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EXPLANATORY NOTEDEFINITIONS

The abbreviations and acronyms used in the Annual Report on2012 Form 10-K are defined below:

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PART I

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

BUSINESS SEGMENT CONTRIBUTIONS

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

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.

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.

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. SeeRates and Regulation, below for more information regarding the status of retail competition in Arizona.

Wholesale Business

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

Generally, TEP commits to future sales based on expected excess generating capability, forward prices, and generation costs, using a diversified portfolio approach to provide a balance between long-term, mid-term, and spot energy sales. 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:

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. SeeRates and Regulation,below.

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

GENERATING AND OTHER RESOURCES

At December 31, 2012, TEP owned or leased 2,267 MW of net generating capability, as set forth in the following table:

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. SeeItem 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.

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. SeeRates and Regulation, Renewable Energy Standard and Tariffbelow for more information.

Purchases and Interconnections

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

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

Peak Demand and Resources

Peak demand 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:

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.

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 year endedremaining 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.

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 seeItem 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. SeeItem 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.

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. SeeItem 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, originallythe 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.

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. SeeItem. 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. SeeItem. 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.

TEP’S UTILITY OPERATING STATISTICS

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.

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.

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.

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.

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.

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.

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

RATES AND REGULATION

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. SeePurchased 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.

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. SeeItem. 1 – Business, TEP, Environmental Matters, for more information.

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is a vertically integrated electric utility company serving approximately 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. SeeRates and Regulation, 2010 UNS Electric Rate Order, below for more information.

UNS Electric also owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona. Valencia consists of four gas and diesel-fueled combustion turbine units and provides approximately 62 MW of peaking resources. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas.

Renewable Energy Resources

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

Future Generating Resources

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

Transmission

UNS Electric imports the power generated at BMGS into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has 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. SeeItem 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. SeeItem 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. SeeItem 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.

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.

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, seeTEP, 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. SeeItem. 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. SeeItem. 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. SeeItem 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.

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:

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 on March 1, 2011,(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 being filed foraccessible as follows: At the purposeUNS Energy main page, select Investors from the menu shown at the top of amending Item 15- Exhibits and Financial Statement Schedules in order to (i) amend the consent of our Independent Registered Public Accounting Firm, PricewaterhouseCoopers, and (ii) correct certain clerical errorspage; next select SEC filings from the menu shown on the Exhibit Index.

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.

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 March 1, 2011.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.

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.

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.

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:

K/A-1