5	$	—
Return on Investment for Company-Owned Solar Projects		1		—		—
Program Budget		8		8		9

⁽¹⁾	UNS Electric met the 2012 renewable energy target of 3.5%.

UNS Electric will invest up to $5 million per year in company-owned renewable assets (between 2013 and 2014) subject to an annual prudency review and approval by the ACC. UNS Electric will recover the associated operating costs, depreciation, and property taxes under the RES program until the next rate case is filed and the assets are incorporated in the Base Rates.

In January 2013, the ACC approved UNS Electric’s 2013 RES implementation plan. UNS Electric’s will collect approximately $7 million from retail customers during 2013, a portion of which is expected to provide recovery of operating costs and a return on investment to UNS Electric for company-owned solar projects.

K-108

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

Energy Efficiency Standards

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

In May 2012, TEP filed a modification to its proposed 2011-2012 Energy Efficiency implementation plan with the ACC. The proposal included a request for a performance incentive for 2012 ranging from approximately $3 million to $4 million and the collection of the performance incentive over a period from October 1, 2012 to December 31, 2012. An administrative law judge issued a recommended opinion and order in August 2012. TEP did not record any income related to the proposed performance incentive in 2012. A proposed settlement agreement in TEP’s pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. The proposed settlement agreement requires the ACC’s approval before it becomes effective.

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 and to reduce total retail therm sales in 2012 by 1,679,890 therms, or 1.2% of 2011 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.

In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Gas Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Gas Energy Efficiency plan or the subsequent requests.

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

Lost Fixed Cost Recovery Mechanism

In May 2012, the ACC authorized a mechanism for UNS Gas to recover therm sales lost as a result of implementing programs under the Gas EE Standards. The LFCR mechanism enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards. UNS Gas recorded less than $0.1 million of LFCR revenue in 2012.

Renewable Energy Credits

UNS Electric had $2 million of RECs on December 31, 2012, and $1 million of RECs on December 31, 2011, recorded in Other Assets on the balance sheets. TEP did not have RECs balances at the end of the periods presented since all RECs have been retired for compliance with the RES standard.

K-109

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Regulatory Assets and Liabilities

The following tables summarize regulatory assets and liabilities:


	December 31, 2012
	TEP			UNS Gas			UNS Electric			UNS Energy
	-Millions of Dollars-
Regulatory Assets—Current
Property Tax Deferrals ⁽¹⁾	$	18		$	—		$	—		$	18
Derivative Instruments (Notes 11 and 16)		2			3			6			11
PPFAC ⁽³⁾		7			—			8			15
DSM ⁽³⁾		5			—			—			5
Other Current Regulatory Assets ⁽⁴⁾		2			1			—			3

Total Regulatory Assets—Current		34			4			14			52

Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 9)		130			4			5			139
Income Taxes Recoverable through Future Revenues ⁽⁵⁾		8			—			2			10
PPFAC—Final Mine Reclamation and Retiree Health Care Costs ⁽⁶⁾		22			—			—			22
Tucson to Nogales Transmission Line ⁽⁷⁾		5			—			—			5
Other Regulatory Assets ⁽⁴⁾		13			1			1			15

Total Regulatory Assets—Noncurrent		178			5			8			191

Regulatory Liabilities—Current
PGA ⁽⁸⁾		—			(17	)		—			(17	)
RES ⁽⁸⁾		(19	)		—			(4	)		(23	)
Other Current Regulatory Liabilities		(2	)		(1	)		(1	)		(4	)

Total Regulatory Liabilities—Current		(21	)		(18	)		(5	)		(44	)

Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements ⁽⁹⁾		(231	)		(25	)		(11	)		(267	)
Income Taxes Payable through Future Rates		(5	)		(1	)		—			(6	)
Deferred Investment Tax Credit ⁽¹⁰⁾		(5	)		—			—			(5	)
Other Regulatory Liabilities		—			—			(1	)		(1	)

Total Regulatory Liabilities—Noncurrent		(241	)		(26	)		(12	)		(279	)

Total Net Regulatory Assets (Liabilities)	$	(50	)	$	(35	)	$	5		$	(80	)

K-110

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	December 31, 2011
	TEP			UNS Gas			UNS Electric			UNS 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 Retiree Benefits (Note 9)		107			3			4			114
Income Taxes Recoverable through Future Revenues ⁽⁵⁾		10			—			2			12
PPFAC ⁽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
PGA ⁽⁸⁾		—			(15	)		—			(15	)
RES ⁽⁸⁾		(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 ⁽⁹⁾		(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	)

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 approximate 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 earned a return on this asset and recovered these costs through Retail Rates over a four-year period ended November 2012.

⁽³⁾	See Cost Recovery Mechanisms discussion above.

⁽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 the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. 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 14 and 20 years.

⁽⁷⁾	The Tucson to Nogales Transmission Line regulatory asset does not earn a return. TEP and UNS Electric will request recovery from FERC for the prudent cost incurred to develop a high-voltage transmission line, which we expect to abandon. See Note 4.

K-111

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Regulatory liabilities represent items that we 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:

⁽⁸⁾	See Cost Recovery Mechanisms discussion above.

⁽⁹⁾

Net Cost of Removal for Interim Retirements represents an estimate of the cost of future AROs 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.

⁽¹⁰⁾	The Deferred Investment Tax Credit is related to federal energy credits generated in 2012 and are deferred as Regulatory Liabilities – Noncurrent and amortized over the tax life of the underlying asset.

Income Statement Impact of Applying Regulatory Accounting

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


	Years Ended December 31,
	2012			2011			2010
	-Millions of Dollars-
TEP
Operating Revenues
Amortization of the Fixed CTC Revenue to be Refunded	$	—		$	36		$	10
Operating Expenses
Depreciation (related to Net Cost of Removal for Interim Retirements)		(33	)		(29	)		(30	)
(Amortization)/Deferral of PPFAC Costs		(31	)		6			22
Other		(7	)		—			(8	)
Non-Operating Income/Expenses
Long-Term Debt (Amortization of Loss on Reacquired Debt Costs)		1			1			1
AFUDC—Equity		3			4			4
Income Taxes—Deferral		(3	)		(8	)		1
Offset by the Tax Effect of the Above Adjustments		26			(4	)		—

Net (Decrease)/Increase to Net Income	$	(44	)	$	6		$	—

Had UNS Gas and UNS Electric not applied regulatory accounting each 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. Regulatory accounting had the following effects on UNS Gas’ and UNS Electric’s net income:


	Years Ended December 31,
	2012			2011			2010
	-Millions of Dollars-
UNS Gas
Net (Decrease)/Increase to Net Income	$	(6	)	$	(5	)	$	(1	)
UNS Electric
Net (Decrease)/Increase to Net Income		(7	)		3			(7	)

K-112

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Future Implications of Discontinuing Application of Regulatory Accounting

We regularly assess whether we can continue to apply regulatory accounting to regulated operations, and we have 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 in the income statements;

•

At December 31, 2012, based on the regulatory assets balances, net of regulatory liabilities:

•

TEP would have recorded an extraordinary after-tax gain of $48 million and an after-tax loss in AOCI of $78 million;

•

UNS Gas would have recorded an extraordinary after-tax loss of $19 million and an after-tax loss in AOCI of $3 million; and

•

UNS Electric would have recorded an extraordinary after-tax gain 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 UNS Energy and UES holding companies, Millennium, and UED are included in Other below.

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


	Reportable Segments
	TEP			UNS Gas			UNS Electric			Other		Reconciling Adjustments			UNS Energy
	-Millions of Dollars-
2012
Income Statement
Operating Revenues-External	$	1,145		$	129		$	189		$	—	$	(1	)	$	1,462
Operating Revenues- Intersegment		17			4			1			18		(40	)		—
Depreciation and Amortization		150			9			18			—		—			177
Interest Income		—			—			—			1		—			1
Interest Expense		88			6			8			3		—			105
Income Tax Expense		39			6			11			—		—			56
Net Income		65			9			17			—		—			91

Cash Flow Statement
Capital Expenditures		(253	)		(16	)		(38	)		—		—			(307	)

Balance Sheet
Total Assets		3,461			310			370			1,121		(1,122	)		4,140

K-113

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Reportable Segments
	TEP			UNS Gas			UNS Electric			Other			Reconciling Adjustments			UNS Energy
	-Millions of Dollars-
2011
Income Statement
Operating Revenues-External ⁽¹⁾	$	1,141		$	149		$	188		$	—		$	1		$	1,479
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		85			10			18			—			(3	)		110

Cash Flow Statement
Capital Expenditures		(352	)		(13	)		(96	)		(34	)		121			(374	)

Balance Sheet
Total Assets		3,278			320			370			1,172			(1,151	)		3,989

2010
Income Statement
Operating Revenue-External ⁽¹⁾	$	1,096		$	144		$	185		$	—		$	1		$	1,426
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		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	)

⁽¹⁾	The amounts previously reported have been revised.

K-114

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Reportable Segments
	TEP		UNS Gas		UNS Electric		Other
Intersegment Revenue	-Millions of Dollars-
2012:
Wholesale Sales—TEP to UNS Electric ⁽¹⁾	$	2	$	—	$	—	$	—
Wholesale Sales—UNS Electric to TEP ⁽¹⁾		—		—		1		—
Wholesale Sales—UNS Gas to TEP ⁽²⁾		—		1		—		—
Gas Revenue—UNS Gas to UNS Electric		—		3		—		—
Other Revenue—TEP to Affiliates⁽³⁾		12		—		—		—
Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas ⁽⁴⁾		—		—		—		18
Other Revenue—TEP to UNS Electric ⁽⁵⁾		3		—		—		—

Total Intersegment Revenue	$	17	$	4	$	1	$	18

2011:
Wholesale Sales—TEP to UNS Electric ⁽¹⁾	$	2	$	—	$	—	$	—
Wholesale Sales—UNS Electric to TEP ⁽¹⁾		—		—		2		—
Wholesale Sales—UED to UNS Electric		—		—		—		5
Gas Revenue—UNS Gas to UNS Electric		—		2		—		—
Other Revenue—TEP to Affiliates⁽³⁾		10		—		—		—
Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas ⁽⁴⁾		—		—		—		18
Other Revenue—TEP to UNS Electric ⁽⁵⁾		3		—		—		—

Total Intersegment Revenue	$	15	$	2	$	2	$	23

2010:
Wholesale Sales—TEP to UNS Electric ⁽¹⁾	$	18	$	—	$	—	$	—
Wholesale Sales—UNS Electric to TEP ⁽¹⁾		—		—		2		—
Wholesale Sales—UED to UNS Electric		—		—		—		11
Wholesale Sales—UNS Gas to TEP⁽²⁾		—		1		—		—
Gas Revenue—UNS Gas to UNS Electric		—		5		—		—
Other Revenue—TEP to Affiliates⁽³⁾		8		—		—		—
Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas ⁽⁴⁾		—		—		—		17
Other Revenue—TEP to UNS Electric⁽⁵⁾		3		—		—		—

Total Intersegment Revenue	$	29	$	6	$	2	$	28

⁽¹⁾	TEP and UNS Electric sell power to each other at third-party market prices.

⁽²⁾	UNS Gas provides gas to TEP for generation of power at third-party market prices.

⁽³⁾	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.

⁽⁴⁾

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 2012 and 2011, and $16 million in 2010 for these services.

⁽⁵⁾	TEP charged UNS Electric for control area services based on a FERC-approved tariff.

TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UNS Energy affiliated entities. Costs are directly assigned to the benefiting entity. Direct costs charged by TEP to affiliates were $10 million in 2012, 2011, and 2010.

UNS 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 2012 and 2011, and $3 million in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other

Other significant reconciling adjustments include the elimination of investments in subsidiaries held by UNS Energy and reclassifications of deferred tax assets and liabilities.

NOTE 4. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

TEP COMMITMENTS

Firm Purchase Commitments

At December 31, 2012, TEP had the following firm non-cancelable purchase commitments (minimum purchase obligations) and operating leases:


	Purchase Commitments
	2013		2014		2015		2016		2017		Thereafter		Total
	-Millions of Dollars-
Fuel (Including Transportation)	$	65	$	65	$	50	$	47	$	39	$	60	$	326
Purchased Power		50		41		29		28		28		386		562
RES Performance-Based Incentive Payments		4		4		4		4		4		42		62
Solar Equipment		12		—		—		—		—		—		12
Transmission		3		3		3		3		3		22		37
Operating Leases		2		2		2		1		1		10		18
Service Agreement		2		2		—		—		—		—		4

Total Unrecognized Firm Commitments	$	138	$	117	$	88	$	83	$	75	$	520	$	1,021

Fuel, Purchased Power, and Transmission Contracts

TEP has long-term contracts for the purchase and delivery of coal with various expiration dates 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 than the minimum purchase obligations to meet its fuel requirements.

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 2013 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2012.

Additionally, Purchased Power includes six 20-year Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011 and 2012. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fuel, purchased power, and transmission costs are recoverable from customers through the PPFAC. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2.

RES Performance-Based Incentives

TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2.

Solar Equipment

TEP committed to purchase 9 MW of photovoltaic equipment through December 2013. TEP spent $11 million in 2012 and $10 million in 2011 under this contract. The ACC approved this purchase under TEP’s RES implementation plan. TEP earns a return on investment in 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 2012, 2011, and 2010.

Service Agreement

In February 2012, TEP entered into a long-term agreement for information technology services. TEP is obligated to pay $2 million per year through December 2014.

UNS GAS AND UNS ELECTRIC COMMITMENTS

At December 31, 2012, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in the table below:


	Purchase Commitments
	2013		2014		2015		2016		2017		Thereafter		Total
	-Millions of Dollars-
Total Unrecognized Firm Commitments – Fuel	$	26	$	13	$	8	$	6	$	4	$	17	$	74

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 Million British Thermal Units (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, 2012. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2013 and 2024.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At December 31, 2012, UNS Electric had various firm non-cancelable purchase commitments as described in the table below:


	Purchase Commitments
	2013		2014		2015		2016		2017		Thereafter		Total
	-Millions of Dollars-
Purchased Power	$	55	$	50	$	14	$	6	$	5	$	80	$	210
Transmission		4		2		2		1		—		—		9

Total Unrecognized Firm Commitments	$	59	$	52	$	16	$	7	$	5	$	80	$	219

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. These contracts expire in various years through 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on market prices as of December 31, 2012. Purchased power commitments also include two 20-year PPAs with renewable energy generation facilities that achieved commercial operation in 2011 and 2012. UNS Electric is obligated to purchase 100% of the output from these facilities.

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 2013 and 2016. However, the effects of both purchased power and transmission cost adjustments are mitigated through UNS Electric’s PPFAC.

UNS Gas and UNS Electric have operating leases, primarily for office facilities and computer equipment, with varying terms and expiration dates. The expense was less than $1 million in each of the years 2012, 2011, and 2010. UNS Gas’ and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are less than $1 million per year for 2013 through 2031.

RES Performance-Based Incentives

UNS Electric is contractually obligated to make RES PBI payments to retail customers with solar installations. UNS Electric’s total obligation for RES PBIs is about $6 million with payments required over periods ranging from 10 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2.

Solar Project

TEP CONTINGENCIES

Springerville Generating Station Unit 3 Outage

In July 2012, Springerville Unit 3 experienced an unplanned outage. As a result of the outage, TEP recorded a pre-tax loss of $2 million in the third quarter of 2012 as TEP did not meet certain availability requirements under the terms of TEP’s operating agreement with Tri-State.

Claims Related to San Juan Generating Station

San Juan Coal Company (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 owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 Arizona Public Service Company (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. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued, and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed Motions to Dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The parties filed a Joint Motion to Stay in November 2012 in furtherance of settlement talks.

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 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, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim.

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 the mines servicing Navajo Generating Station (Navajo), San Juan, and Four Corners. TEP’s share of reclamation costs is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) was $16 million at December 31, 2012, and $13 million at December 31, 2011.

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 us to pass through most fuel costs (including final reclamation costs) to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements on an accrual basis and recovering the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

In June 2012, the participants at San Juan executed a Trust Reclamation Agreement requiring each participant to individually establish and fund a trust based on the participant’s share of the estimated final mine reclamation costs. The trust must remain in effect through completion of final mine reclamation activities currently projected to be 2050. TEP established and funded its trust with $1 million in 2012. TEP expects to make additional cumulative deposits to the trust of approximately $1 million over the next five years.

Tucson to Nogales Transmission Line

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

RESOLUTION OF CONTINGENCIES

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 United States District Court for the District of New Mexico against Public Service Company of New Mexico (PNM), as operator of San Juan, SJCC, and PNM’s and SJCC’s respective parent companies. The suit alleged 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) violated RCRA and SMCRA. The suit sought an injunction with respect to the placement of CCRs at the mine, the imposition of civil penalties, and attorney’s fees and costs. In March 2012, the parties settled the case. The settlement was approved by the court.

TEP is responsible for its share of the settlement of the San Juan claims. TEP recorded less than $1 million for its share of the costs to fund environmental projects and Sierra Club attorney and expert fees required by the settlement, substantially all of which was recorded in 2011. In addition, TEP paid $1 million for its share of construction costs for a new groundwater recovery system adjacent to San Juan and other environmental projects required by the settlement.

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. The mine resumed production in June 2012. The mine fire did not have a material effect on TEP’s financial condition, results of operations, or cash flows due to the use of on-hand inventory of previously mined coal and the low market price of wholesale power during the closure. TEP awaits final resolution in the matter pending an insurance settlement between the mine operator and its insurance company.

ENVIRONMENTAL MATTERS

Environmental Regulation

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $2 million in 2012, $8 million in 2011, and $18 million in 2010 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan. TEP expects to capitalize environmental compliance costs of $10 million in 2013 and $27 million in 2014. In addition, TEP recorded O&M expenses of $15 million in 2012, $12 million in 2011, and $14 million in 2010 related to environmental compliance. TEP expects environmental O&M expenses to be $16 million in 2013.

TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.

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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. In February 2012, the EPA issued final rules called the Mercury and Air Toxics Standards setting limits for mercury emissions and other hazardous air pollutants from power plants.

Navajo

Based on the EPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which include the regional haze final Best Available Retrofit Technology (BART) rules.

San Juan

TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards.

Four Corners

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

Springerville

Based on the EPA’s final standards, Springerville may need mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million.

Sundt Generating Station

TEP expects the final EPA standards will have little effect on capital expenditures at Sundt Generating Station (Sundt).

Regional Haze Rules

Complying with the EPA’s BART findings, and with other environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.

Navajo

In January 2013, the EPA proposed an alternative BART determination that would require the installation of SCR technology on all three units at Navajo by 2023. If SCR technology is ultimately required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant’s particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP’s share of annual operating costs is estimated at less than $1 million for each of the control technologies (SCR and baghouses).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

San Juan

In February 2013, the State of New Mexico released a proposed plan that it presented to the EPA as an alternative to the FIP. The proposed plan includes: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million.

If the proposed plan is not accepted and agreed to by the EPA, the New Mexico Environmental Department, the San Juan participants, and various other regulatory entities, TEP may begin making capital expenditures to install SCRs on San Juan Units 1 and 2 in 2013 to meet the FIP compliance deadline. TEP cannot predict the ultimate outcome of this matter.

Four Corners

In August 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly-owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. In either case, TEP’s estimated share of the capital costs to install SCR technology is about $35 million. TEP’s share of annual operating costs for SCR is estimated at $2 million.

Springerville

Regional haze regulations requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018.

Sundt

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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:


	UNS Energy				TEP
	December 31,				December 31,
	2012		2011		2012		2011
	-Millions of Dollars-
Plant in Service:
Electric Generation Plant	$	1,932	$	1,879	$	1,847	$	1,795
Electric Transmission Plant		842		810		796		766
Electric Distribution Plant		1,495		1,453		1,271		1,234
Gas Distribution Plant		240		233		—		—
Gas Transmission Plant		18		18		—		—
General Plant		347		331		309		302
Intangible Plant—Software Costs ^{(1) (2)}		124		122		123		121
Intangible Plant—Other		5		5		—		—
Electric Plant Held for Future Use		3		5		2		4

Total Plant in Service	$	5,006	$	4,856	$	4,348	$	4,222

Utility Plant under Capital Leases	$	583	$	583	$	583	$	583

⁽¹⁾	Unamortized computer software costs were $36 million for UNS Energy and $35 million for TEP as of December 31, 2012, and $43 million for UNS Energy and $42 million for TEP as of December 31, 2011.

⁽²⁾

The amortization of computer software costs in UNS Energy’s income statements was $13 million in 2012, $10 million in 2011, and $9 million in 2010. The amortization of computer software costs in TEP’s income statements before intercompany allocations was $13 million in 2012, $10 million in 2011, and $9 million in 2010.

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. At December 31, 2012, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:


	Years Ended December 31,
	2012		2011		2010
	-Millions of Dollars-
Lease Expense:
Interest Expense – Included in:
Capital Leases	$	34	$	40	$	47
Operating Expenses – Fuel		3		4		4
Other Expense		—		1		2
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel		4		3		3
Operating Expenses – Amortization		14		14		14

Total Lease Expense	$	55	$	62	$	70

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The depreciable lives as of December 31, 2012, were as follows:


Major Class of Utility Plant in Service	TEP	UNS Gas and UNS Electric
Electric Generation Plant	11-57 years	38-49 years
Electric Transmission Plant	20-60 years	20-50 years
Electric Distribution Plant	28-60 years	23-50 years
Gas Distribution Plant	n/a	30-55 years
Gas Transmission Plant	n/a	30-65 years
General Plant	5-31 years	5-40 years
Intangible Plant	3-19 years	3-32 years

See Utility Plant in Note 1 and TEP Capital Lease Obligations in Note 6.

JOINTLY-OWNED FACILITIES

At December 31, 2012, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:


	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%	$	443	$	7	$	220	$	230
Navajo Units 1, 2, and 3	7.5		148		1		106		43
Four Corners Units 4 and 5	7.0		97		2		73		26
Luna Energy Facility	33.3		53		—		—		53
Transmission Facilities	7.5 to 95.0		328		22		186		164

Total		$	1,069	$	32	$	585	$	516

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.

ASSET RETIREMENT OBLIGATIONS

The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:


	UNS Energy and TEP
	December 31,
	2012		2011
	-Millions of Dollars-
Beginning Balance	$	13	$	4
Liabilities Incurred		—		1
Liabilities Settled		—		—
Accretion Expense		1		—
Revision to Estimated Cash Flows		—		8

Ending Balance	$	14	$	13

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 UNS Energy’s and TEP’s long-term debt in the statements of capitalization.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS ENERGY DEBT—CONVERTIBLE SENIOR NOTES

In 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due in 2035. In 2012, UNS Energy converted or redeemed the entire $150 million Convertible Senior Notes outstanding. Holders of the Convertible Senior Notes had the option of converting their interests to Common Stock at a conversion rate applicable at the time of each notice of redemption or receiving the redemption price of par plus accrued interest for the Convertible Senior Notes. In the first quarter of 2012, holders of approximately $73 million of the Convertible Senior Notes converted their interests into approximately 2.1 million shares of Common Stock and $2 million were redeemed for cash. In the second quarter of 2012, holders of approximately $74 million of Convertible Senior Notes converted their interests into approximately 2.2 million shares of Common Stock and $1 million were redeemed for cash.

TEP DEBT

Tax-Exempt Variable Rate Bonds and Interest Rate Swap

TEP had $215 million in tax-exempt variable rate debt outstanding at December 31, 2012 and December 31, 2011. Each series of bonds is supported by a Letter of Credit (LOC) issued under the TEP Credit Agreement or separate TEP Letter of Credit and Reimbursement Agreements. The LOCs are secured by mortgage bonds issued under TEP’s 1992 Mortgage.

In November 2011, TEP repurchased $150 million of variable rate bonds. 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 LOC, which 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 0.22% in 2012 and 0.23% in 2011. 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 – Long-Term Debt in the income statements through October 2032, the term of the bonds.

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


	Years Ended December 31,
	2012			2011			2010
Interest Rates on Bonds:
Average Interest Rate		0.17	%		0.18	%		0.26	%
Range of Average Weekly Rates		0.06	%		0.05	%		0.17	%
		to 0.26	%		to 0.34	%		to 0.39	%

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

Unsecured Fixed Rate Bonds

At December 31, 2012, TEP had $609 million in unsecured fixed rate bonds. At December 31, 2011, TEP had $616 million outstanding.

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UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875% and maturity dates ranging from 2026 to 2033. TEP’s $8 million payment to the trustee was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized approximately $2 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statements through March 2030, the term of the bonds.

In June 2012, the Industrial Development Authority of Pima County, Arizona issued approximately $16 million of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds together with $0.4 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $16 million of outstanding unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized less than $0.5 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statements through June 2030, the term of the bonds.

In November 2011, TEP redeemed $22 million in unsecured fixed rate bonds. 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. TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs to Interest Expense-Long-Term Debt in the income statements through October 2040, the term of the bonds.

2012 TEP Unsecured Notes

2011 TEP Unsecured Notes

In November 2011, TEP issued $250 million of 5.15% unsecured notes due November 2021. TEP may call the debt any time before August 15, 2021, with a make-whole premium plus accrued interest. 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 bonds; 2) redeem $22 million of 6.1% fixed rate bonds; and 3) repay $78 million of outstanding revolving credit facility balances, with the remaining proceeds applied to general corporate purposes. The variable rate bonds were supported by LOCs issued under TEP’s Credit Facility. As a result of the repurchase of the variable rate bonds, 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-Long-Term Debt in the income statements through November 2021, the term of the unsecured notes.

K-126

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1992 Mortgage

TEP’s 1992 Mortgage creates liens on and security interests in most of TEP’s utility plant assets, with the exception of Springerville Unit 2. San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title to Springerville Unit 2. Utility Plant under Capital Leases is not subject to such liens nor is it 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, 2012, and December 31, 2011.

TEP CAPITAL LEASE OBLIGATIONS

Springerville Leases

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

•

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. 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 2012, TEP initiated a proceeding seeking judicial confirmation of the results of the appraisal process in federal district court. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for the leased interest. In January 2013, the federal district court denied TEP’s petition on the grounds that the court lacks jurisdiction in the matter. In February 2013, TEP appealed the matter to the U.S. Court of Appeals for the Ninth Circuit.

•

The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for 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 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.

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 Facilities 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 January 2013, through scheduled lease payments, TEP reduced its capital lease obligations by $82 million.

LEASE DEBT AND EQUITY

Investments in Springerville Lease Debt and Equity

TEP’s investments in Springerville Unit 1 lease debt totaled $9 million at December 31, 2012, and $29 million at December 31, 2011. In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2012, and $37 million at December 31, 2011.

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UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 London Interbank Offered Rate (LIBOR) plus a spread. The applicable spread was 1.75% at December 31, 2012, and 1.625% at December 31, 2011.

The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:


Outstanding at December 31, 2012	Fixed Ratio			LIBOR Spread
$ 34 million		5.77	%		1.75	%
$ 19 million		3.18	%		1.75	%
$ 6 million		3.32	%		1.75	%

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 United States 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 1.125%. 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 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 United States Treasury security yield plus 50 basis points. UES guarantees the notes. 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.

K-128

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS ENERGY CREDIT AGREEMENT

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

In November 2010, UNS 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. UNS Energy’s obligations under the agreement are secured by a pledge of the capital stock of Millennium, UES, and UED.

UNS 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.

UNS Energy had $45 million of outstanding borrowings at December 31, 2012, and $57 million of outstanding borrowings at December 31, 2011, under its revolving credit facility. The weighted average interest rate on the revolver was 1.96% at December 31, 2012, and 2.04% at December 31, 2011. We reflected the revolver borrowings in Long-Term Debt on the balance sheet as UNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 13, 2013, outstanding borrowings under the UNS Credit Agreement were $45 million.

Interest rates and fees under the UNS Energy Credit Agreement are based on a pricing grid tied to UNS 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 UNS Energy Credit Agreement contains a number of covenants which restrict UNS Energy and its subsidiaries, including restrictions on additional indebtedness, liens, mergers, and sales of assets. The UNS Energy Credit Agreement also requires UNS Energy to meet a minimum cash flow to interest coverage ratio determined on a UNS Energy standalone basis and not to exceed a maximum leverage ratio determined on a consolidated basis. Under the UNS Energy Credit Agreement, UNS 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 bonds 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, revolving LOC facility, and a $341 million LOC 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%.

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 UNS Energy so long as it maintains compliance with the agreement.

K-129

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2012, TEP had no borrowings outstanding and $1 million in LOCs issued under its revolving credit facility. As of December 31, 2011, TEP had $10 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility. The revolving loan balance was included in Current Liabilities on UNS Energy’s and TEP’s balance sheets. The outstanding LOCs are off-balance sheet obligations of TEP. As of February 13, 2013, TEP had $30 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility.

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 bonds 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 REVOLVER

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 Revolver 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 Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric. The UNS Gas/UNS Electric Revolver may be used to issue LOCs, as well as for revolver borrowings. UNS Gas and UNS Electric issue LOCs, 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 continue to amortize these costs through November 2016 to Interest Expense – Long-Term Debt in the income statements.

Interest rates and fees under the UNS Gas/UNS Electric Revolver are based on a pricing grid tied to their credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.25% for Eurodollar loans or Alternate Base Rate plus 0.25% for Alternate Base Rate loans.

The UNS Gas/UNS Electric Revolver 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 Gas/UNS Electric Revolver also stipulates a maximum leverage ratio. Under the terms of the UNS Gas/UNS Electric Revolver, UNS Gas and UNS Electric may pay dividends so long as they maintain compliance with the agreement.

UNS Electric had less than $0.5 million in outstanding LOCs under the UNS Gas/UNS Electric Revolver as of December 31, 2012, and $6 million outstanding as of December 31, 2011. These balances are not shown on the balance sheet.

OTHER

At December 31, 2012, UNS 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.

K-130

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DEBT MATURITIES

Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:


	TEP Variable Rate Bonds Supported by Letters of Credit⁽¹⁾		TEP Scheduled Debt Retirements⁽²⁾		TEP Capital Lease Obligations			TEP Total			UNS Gas		UNS Electric		UNS Energy Parent Company		Total
	—Millions of Dollars -
2013	$	—	$	—	$	121		$	121		$	—	$	—	$	—	$	121
2014		37		—		194			231			—		—		—		231
2015		—		—		23			23			50		80		—		153
2016		178		—		17			195			—		—		45		240
2017		—		—		18			18			—		—		—		18

Total 2013 – 2017		215		—		373			588			50		80		45		763
Thereafter		—		1,009		42			1,051			50		50		—		1,151
Less: Imputed Interest		—		—		(62	)		(62	)		—		—		—		(62	)

Total	$	215	$	1,009	$	353		$	1,577		$	100	$	130	$	45	$	1,852

⁽¹⁾

TEP’s variable rate bonds 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 in December 2014. Although the variable rate bonds 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.

NOTE 7. STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UNS Energy

UNS Energy’s 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. UNS Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2012; therefore, TEP and the other subsidiaries were not restricted from paying dividends.

In February 2013, UNS Energy declared a first quarter dividend to shareholders of $0.435 per share of UNS Energy Common Stock. The dividend, totaling approximately $18 million, will be paid on March 25, 2013, to common shareholders of record as of March 13, 2013.

In the first half of 2012, $147 million of the Convertible Senior Notes outstanding were converted into approximately 4.3 million shares of UNS Energy Common Stock increasing common stock equity by $147 million.

TEP

The Federal Power Act states that an electric utility’s dividends shall not be paid out of funds properly included in capital accounts. TEP has an accumulated deficit rather than positive retained earnings. 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. TEP paid dividends to UNS Energy of $30 million in 2012; no dividends were paid in 2011; and $60 million were paid in 2010.

K-131

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Energy did not contribute capital to TEP in 2012 but made capital contributions of $30 million in 2011 and $15 million in 2010.

NOTE 8. INCOME TAXES

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


	UNS Energy									TEP
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	-Millions of Dollars-
Federal Income Tax Expense at Statutory Rate	$	51		$	62		$	66		$	37		$	48		$	58
State Income Tax Expense, Net of Federal Benefit		7			8			9			5			6			8
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	)		—			—			(3	)
Federal/State Tax Credits		(1	)		(3	)		(2	)		(1	)		(2	)		(2	)
Other		—			1			(3	)		(1	)		1			—

Total Federal and State Income Tax Expense	$	56		$	67		$	77		$	39		$	52		$	60

Effective Tax Rate		38	%		38	%		41	%		37	%		38	%		36	%

In 2010, UNS 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 current and prior period financial statements.

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

	UNS Energy									TEP
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	-Millions of Dollars-
Current Tax Expense (Benefit)
Federal	$	(2	)	$	(7	)	$	34		$	(4	)	$	(5	)	$	28
State		(2	)		(2	)		7			(2	)		(2	)		7

Total		(4	)		(9	)		41			(6	)		(7	)		35

Deferred Tax Expense (Benefit)
Federal		51			64			32			38			50			24
Federal Investment Tax Credits		—			(1	)		(1	)		—			(1	)		(1	)
State		9			13			5			7			10			2

Total		60			76			36			45			59			25

Total Federal and State Income Tax Expense	$	56		$	67		$	77		$	39		$	52		$	60

K-132

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	UNS Energy						TEP
	December 31,						December 31,
	2012			2011			2012			2011
	-Millions of Dollars-
Gross Deferred Income Tax Assets
Capital Lease Obligations	$	141		$	169		$	141		$	169
Net Operating Loss Carryforwards		72			81			85			76
Customer Advances and Contributions in Aid of Construction		34			30			19			17
Alternative Minimum Tax Credit		43			43			24			25
Accrued Postretirement Benefits		23			23			23			23
Renewable Energy Credit Up-Front Incentive Payments		26			22			20			18
Emission Allowance Inventory		10			10			10			10
Unregulated Investment Losses		9			9			—			—
Other		44			34			43			29

Gross Deferred Income Tax Assets		402			421			365			367

Deferred Tax Assets Valuation Allowance		(7	)		(7	)		—			—

Gross Deferred Income Tax Liabilities
Plant – Net		(648	)		(585	)		(571	)		(516	)
Capital Lease Assets – Net		(34	)		(41	)		(34	)		(41	)
Pensions		(23	)		(17	)		(24	)		(18	)
PPFAC		(6	)		(19	)		(3	)		(16	)
Other		(15	)		(29	)		(15	)		(17	)

Gross Deferred Income Tax Liabilities		(726	)		(691	)		(647	)		(608	)

Net Deferred Income Tax Liabilities	$	(331	)	$	(277	)	$	(282	)	$	(241	)

The net deferred income tax liability on the balance sheet is as follows:


	UNS Energy						TEP
	December 31,						December 31,
	2012			2011			2012			2011
	-Millions of Dollars-
Deferred Income Taxes – Current Assets	$	34		$	23		$	37		$	22
Deferred Income Taxes – Noncurrent Liabilities		(365	)		(300	)		(319	)		(263	)

Net Deferred Income Tax Liability	$	(331	)	$	(277	)	$	(282	)	$	(241	)

The $9 million unregulated investment loss deferred tax asset includes $7 million of capital loss at December 31, 2012, and December 31, 2011. 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, UNS Energy recorded a $7 million valuation allowance against the deferred tax asset as of December 31, 2012, and December 31, 2011. Management believes that based on its historical pattern of taxable income, UNS Energy will produce sufficient income in the future to realize all other deferred income tax assets.

K-133

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Tax Position

As of December 31, 2012, UNS Energy and TEP had the following carryforward amounts:


	UNS Energy			TEP
	Amount		Expiring Year	Amount		Expiring Year
	-Amounts in Millions of Dollars-
Capital Loss	$	8	2015	$	—	—
Federal Net Operating Loss		202	2031-32		233	2031-32
State Net Operating Loss		14	2032		57	2016-32
State Credits		2	2016-17		4	2016-17
AMT Credit		43	None		24	None

State Tax Rate Change

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 UNS 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 UNS Energy’s and TEP’s effective tax rate for 2012 or 2011.

Excess Tax Benefit Realized from Share-Based Compensation Plans

UNS Energy records excess tax benefits as an increase to Common Stock when tax deductions for share-based compensation exceed the expense recorded in the financial statements and they result in a reduction to income taxes payable. As of December 31, 2012, UNS Energy had $2 million of excess tax benefits that were not recorded in Common Stock. The excess benefits will be recorded in Common Stock when the Federal net operating loss carryforwards of $202 million are used.

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 UNS Energy and TEP:


	UNS Energy						TEP
	December 31,						December 31,
	2012			2011			2012			2011
	-Millions of Dollars-
Unrecognized Tax Benefits, Beginning of Year	$	29		$	41		$	24		$	35
Additions Based on Tax Positions Taken in the Current Year		5			9			3			8
Reductions Based on Settlements with Tax Authorities		(4	)		(22	)		(4	)		(19	)
Additions Based on Tax Positions Taken in the Prior Year		—			1			—			—

Unrecognized Tax Benefits, End of Year	$	30		$	29		$	23		$	24

Unrecognized tax benefits of $1 million, if recognized, would reduce the effective tax rate at December 31, 2012, and December 31, 2011, for both UNS Energy and TEP. The balance in unrecognized tax benefits could change in the next 12 months as a result of ongoing IRS audits, but we are unable to determine the amount of the change.

UNS Energy and TEP recognize interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements. UNS Energy and TEP did not recognize a reduction to interest expense in 2012. A reduction to Other Interest Expense of $1 million was recorded in 2011. The balance of interest payable for UNS Energy and TEP was $1 million at both December 31, 2012 and December 31, 2011. We have no penalties accrued in the years presented.

K-134

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

UNS Energy and TEP have been audited by the IRS through tax year 2008 and are currently under audit by the IRS for 2009 and 2010. We are unable to determine when the audits will be completed. UNS Energy and TEP are not currently under audit by any state tax agencies.

NOTE 9. EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

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 2013, UNS Energy expects to contribute $24 million to the pension plans, including $22 million in contributions by TEP.

OTHER RETIREE BENEFIT PLANS

TEP provides limited health care and life insurance benefits for retirees. Active TEP 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 retiree medical benefits for current retirees. UNS Gas and UNS Electric active employees are not eligible for retiree medical benefits.

TEP has a Voluntary Employee Beneficiary Association (VEBA) to fund its other retiree benefit plan related to classified employees. TEP contributed $3 million in 2012, and $2 million in each of 2011 and 2010 to the VEBA. We record changes in other retiree obligation, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Other retiree benefits for unclassified employees are funded on a year-by-year basis.

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. TEP’s retiree medical plan was amended in 2012, to increase the participant contributions for classified employees who retire after February 1, 2014.

K-135

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Pension Benefits						Other Retiree Benefits
	Years Ended December 31,
	2012			2011			2012			2011
	-Millions of Dollars-
Regulatory Pension Asset Included in Other Regulatory Assets	$	129		$	106		$	10		$	8
Accrued Benefit Liability Included in Accrued Employee Expenses		(1	)		(1	)		(2	)		(2	)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits		(90	)		(72	)		(69	)		(66	)
Accumulated Other Comprehensive Loss (related to SERP)		4			2			—			—

Net Amount Recognized	$	42		$	35		$	(61	)	$	(60	)

The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $9 million at December 31, 2012, and $8 million at December 31, 2011. The table also includes a retiree 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 retiree benefit plans at December 31, 2012, and December 31, 2011. The table below includes 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:


	Pension Benefits						Other Retiree Benefits
	Years Ended December 31,
	2012			2011			2012			2011
	-Millions of Dollars-
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	319		$	283		$	73		$	73
Actuarial (Gain) Loss		51			22			3			—
Interest Cost		15			16			3			4
Service Cost		10			10			3			3
Amendments		—			—			—			(2	)
Benefits Paid		(15	)		(12	)		(4	)		(5	)

Projected Benefit Obligation at End of Year		380			319			78			73

Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		245			220			5			4
Actual Return on Plan Assets		36			14			1			—
Benefits Paid		(15	)		(12	)		(4	)		(5	)
Employer Contributions ⁽¹⁾		23			23			5			6

Fair Value of Plan Assets at End of Year		289			245			7			5

Funded Status at End of Year	$	(91	)	$	(74	)	$	(71	)	$	(68	)

⁽¹⁾	TEP made $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012 and 2011.

K-136

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

•

Pension benefit obligations of $23 million at December 31, 2012, and $18 million at December 31, 2011;

•

Plan assets of $14 million at December 31, 2012, and $10 million at December 31, 2011; and

•

A retiree benefit obligation of $1 million at December 31, 2012, and at December 31, 2011.

The following table provides the components of UNS 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:


	Pension Benefits				Other Retiree Benefits
	Years Ended December 31,
	2012		2011		2012			2011
	-Millions of Dollars-
Net Loss	$	133	$	108	$	13		$	11
Prior Service Cost (Benefit)		1		1		(3	)		(3	)

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


	December 31,
	2012		2011
	-Millions of Dollars-
Projected Benefit Obligation at End of Year	$	380	$	319
Accumulated Benefit Obligation at End of Year		334		281
Fair Value of Plan Assets at End of Year		289		245

At December 31, 2012, and December 31, 2011, all UNS 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:


	Pension Benefits									Other Retiree Benefits
	Years Ended December 31,
	2012			2011			2010			2012		2011			2010
	-Millions of Dollars-
Service Cost	$	10		$	10		$	8		$	3	$	3		$	3
Interest Cost		16			15			15			3		4			4
Expected Return on Plan Assets		(17	)		(16	)		(14	)		—		—			—
Prior Service Cost Amortization		—			—			—			—		(1	)		(2	)
Recognized Actuarial Loss		7			6			5			—		—			—

Net Periodic Benefit Cost	$	16		$	15		$	14		$	6	$	6		$	5

Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in current year earnings.

K-137

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:


	Pension Benefits
	2012					2011						2010
	Regulatory Asset			AOCI		Regulatory Asset			AOCI			Regulatory Asset			AOCI
	-Millions of Dollars-
Current Year Actuarial (Gain) Loss	$	30		$	1	$	25		$	(2	)	$	16		$	1
Amortization of Actuarial Gain (Loss)		(7	)		—		(5	)		—			(5	)		—

Total Recognized (Gain) Loss	$	23		$	1	$	20		$	(2	)	$	11		$	1


	Other Retiree Benefits
	2012		2011			2010
	Regulatory Asset		Regulatory Asset			Regulatory Asset
	-Millions of Dollars-
Prior Service Cost (Credit)	$	—	$	(2	)	$	—
Current Year Actuarial (Gain) Loss		2		—			(1	)
Amortization of Actuarial (Gain) Loss		—		—			(1	)
Amortization of Prior Service (Cost) Credit		—		1			2

Total Recognized (Gain) Loss	$	2	$	(1	)	$	—

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 $9 million estimated net loss from other regulatory assets and less than $0.5 million prior service cost from AOCI into net periodic benefit cost in 2013. The estimated net loss for the defined benefit postretirement plans that will be amortized from other regulatory assets into net periodic benefit cost in 2013 is less than $1 million. The estimated prior service benefit that will be amortized is less than $1 million.


	Pension Benefits		Other Retiree Benefits
	2012	2011	2012			2011
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	4.1%-4.3%	4.9%-5.0%		3.8	%		4.7	%
Rate of Compensation Increase	3.0%	3.0%		N/A			N/A


	Pension Benefits			Other Retiree Benefits
	2012	2011	2010	2012			2011			2010
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate	4.9% - 5.0%	5.5% - 5.6%	6.3%		4.7	%		5.2	%		6.0	%
Rate of Compensation Increase	3.0%	3.0% - 5.0%	3.0% - 5.0%		N/A			N/A			N/A
Expected Return on Plan Assets	7.0%	7.0%	7.5%		7.0	%		5.1	%		5.6	%

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-138

UNS 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. The assumed health care cost trend rates follow:


	December 31,
	2012			2011
Health Care Cost Trend Rate Assumed for Next Year		6.9	%		6.9	%
Ultimate Health Care Cost Trend Rate Assumed		4.5	%		4.5	%
Year that the Rate Reaches the Ultimate Trend Rate		2027			2027

Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2012, amounts:


	One-Percentage- Point Increase		One-Percentage- Point Decrease
	-Millions of Dollars-
Effect on Total Service and Interest Cost Components	$	1	$	(1	)
Effect on Retiree Benefit Obligation		6		(5	)

PENSION PLAN AND OTHER RETIREE 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, on the measurement date were as follows:


	TEP Plan Assets						UNS Gas and UNS Electric Plan Assets
	2012			2011			2012			2011
Asset Category
Equity Securities		50	%		49	%		56	%		55	%
Fixed Income Securities		41			42			33			34
Real Estate		7			7			11			11
Other		2			2			—			—

Total		100	%		100	%		100	%		100	%

K-139

UNS 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:


	Fair Value Measurements of Pension Assets December 31, 2012
	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:
United States Large Cap		—		71		—		71
United States Small Cap		—		15		—		15
Non-United States		—		59		—		59
Fixed Income		—		116		—		116
Real Estate		—		8		13		21
Private Equity		—		—		6		6

Total	$	1	$	269	$	19	$	289


	Fair Value Measurements of Pension Assets December 31, 2011
	Level 1		Level 2		Level 3		Total
	- Millions of Dollars -
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap		—		61		—		61
United States Small Cap		—		13		—		13
Non-United States		—		47		—		47
Fixed Income		—		101		—		101
Real Estate		—		7		11		18
Private Equity		—		—		4		4

Total	$	1	$	229	$	15	$	245

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, United States bond funds, 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 87% of real estate assets tracked by the index in 2012 and comprising 85% in 2011.

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

The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UES pension plan of $14 million at December 31, 2012, and $10 million at December 31, 2011.

K-140

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.


	Year Ended December 31, 2012
	Private Equity		Real Estate		Total
Beginning Balance at January 1, 2012	$	4	$	11	$	15
Actual Return on Plan Assets:
Assets Held at Reporting Date		1		2		3
Purchases, Sales, and Settlements		1		—		1

Ending Balance at December 31, 2012	$	6	$	13	$	19


	Year Ended December 31, 2011
	Private Equity		Real Estate		Total
Beginning Balance at January 1, 2011	$	2	$	10	$	12
Actual Return on Plan Assets:
Assets Held at Reporting Date		—		1		1
Purchases, Sales, and Settlements		2		—		2

Ending Balance at December 31, 2011	$	4	$	11	$	15

UNS Gas and UNS Electric have no pension assets classified as Level 3 in the fair value hierarchy.

Pension Plan Investments

Investment Goals

Asset allocation is the principal method for achieving each pension plan’s investment objectives, 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: plan status, plan sponsor financial status and profitability, plan features, and 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 may also be used for defensive purposes.

Relationship between Plan Assets and Benefit Obligations

The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair 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.

K-141

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Target Allocation Percentages

The current target allocation percentages for the major asset categories of the plan as of December 31, 2012, follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.


	TEP Plan			UES Plan			VEBA Trust
Fixed Income		41	%		33	%		35	%
United States Large Cap		24			28			43
Non-United States Developed		15			17			13
Real Estate		8			11			—
United States Small Cap		5			6			2
Non-United States Emerging		5			5			5
Private Equity		2			—			—
Cash/Treasury Bills		—			—			2

Total		100	%		100	%		100	%

Pension Fund Descriptions

For each type of asset category selected by the Pension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds.

Other Retiree Benefit Assets

As of December 31, 2012, the fair value of VEBA trust assets was $7 million, of which $3 million were fixed income investments and $4 million were equities. As of December 31, 2011, the fair value of VEBA trust assets was $5 million, including $3 million of fixed income investments and approximately $2 million of equity and money market funds. The VEBA trust assets are primarily Level 2. There are no Level 3 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 retiree plan, which reflect future service, as appropriate.


	Pension Benefits		Other Retiree Benefits
	-Millions of Dollars-
2013	$	15	$	4
2014		16		5
2015		16		5
2016		18		5
2017		20		5
Years 2018-2022		110		30

TEP’s union plan was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments shown above was approximately $5 million in total. The pension benefit obligation was not materially affected by this amendment.

UNS Gas and UNS Electric expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $2 million in 2013 through 2017, and $9 million in 2018 through 2022.

K-142

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DEFINED CONTRIBUTION PLAN

We offer a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account which may include a UNS Energy stock fund. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in 2012, $5 million in 2011, and $4 million in 2010. UNS Gas and UNS Electric made matching contributions of less than $1 million in each of 2012, 2011, and 2010.

NOTE 10. SHARE-BASED COMPENSATION PLAN

Under the UNS Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), the Compensation Committee of the UNS 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.

STOCK OPTIONS

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.

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


(Shares in Thousands)	2012					2011					2010
Stock Options	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding, Beginning of Year		581		$	29.11		921		$	27.96		1,598		$	24.50
Granted		—			—		—			—		—			—
Exercised		(132	)		26.54		(319	)		25.60		(660	)		19.33
Forfeited/Expired		(40	)		37.88		(21	)		31.92		(17	)		37.88

Outstanding, End of Year		409			29.09		581			29.11		921			27.96

Exercisable, End of Year		409		$	29.09		508		$	29.53		654		$	28.70
Aggregate Intrinsic Value of Options Exercised ($000s)				$	1,878				$	3,690				$	9,124


	At December 31, 2012
Aggregate Intrinsic Value for Options Outstanding ($000s)	$	5,450
Aggregate Intrinsic Value for Options Exercisable ($000s)	$	5,450
Weighted Average Remaining Contractual Life of Outstanding Options		5.2 years
Weighted Average Remaining Contractual Life of Exercisable Options		5.2 years

K-143

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

See summary of stock options in the table below:


	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
$26.11—$37.88		409		5.2 years	$	29.09		409	$	29.09

RESTRICTED STOCK UNITS AND PERFORMANCE SHARE AWARDS

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 31,058 in 2012, 56,705 in 2011, and 14,866 in 2010 were issued with no additional increase in equity as the expense was previously recognized over the vesting period.

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

•

2012—15,303 stock units at a weighted average fair value of $35.94 per share;

•

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

•

2010—15,620 stock units at a weighted average fair value of $31.69 per share.

Performance Share Awards

In 2012, 2011, and 2010, the Compensation Committee granted performance share awards to upper management. Half of the performance share awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Return to the Edison Electric Institute Index during the performance period. The grant date fair value of these awards with a market condition were derived based on a Monte Carlo simulation. Compensation expense equal to the fair value on the grant date is recognized over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half will be paid out in Common Stock based on cumulative net income during the performance period. The grant date fair values of these awards with a performance condition were the closing Common Stock market prices on the dates of grant. Compensation expense equal to the fair value on the grant date is recognized over the requisite service period only for the awards that ultimately vest. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Vested performance shares are eligible for dividend equivalents during the performance period.


					Grant Date Fair Value
Award Year	Performance Period		Shares Granted		Market Condition		Performance Condition
2012		January 1, 2012 to December 31, 2014		80,140	$	32.71	$	36.40
2011		January 1, 2011 to December 31, 2013		80,440		33.73		36.58
2010		January 1, 2010 to December 31, 2012		93,720		31.26		30.52

K-144

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At December 31, 2012, upon completion of the three-year performance period, 76,478 shares were earned and vested; 17,242 shares were unearned and forfeited. The vested performance shares also earned 10,516 in dividend equivalent shares.


	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, 2012		153		$	32.85		15		$	37.53
Granted		80			34.56		15			35.94
Vested		(77	)		31.08		(15	)		37.53
Forfeited		(11	)		31.42		—			—

Non-vested at December 31, 2012		145			34.83		15			35.94

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

Annually during 2010 through 2012, UNS 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. The actual tax deduction realized from the exercise of share-based payment arrangements totaled less than $1 million in 2012 and $3 million in 2010. UNS Energy did not realize a tax deduction from the exercise of share-based payment arrangements in 2011.

At December 31, 2012, 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 2014. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at December 31, 2012, was 1 million.

NOTE 11. FAIR VALUE MEASUREMENTS

We categorize our assets and liabilities at fair value into the three-level hierarchy based on inputs used to determine the fair value measurement. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable. Level 3 inputs are unobservable and supported by little or no market activity.

K-145

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables present, by level within the fair value hierarchy, UNS 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.


	UNS Energy
	Level 1		Level 2			Level 3			Total
	December 31, 2012
	- Millions of Dollars -
Assets
Cash Equivalents⁽¹⁾	$	20	$	—		$	—		$	20
Rabbi Trust Investments to Support the Deferred Compensation and SERP Plans⁽²⁾		—		19			—			19
Energy Contracts⁽³⁾		—		2			5			7

Total Assets		20		21			5			46

Liabilities
Energy Contracts⁽³⁾		—		(7	)		(10	)		(17	)
Interest Rate Swaps⁽⁴⁾		—		(10	)		—			(10	)

Total Liabilities		—		(17	)		(10	)		(27	)

Net Total Assets and (Liabilities)	$	20	$	4		$	(5	)	$	19


	UNS Energy
	Level 1		Level 2			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⁽³⁾		—		—			14			14

Total Assets		23		16			14			53

Liabilities
Energy Contracts⁽³⁾		—		(21	)		(24	)		(45	)
Interest Rate Swaps⁽⁴⁾		—		(12	)		—			(12	)

Total Liabilities		—		(33	)		(24	)		(57	)

Net Total Assets and (Liabilities)	$	23	$	(17	)	$	(10	)	$	(4	)


	TEP
	Level 1		Level 2			Level 3			Total
	December 31, 2012
	- Millions of Dollars -
Assets
Cash Equivalents⁽¹⁾	$	7	$	—		$	—		$	7
Rabbi Trust Investments to Support the Deferred Compensation and SERP Plans⁽²⁾		—		19			—			19
Energy Contracts⁽³⁾		—		1			2			3

Total Assets		7		20			2			29

Liabilities
Energy Contracts⁽³⁾		—		(3	)		(2	)		(5	)
Interest Rate Swaps⁽⁴⁾		—		(10	)		—			(10	)

Total Liabilities		—		(13	)		(2	)		(15	)

Net Total Assets and (Liabilities)	$	7	$	7		$	—		$	14

K-146

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	TEP
	Level 1		Level 2			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⁽³⁾		—		—			3			3

Total Assets		8		16			3			27

Liabilities
Energy Contracts⁽³⁾		—		(9	)		(3	)		(12	)
Interest Rate Swaps⁽⁴⁾		—		(11	)		—			(11	)

Total Liabilities		—		(20	)		(3	)		(23	)

Net Total Assets and (Liabilities)	$	8	$	(4	)	$	—		$	4

⁽¹⁾	Cash Equivalents are based on observable market prices and include the fair value of money market funds and certificates of deposit. These amounts are included in Cash and Cash Equivalents and in 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⁾

Energy Contracts include gas swap agreements (Level 2), gas and power options (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 Other Assets and Derivative Instruments on the balance sheets. The valuation techniques are described below. See Note 16.

⁽⁴⁾	Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association 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 pricing adjusted for basis differences, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

For both power and gas prices, we 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 such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.

We estimate the fair value of our options using the Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, correlations, interest rates, and forward price curves.

K-147

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.

Our 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. We review the assumptions underlying our contracts monthly.

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:


	Fair Value at December 31, 2012					Range of
	Assets		Liabilities			Unobservable Input
	-Millions of Dollars-
Forward Contracts⁽¹⁾	$	4	$	(10	)
Valuation Technique: Market approach
Unobservable Input:
Market price per MWh							$19.50 - $ 56.24

Option Contracts⁽²⁾		1		—
Valuation Technique: Option model
Unobservable Inputs:
Market Price per MWh							$29.50 - $ 46.00
Power Volatility							30.38% - 59.95%
Market Price per MMbtu							$3.22 - $ 3.84
Gas Volatility							29.32% -36.14%

Level 3 Energy Contracts	$	5	$	(10	)

⁽¹⁾	TEP comprises $1 million of the forward contract assets and $2 million of the forward contract liabilities.

⁽²⁾	The option contracts relate to TEP.

Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability. These are recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statements.

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:


	Year Ended December 31, 2012
	UNS Energy			TEP
	Energy Contracts
	-Millions of Dollars-
Balance as of December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses)Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments		(5	)		1
Settlements		10			(1	)

Balance as of December 31, 2012	$	(5	)	$	—

Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

K-148

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Year Ended December 31, 2011
	UNS Energy			TEP
	Energy Contracts
	-Millions of Dollars-
Balance as of December 31, 2010	$	(10	)	$	1
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – 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/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(9	)	$	—

Financial Instruments Not Carried at Fair Value

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:

•

The carrying amounts of our current assets and liabilities, including current maturities of long-term debt, and amounts outstanding under our credit agreements, which approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.

•

For Investment in Lease Debt, we calculate the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporate the impact of counterparty credit risk using market credit default swap data.

•

For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 in 2011.

•

For Long-Term Debt, we use quoted market prices, where available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.

K-149

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying value recorded on the balance sheet and the estimated fair values of our financial instruments were as follows:


			December 31,
			2012				2011
	Fair Value Hierarchy		Carrying Value		Fair Value		Carrying Value		Fair Value
			-Millions of Dollars-
Assets:
TEP Investment in Lease Debt		Level 2	$	9	$	9	$	29	$	29
TEP Investment in Lease Equity		Level 3		36		23		37		21
Liabilities:
Long-Term Debt
UNS Energy		Level 2		1,498		1,583		1,517		1,543
TEP		Level 2		1,223		1,271		1,080		1,061

TEP held the Investment in Lease Debt to maturity in January 2013. This investment was stated at amortized cost, which means the purchase cost had been adjusted for the amortization of the premium and discount to maturity.

The fair value of TEP’s Long-Term Debt increased from prior year because of a change in valuation methodology concerning the make-whole premium applied to the bonds if they are called early.

NOTE 12. UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (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 Senior 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 remaining notes, not yet converted, were converted to Common Stock.

K-150

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Years Ended December 31,
	2012		2011		2010
	-Thousands of Dollars-
Numerator:
Net Income	$	90,919	$	109,975	$	112,984
Income from Assumed Conversion of Convertible Senior Notes		1,100		4,390		4,390

Adjusted Numerator	$	92,019	$	114,365	$	117,374


	-Thousands of Shares-
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued		40,212		36,780		36,200
Fully Vested Deferred Stock Units		150		129		123
Participating Securities		—		53		92

Total Weighted Average Shares of Common Stock Outstanding and Participating Securities—Basic		40,362		36,962		36,415
Effect of Diluted Securities:
Convertible Senior Notes		1,062		4,281		4,178
Options and Stock Issuable Under Share-Based Compensation Plans		331		366		448

Total Shares—Diluted		41,755		41,609		41,041

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:

Years Ended December 31,

2012

2011

2010

-Thousands of Shares-

Stock Options Excluded from the Diluted EPS Computation

153

212

In the first half of 2012, the entire balance of Convertible Senior Notes was converted to Common Shares or redeemed for cash. See Note 6.

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 in UNS 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, receiving an upfront payment of $5 million in 2009 and a $15 million, 6% secured promissory note. Millennium received the remaining principal amount of $15 million in 2012.

K-151

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The following recently issued accounting standards are not yet reflected in the financial statements:

•

The Financial Accounting Standards Board (FASB) issued a pronouncement that will require entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position (balance sheet) or subject to an agreement similar to a master netting arrangement. In addition, the pronouncement 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 and do not expect this pronouncement to have a material impact on our disclosures.

•

The FASB issued a rule which amends the guidance for impairment testing of indefinite-lived intangible assets. An entity will have the option to perform qualitative analysis to determine whether an indefinite-lived intangible asset may be impaired. If the qualitative assessment does not result in likely impairment, an entity will not be required to perform the quantitative impairment test. We will be required to comply in the first quarter of 2013; however, we do not expect this pronouncement to have a material impact on our financial statements as our indefinite-lived intangible assets, RECs, are currently recoverable under the RES as we use RECs to comply with renewable resources requirements.

•

The FASB decided in December 2012 to require new disclosures on items reclassified from AOCI. Companies will be required to disclose, in a single location, amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. We plan to present this information in a footnote. We will be required to comply in the first quarter of 2013 and do not expect this decision to have a material impact on our financial statements.

K-152

UNS 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:


	UNS Energy
	Years Ended December 31,
	2012			2011			2010
	-Thousands of Dollars-
Net Income	$	90,919		$	109,975		$	112,984
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense		141,303			133,832			128,215
Amortization Expense		35,784			30,983			28,094
Depreciation and Amortization Recorded to Fuel and O&M Expense		6,622			6,140			5,432
Amortization of Deferred Debt-Related Costs included in Interest Expense		3,000			3,985			3,753
Provision for Retail Customer Bad Debts		2,767			2,072			3,724
Use of Renewable Energy Credits for Compliance		5,935			5,695			4,745
Deferred Income Taxes		60,273			75,787			28,142
Deferred Tax Valuation Allowance		(9	)		(272	)		7,510
Pension and Retiree Expense		21,856			21,202			19,688
Pension and Retiree Funding		(29,058	)		(28,775	)		(27,742	)
Share-Based Compensation Expense		2,573			2,599			2,751
Excess Tax Benefit from Stock Options Exercised		(145	)		—			(3,338	)
Allowance for Equity Funds Used During Construction		(3,464	)		(4,496	)		(4,232	)
Increase (Decrease) to Reflect PPFAC/PGA Recovery		32,246			(4,932	)		(29,622	)
Competition Transition Charge Revenue Refunded		—			(35,958	)		(10,095	)
Partial Write-off of Tucson to Nogales Transmission Line		4,668			—			—
Liquidated Damages for Springerville Unit 3 Outage		2,050			—			—
Gain on Settlement of El Paso Electric Dispute		—			(7,391	)		—
Loss on Millennium’s Investments		—			—			9,936
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable		3,369			2,743			(8,851	)
Materials and Fuel Inventory		(39,429	)		(20,864	)		21,744
Accounts Payable		595			8,792			2,661
Income Taxes		(11,557	)		(2,739	)		24,470
Interest Accrued		6,922			14,344			14,354
Taxes Other Than Income Taxes		(58	)		2,857			2,442
Current Regulatory Liabilities		(684	)		2,644			2,788
Other		11,631			19,097			7,367

Net Cash Flows – Operating Activities	$	348,109		$	337,320		$	346,920

K-153

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	TEP
	Years Ended December 31,
	2012			2011			2010
	-Thousands of Dollars-
Net Income	$	65,470		$	85,334		$	108,260
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense		110,931			104,894			99,510
Amortization Expense		39,493			34,650			32,196
Depreciation and Amortization Recorded to Fuel and O&M Expense		5,384			4,509			3,855
Amortization of Deferred Debt-Related Costs included in Interest Expense		2,227			2,378			2,146
Provision for Retail Customer Bad Debts		1,871			1,447			2,506
Use of Renewable Energy Credits for Compliance		5,071			5,190			4,245
Deferred Income Taxes		45,232			59,309			24,897
Pension and Retiree Expense		19,289			18,816			17,454
Pension and Retiree Funding		(25,899	)		(25,878	)		(25,672	)
Share-Based Compensation Expense		2,029			2,027			2,131
Allowance for Equity Funds Used During Construction		(2,840	)		(3,842	)		(3,567	)
Increase (Decrease) to Reflect PPFAC Recovery		31,113			(6,165	)		(21,541	)
Competition Transition Charge Revenue Refunded		—			(35,958	)		(10,095	)
Partial Write-off of Tucson to Nogales Transmission Line		4,484			—			—
Liquidated Damages for Springerville Unit 3 Outage		2,050			—			—
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		(871	)		4,809			(5,156	)
Materials and Fuel Inventory		(38,384	)		(19,789	)		20,920
Accounts Payable		1,115			14,561			(447	)
Income Taxes		(11,421	)		(5,582	)		20,203
Interest Accrued		8,055			14,268			14,431
Taxes Other Than Income Taxes		905			2,282			1,469
Current Regulatory Liabilities		(3,040	)		303			2,500
Other		5,655			18,122			12,238

Net Cash Flows – Operating Activities	$	267,919		$	268,294		$	302,483

NON-CASH TRANSACTIONS

In 2012, the following non-cash transactions occurred:

•

UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Shares. See Note 6; and

•

TEP redeemed $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. See Note 6.

In 2010, the following non-cash transactions occurred:

•

TEP used a trustee to issue and redeem $37 million tax-exempt bonds. TEP had no cash receipts or payments as a result of this transaction. See Note 6; and

•

TEP deposited proceeds from the issuance of $100 million Pima County tax-exempt IDBs 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. See Note 6.

K-154

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:


	Years Ended December 31,
	2012		2011			2010
	-Thousands of Dollars-
(Decrease)/Increase to Utility Plant Accruals⁽¹⁾	$	4,813	$	(2,741	)	$	8,514
Net Cost of Removal of Interim Retirements⁽²⁾		35,983		31,626			4,592
Capital Lease Obligations⁽³⁾		11,967		15,162			16,630
Asset Retirement Obligations⁽⁴⁾		789		7,638			(1,872	)
UED Secured Term Loan Prepayments⁽⁵⁾		—		—			3,188

⁽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

See Note 1 for description of our related accounting policies and Note 11 for information related to the fair value of derivatives.

FINANCIAL IMPACT OF DERIVATIVES

Cash Flow Hedges

UNS Energy and TEP had liabilities related to cash flow hedges of $12 million as of December 31, 2012, and $14 million as of December 31, 2011. TEP’s power purchase swap agreement under which these hedges are entered into expires in 2015.

The after-tax unrealized gains and losses on cash flow hedge activity and amounts reclassified to earnings are reported in the statements of other comprehensive income. The amounts reclassified to earnings are reported in Long Term Debt Interest Expense, Capital Leases Interest Expense, and Purchased Power Expense in the statements of income. The amounts expected to be reclassified to earnings within the next twelve months is estimated to be $2 million.

Regulatory Treatment of Commodity Derivatives

We disclose unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than in the statements of other comprehensive income or in the income statements, as shown in the following table:


	UNS Energy							TEP
	Years Ended December 31,
	2012			2011		2010		2012			2011		2010
	-Millions of Dollars-
Increase (Decrease) to Regulatory Assets /Liabilities	$	(21	)	$	2	$	—	$	(6	)	$	2	$	(4	)

K-155

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The fair values of derivative assets and liabilities were as follows:


	UNS Energy						TEP
	Years Ended December 31,
	2012			2011			2012			2011
	-Millions of Dollars-
Assets	$	7		$	14		$	4		$	3
Liabilities		(15	)		(43	)		(4	)		(9	)

Net Assets (Liabilities)	$	(8	)	$	(29	)	$	—		$	(6	)

Derivative assets are included in Derivative Instruments and Other Non-Current Assets on the UNS Energy balance sheet and Other Current Assets and Other Non-Current Assets on the TEP balance sheet.

The realized losses on settled gas swaps that are fully recoverable through the PPFAC or PGA were as follows:


	UNS Energy									TEP
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	-Millions of Dollars-
Realized Losses on Gas Swaps	$	(22	)	$	(19	)	$	(23	)	$	(10	)	$	(7	)	$	(9	)

At December 31, 2012, UNS Energy and TEP had contracts that will settle through the fourth 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 UNS Energy and TEP as follows:


	UNS Energy									TEP
	2012			2011			2010			2012			2011			2010
	-Millions of Dollars-
Recorded in Wholesale Sales⁽¹⁾:
Forward Power Sales	$	22		$	41		$	53		$	5		$	14		$	27
Forward Power Purchases		(20	)		(46	)		(62	)		(6	)		(15	)		(34	)

Total Sales and Purchases Not Resulting in Physical Delivery	$	2		$	(5	)	$	(9	)	$	(1	)	$	(1	)	$	(7	)

⁽¹⁾ The amounts previously reported have been revised.

DERIVATIVE VOLUMES

At December 31, 2012, UNS Energy had gas swaps totaling 14,351 billion British thermal units (GBtu) and power contracts totaling 2,228 Gigawatt-hours (GWh), while TEP had gas swaps totaling 6,158 GBtu and power contracts totaling 820 GWh. At December 31, 2011, UNS Energy had gas swaps totaling 14,856 GBtu and power contracts totaling 3,147 GWh, while TEP had gas swaps totaling 6,855 GBtu and power contracts totaling 815 GWh.

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, 2012 and December 31, 2011.

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 subsequent measurement at fair value valuations.

K-156

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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 LOCs 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, 2012. It also shows LOCs posted and additional collateral to be posted if credit-risk related contingent features are triggered.


	UNS Energy		TEP
	December 31, 2012
	-Millions of Dollars-
Net Liability Position	$	36	$	10
LOCs		1		1
Additional Collateral to Post if Contingent Features Triggered		36		10

As of December 31, 2012, TEP had $15 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities, of which two counterparties individually composed greater than 10% of the total credit exposure. UNS Electric and UNS Gas had less than $1 million of such credit exposure related to its supply and hedging contracts.

K-157

UNS ENERGY, TEP, AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

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.


	UNS Energy
	First		Second		Third		Fourth
	-Thousands of Dollars- (Except Per Share Amounts)
2012
Operating Revenue	$	315,387	$	363,997	$	434,108	$	348,274
Operating Income		34,403		68,065		106,409		42,918
Net Income		6,476		26,273		50,664		7,506
Basic EPS		0.17		0.65		1.22		0.18
Diluted EPS		0.17		0.64		1.21		0.18
2011
Operating Revenue	$	338,177	$	365,141	$	441,557	$	333,827
Operating Income		44,820		71,290		123,760		41,837
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

EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.


	TEP
	First			Second		Third		Fourth
	-Thousands of Dollars-
2012
Operating Revenue	$	223,978		$	299,419	$	366,910	$	271,353
Operating Income		17,892			58,211		94,079		30,305
Net Income (Loss)		(1,461	)		21,910		44,569		452
2011
Operating Revenue	$	239,588		$	295,233	$	369,845	$	251,720
Operating Income		27,792			62,497		111,479		27,640
Net Income		4,704			25,158		53,912		1,560

The following tables reflect the quarterly impact of revisions on UNS Energy’s statements of income recorded in the fourth quarter of 2012 (See Note 1):


	UNS Energy
	2012 Three Months Ended
	March 31,				June 30,				September 30,
	As Reported		As Revised		As Reported		As Revised		As Reported		As Revised
	-Thousands of Dollars-
Income Statement
Operating Revenue	$	318,874	$	315,387	$	367,171	$	363,997	$	437,261	$	434,108
Operating Income ⁽¹⁾		34,395		34,403		68,059		68,065		106,409		106,409
	2011 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-
Income Statement
Operating Revenue	$	344,766	$	338,177	$	369,673	$	365,141	$	450,947	$	441,557	$	344,129	$	333,827
Operating Income ⁽¹⁾		44,820		44,820		71,290		71,290		123,760		123,760		41,802		41,837

⁽¹⁾	Includes immaterial reclassifications from Operating Expense to Other Expense to conform with current year presentation.

K-158

Schedule II—Valuation and Qualifying Accounts – UNS Energy


Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
	-Millions of Dollars-
Year Ended December 31,

Reserve for Uncollectible Accounts ⁽¹⁾
2012	$	16	$	4	$	13	$	7
2011	$	13	$	5	$	2	$	16
2010	$	13	$	4	$	4	$	13

Deferred Tax Assets Valuation Allowance ⁽²⁾
2012	$	7	$	—	$	—	$	7
2011	$	8	$	—	$	1	$	7
2010	$	—	$	8	$	—	$	8

Other ⁽³⁾
2012	$	6					$	9
2011	$	4					$	6
2010	$	2					$	4

⁽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 matters, and damages billable to third parties. As the Other reserves are not individually significant, additions and deductions need not be disclosed.

Schedule II—Valuation and Qualifying Accounts—TEP


Description	Beginning Balance		Additions- Charged to Income		Deductions		Ending Balance
	-Millions of Dollars-
Year Ended December 31,

Reserve for Uncollectible Accounts ⁽¹⁾
2012	$	14	$	3	$	12	$	5
2011	$	11	$	4	$	1	$	14
2010	$	11	$	3	$	3	$	11

Other ⁽²⁾
2012	$	4					$	8
2011	$	3					$	4
2010	$	—					$	3

⁽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 matters, and damages billable to third parties. As the Other reserves are not individually significant, additions and deductions need not be disclosed.

TEP had no deferred tax assets valuation allowance in the periods presented.

K-159

ITEM 9. – CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. – CONTROLS AND PROCEDURES

UNS Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UNS 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, 2012. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UNS 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 UNS 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, UNS Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UNS Energy and TEP’s disclosure controls and procedures are effective.

While UNS 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 UNS Energy or TEP’s internal control over financial reporting during the fourth quarter of 2012, that has materially affected, or is reasonably likely to materially affect, UNS Energy or TEP’s internal control over financial reporting.

UNS 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 UNS Energy’s and TEP’s 2012 Annual Report on Form 10-K, the Report of Independent Registered Public Accounting Firm for UNS 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.

K-160

PART III

ITEM 10. – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS

Directors – UNS Energy


Name	Age		Board Committee*		Director Since
Paul J. Bonavia		61		None		2009
Lawrence J. Aldrich		60		2,3		2000
Barbara M. Baumann		57		1,2,4		2005
Larry W. Bickle		67		3,5		1998
Harold W. Burlingame		72		2,3		1998
Robert A. Elliott		57		1,2,3,4,5		2003
Daniel W.L. Fessler		71		1,3,5		2005
Louise L. Francesconi		60		1,2,4		2008
Warren Y. Jobe		72		1,4,5		2001
Ramiro G. Peru		57		1,2,4		2008
Gregory A. Pivirotto		60		1,2,4		2008
Joaquin Ruiz		60		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 UNS Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. Prior to joining UNS 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*		Chairman and Executive Director, Arizona Business Coalition on Health, since October 2011; President and Chief Executive Officer of University Physicians Healthcare (UPH) from 2009 to 2010; Senior Vice President/Corporate Operations and General Counsel for UPH from 2007 to 2008; President of Aldrich Capital Company since January 2007; Chief Operating Officer of The Critical Path Institute from 2005 to 2007.

*Barbara M. Baumann*		President and Owner of Cross Creek Energy Corporation since 2003; Director of SM Energy Company since 2002; Member of the Board of Trustees of The Putnam Funds since 2010; Director of Cody Resources since 2010.

*Larry W. Bickle*		Director of SM Energy Company 1994; Retired private equity investor since 2007; Managing Director of Haddington Ventures, LLC 1997 to 2007; Non-executive Chairman of Quantum Natural Gas Storage, 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 Elliott Accounting since 1983; Vice Chairman of AAA of Arizona since 2012 and Director since 2007; Director and Corporate Secretary of Southern Arizona Community Bank from 1998 to 2010; Television Analyst/Pre-game Show Co-host for Fox Sports Arizona from 1998 to 2009; Chairman of the Board of the Tucson Airport Authority from January 2006 to January 2007; President and Chairman of the Board of the National Basketball Retired Players Association since 2011; Director of University of Arizona Foundation, a philanthropic organization, since 2011.

K-161


*Daniel W.L. Fessler*		President of the California Public Utility Commission from 1991 to 1996; Professor Emeritus of the University of California since 1994; Of Counsel for the law firm of Holland & Knight from 2003 to 2007; Partner in the law firm of LeBoeuf, Lamb, Greene & MacRae LLP from 1997 to 2003; previously served on the UNS Energy and TEP boards of directors from 1998 to 2003; Managing Principal of Clear Energy Solutions, LLC since December 2004.

*Louise L. Francesconi*		President of Raytheon Missile Systems from 1997 to 2008; Director of Stryker Corporation since July 2006; Chairman of the Board of Trustees for TMC Healthcare since 1999; and Director of Global Solar Energy, Inc. from 2008 to 2011.

*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 from June 2007 to December 2007; Executive Vice President and Chief Financial Officer of Phelps Dodge Corporation from 2004 to 2007; Senior Vice President and Chief Financial Officer of Phelps Dodge Corporation from 1999 to 2004; Director of WellPoint, Inc. since 2004.

*Gregory A. Pivirotto*		Adjunct Professor at the University of Arizona College of Law since 2013; President and Chief Executive Officer and Director of University Medical Center Corporation, in Tucson, AZ from 1994 to 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


Name	Age	Director Since
Paul J. Bonavia	61	2009
Michael J. DeConcini	48	2009
David G. Hutchens	46	2011
Kevin P. Larson	56	2009


*Paul J. Bonavia*		Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. Prior to joining UNS 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 UNS 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.

K-162


*David G. Hutchens*		Mr. Hutchens has served as President of UNS Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UNS 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 UNS 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 UNS Energy and TEP since September 2005. Mr. Larson is also Treasurer of UNS 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 UNS Energy and TEP

See Item 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 UNS 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, 2012, which information is incorporated herein by reference.

ITEM 11. – EXECUTIVE COMPENSATION

Information concerning Executive Compensation will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.

ITEM 12. – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

General

At February 13, 2013, UNS Energy had outstanding 41.4 million shares of Common Stock. At February 13, 2013, the number of shares of Common Stock beneficially owned by all directors and officers of UNS Energy as a group amounted to less than 1% of the outstanding Common Stock.

At February 13, 2013, UNS 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 UNS Energy will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.

Security Ownership of Management

Information concerning the security ownership of the Directors and Executive Officers of UNS Energy will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.

K-163

Securities Authorized for Issuance Under Equity Compensation Plans

Information concerning securities authorized for issuance under equity compensation plans will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, 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 UNS Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks, and Insider Participation in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, 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 UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.

PART IV

ITEM 15. – EXHIBITS AND FINANCIAL STATEMENT SCHEDULE


	Page
(a) (1) Consolidated Financial Statements as of December 31, 2012 and 2011 and for Each of the Three Years in the Period Ended December 31, 2012

UNS Energy Corporation
Report of Independent Registered Public Accounting Firm		80
Consolidated Statements of Income		82
Consolidated Statements of Comprehensive Income		83
Consolidated Statements of Cash Flows		84
Consolidated Balance Sheets		85
Consolidated Statements of Capitalization		87
Consolidated Statements of Changes in Stockholders’ Equity		88
Notes to Consolidated Financial Statements		96

Tucson Electric Power Company
Report of Independent Registered Public Accounting Firm		81
Consolidated Statements of Income		89
Consolidated Statements of Comprehensive Income		90
Consolidated Statements of Cash Flows		91
Consolidated Balance Sheets		92
Consolidated Statements of Capitalization		94
Consolidated Statements of Changes in Stockholder’s Equity		95
Notes to Consolidated Financial Statements		96

(2) Financial Statement Schedule
Schedule II
Valuation and Qualifying Accounts		158

(3) Exhibits

Reference is made to the Exhibit Index commencing on page 167.

K-164

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.


	UNS ENERGY CORPORATION

Date: February 26, 2013	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief 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 26, 2013				/s/ Paul J. Bonavia*
				Paul J. Bonavia
				Chairman of the Board and Chief Executive Officer
				(Principal Executive Officer)

Date: February 26, 2013				/s/ Kevin P. Larson
				Kevin P. Larson
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)

Date: February 26, 2013				/s/ Karen G. Kissinger*
				Karen G. Kissinger
				Vice President, Controller, and Chief Compliance Officer
				(Principal Accounting Officer)

Date: February 26, 2013				/s/ Lawrence J. Aldrich*
				Lawrence J. Aldrich
				Director

Date: February 26, 2013				/s/ Barbara M. Baumann*
				Barbara M. Baumann
				Director

Date: February 26, 2013				/s/ Larry W. Bickle*
				Larry W. Bickle
				Director

Date: February 26, 2013				/s/ Harold W. Burlingame*
				Harold W. Burlingame
				Director

Date: February 26, 2013				/s/ Robert A. Elliott*
				Robert A. Elliott
				Director

K-165


Date: February 26, 2013		/s/ Daniel W.L. Fessler*
		Daniel W.L. Fessler
		Director

Date: February 26, 2013		/s/ Louise L. Francesconi*
		Louise L. Francesconi
		Director

Date: February 26, 2013		/s/ Warren Y. Jobe*
		Warren Y. Jobe
		Director

Date: February 26, 2013		/s/ Ramiro Peru*
		Ramiro Peru
		Director

Date: February 26, 2013		/s/ Gregory A. Pivirotto*
		Gregory A. Pivirotto
		Director

Date: February 26, 2013		/s/ Joaquin Ruiz*
		Joaquin Ruiz
		Director

Date: February 26, 2013	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

K-166

SIGNATURES


	TUCSON ELECTRIC POWER COMPANY

Date: February 26, 2013	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer


Date: February 26, 2013		/s/ Paul J. Bonavia*
		Paul J. Bonavia
		Chairman of the Board and Chief Executive Officer
		(Principal Executive Officer)

Date: February 26, 2013		/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

Date: February 26, 2013		/s/ Karen G. Kissinger*
		Karen G. Kissinger
		Vice President, Controller, and Chief Compliance Officer
		(Principal Accounting Officer)

Date: February 26, 2013		/s/ Michael J. DeConcini*
		Michael J. DeConcini
		Director

Date: February 26, 2013		/s/ David G. Hutchens*
		David G. Hutchens
		Director

Date: February 26, 2013	By:	/s/ Kevin P. Larson
		Kevin P. Larson
		As attorney-in-fact for each of the persons indicated

K-167

EXHIBIT INDEX



*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 UNS Energy, as amended. (Form 8-K, dated May 10, 2012, File No. 1-13739 – Exhibit 3.1).

*3(d)	—	Revised and restated bylaws of UNS 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-168



*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)).

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*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)).

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*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)).

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*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)	—	Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-13739, Exhibit 4(a)).

*4(l)(2)	—	Loan Agreement, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-13739, Exhibit 4(b)).

*4(m)(1)	—	Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-13739, Exhibit 4(a)).

*4(m)(2)	—	Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-13739, Exhibit 4(b)).

4(n)	—	Reserved.

*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.

*4(p)(1)	—	Note Purchase and Guaranty Agreement dated August 11, 2003 among UNS Gas, Inc., UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 — Exhibit 99.2).

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*4(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., 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)	—	Reserved.

*4(s)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UNS 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 UNS 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 UNS 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)).

*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)).

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*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 and 3.85% Notes due 2023 (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)).

*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)).

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*10(a)(8)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(8)).

*10(a)(9)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(9)).

*10(a)(10)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(10)).

*10(a)(11)	—	Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(11)).

*10(a)(12)	—	Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(12)).

*10(a)(13)	—	Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(13)).

*10(a)(14)	—	Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(14)).

*10(a)(15)	—	Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbell Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar). (Form S-4 Registration No. 33-52860 — Exhibit 10(f)(15)).

*10(a)(16)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(12)).

*10(a)(17)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine 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)).

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*10(a)(18)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(14)).

*10(a)(19)	—	Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(19)).

*10(a)(20)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 —Exhibit 10(f)(20)).

*10(a)(21)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(21)).

*10(a)(22)	—	Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(22)).

*10(a)(23)	—	Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(15)).

*10(a)(24)	—	Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(16)).

*10(a)(25)	—	Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(25)).

*10(a)(26)	—	Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(26)).

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*10(a)(27)	—	Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732 — Exhibit 10(f)(27)).

*10(b)(1)	—	Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(1)).

*10(b)(2)	—	Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(2)).

*10(b)(3)	—	Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(3)).

*10(b)(4)	—	Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(4)).

*10(b)(5)	—	Lease Supplement No.1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(5)).

*10(b)(6)	—	Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 — Exhibit 10(g)(6)).

*10(b)(7)	—	Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and TEP and San Carlos, jointly and severally, as Lessee. (Form S-1, Registration No. 33-55732 — Exhibit 10(g)(7)).

*10(b)(8)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(8)).

*10(b)(9)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and 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)).

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*10(b)(10)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(10)).

*10(b)(11)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(11)).

*10(b)(12)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(12)).

*10(b)(13)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(13)).

*10(b)(14)	—	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(a)).

*10(b)(15)	—	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit, LLC as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(b)).

*10(b)(16)	—	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(c)).

*10(b)(17)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(d)).

*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)).

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*10(b)(19)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(f)).

*10(b)(20)	—	Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.1).

*10(b)(21)	—	Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Selco Service Corporation as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.2).

*10(b)(22)	—	Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Emerson Finance LLC as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.3).

*10(b)(23)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.4).

*10(b)(24)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement , dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Selco Service Corporation as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.5).

*10(b)(25)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement , dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Emerson Finance LLC as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.6).

*10(d)	—	Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1. (Form S-1, Registration No. 33-55732 — Exhibit 10(u)).

*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)).

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*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)	—	Reserved.

10(i)	—	Reserved.

10(j)	—	Reserved.

10(k)	—	Reserved.

10(m)	—	Reserved.

+*10(n)	—	Amended and Restated UNS Energy 1994 Outside Director Stock Option Plan of UNS Energy. (Form S-8 dated September 9, 2002, File No. 333-99317).

10(o)	—	Reserved.

+*10(p)	—	UNS Energy 2006 Omnibus Stock and Incentive Plan. (Form S-8 dated January 31, 2007, File No. 333-140353).

10(q)	—	Reserved.

+*10(r)	—	Management and Directors Deferred Compensation Plan II of UNS Energy. (Form S-8 dated December 30, 2008, File No. 333-156491).

10(s)	—	Reserved.

+*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)	—	Reserved.

+*10(v)	—	UNS Energy Corporation 2011 Omnibus Stock and Incentive Plan. (Form 8-K dated May 10, 2011, File 1-13739 – Exhibit 10.1).

12(a)	—	Computation of Ratio of Earnings to Fixed Charges – UNS 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 – UNS Energy.

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23(b)	—	Consent of Independent Registered Public Accounting Firm – TEP.

24(a)	—	Power of Attorney – UNS Energy.

24(b)	—	Power of Attorney – TEP.

31(a)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Paul J. Bonavia.

31(b)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS 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 UNS Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language):

		(a)	UNS Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Balance Sheets, (v) Consolidated Statements of Capitalization, (vi) Consolidated Statements of Changes in Stockholders’ Equity; and

		(b)	Notes to Consolidated Financial Statements.

(*)	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.

***

XBRL materials for Tucson Electric Power Company are deemed not filed or part of a registration statement or prospectus for the purposes of Section 11 or 12 of the Securities Act of 1933, as amended, and are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

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