UNITED STATES

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

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

Rates and Regulation of TEP, UNS Gas and UNS Electric

The Arizona Corporation Commission (ACC) regulates portions of TEP, UNS Gas and UNS Electric’s utility accounting practices and energy rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. Our regulated utility Retail Rates for retail electric and natural gas service are determined on a “cost of service” basis. Retail Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for our utility businesses to earn a reasonable return on rate base. Rate base is generally determined by reference to the original cost (net of depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and other items plus a working capital component. Over time, additions to utility plant in service increase rate base while depreciation and retirements of utility plant reduce rate base.

Retail Rates charged by TEP, UNS Gas and UNS Electric also include pass-through mechanisms that allow each utility to recover the actual costs of its fuel, transmission, and energy purchases.

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

TEP

TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UniSource Energy. In 2011, TEP’s electric utility operations contributed 77% of UniSource Energy’s operating revenues and comprised 82% of its assets.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to approximately 404,000 retail customers in southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately one million people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells electricity to other utilities and power marketing entities in the western United States.

Retail Customers

TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases and other governmental entities. TEP’s retail sales are influenced by several factors, including economic conditions, seasonal weather patterns, demand side management (DSM) initiatives and increasing use of energy efficient products, and opportunities for customers to generate their own electricity.

Customer Base

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

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

Two of TEP’s largest retail customers are in the copper mining industry. TEP’s kilowatt-hour (kWh) sales to mining customers depend on a variety of factors including the market price of copper, the Retail Rate paid by mining customers, and the mines’ potential development of their own electric generation resources. TEP’s kWh sales to mining customers increased by 0.3% in 2011 and 1.4% in 2010 as a result of increased production due to high copper prices.

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

Sales Volumes

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

Energy Service Providers

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

Wholesale Business

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

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

Long-Term Sales

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

Short-Term Sales

Forward contracts commit TEP to sell a specified amount of capacity or energy at a specified price over a given period of time, typically for one-month, three-month or one-year periods. TEP also engages in short-term sales by selling energy in the daily or hourly markets at fluctuating spot market prices and making other non-firm energy sales. All revenues from short-term wholesale sales offset fuel and purchased power costs and are passed through to TEP retail customers. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. SeeRates and Regulation,below.

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

GENERATING AND OTHER RESOURCES

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

Springerville Generating Station

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

The terms of the Springerville Unit 1 Leases, which include a 50% interest in the Springerville Common Facilities, expire in 2015 but have optional fair market value renewal and purchase provisions. In 1985, TEP sold and leased back the remaining 50% interest in the Springerville Common Facilities.

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

The Springerville Common Facilities Leases, which expire in 2017 and 2021, have optional fair market value renewal options as well as a fixed-price purchase provision. The fixed prices to acquire the leased interests in the Springerville Common Facilities are $38 million in 2017 and $68 million in 2021.

In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. Since entering the lease, TEP purchased a 13% ownership interest in the Springerville Coal Handling Facilities. The terms of the Springerville Coal Handling Facilities Leases expire in 2015 but have optional fixed-rate renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million.

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

Sundt Generating Station

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

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

Renewable Energy Resources

Owned Resources

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

Power Purchase Agreements

In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 130 MW of capacity from solar resources, 50 MW of capacity from wind resources and 2 MW of capacity from a landfill gas generation plant. As of December 31, 2011, approximately 2 MW of contracted solar resources and 50 MW of contracted wind resources were operational. The remaining resources are expected to be developed over the next several years. The solar PPAs contain options that would allow TEP to purchase all or part of the related project at a future period. SeeRates and Regulation, Renewable Energy Standard and Tariffbelow for more information.

Purchases and Interconnections

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

TEP typically uses generation from its gas-fired units, supplemented by purchased power, to meet the summer peak demands of its retail customers. Some of these PPAs are price-indexed to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure with fixed price contracts for a maximum of three years. TEP also purchases energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when doing so is more economical than generating its own energy.

TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as plant outages and system disturbances, and reduce the amount of reserves TEP is required to carry.

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

Springerville Units 3 and 4

Springerville Units 3 and 4 are each approximately 400 MW coal-fired generating facilities that are operated, but not owned by TEP. These facilities are located at the same site as TEP’s Springerville Units 1 and 2. The owners of Units 3 and 4 compensate TEP for operating the facilities and pay an allocated portion of the fixed costs related to the Springerville Common Facilities and Coal Handling Facilities. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4.

Peak Demand and Resources

Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand varies from year-to-year due to weather, economic conditions and other factors. TEP’s retail peak demand declined from 2008 to 2010 due primarily to weak economic conditions and the implementation of energy efficiency programs.

The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s total margin is the difference between total energy resources and coincident peak demand, and

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

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

Future Generating Resources

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

FUEL SUPPLY

Fuel Summary

Fuel cost and usage information is provided below:

Coal

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and Colorado. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices. The average cost per ton of coal, including transportation, for 2011, 2010 and 2009 was $46.64, $41.99, and $39.81, respectively.

TEP Operated Generating Facilities

TEP is the operator, and sole owner (or lessee), of the Springerville Units 1 and 2 and Sundt Unit 4. The coal supplies for Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects coal reserves to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their presently estimated remaining lives.

The coal supplies for Sundt are transported approximately 1,300 miles by railroad from Colorado. Prior to 2010, Sundt Unit 4 was predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with methane, a renewable energy resource, piped in from a nearby landfill. Since 2010, TEP has fueled Sundt Unit 4 with both coal and natural gas depending on which resource is most economic. In 2012, TEP expects to fuel Sundt Unit 4 with natural gas. See Note 4 for more information.

Generating Facilities Operated by Others

TEP also participates in jointly-owned coal-fired generating facilities at the Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo) and the San Juan Generating Station (San Juan). Four Corners, which is operated by Arizona Public Service (APS), and San Juan, which is operated by PNM, are mine-mouth generating stations located adjacent to the coal reserves. Navajo, which is operated by SRP, obtains its coal supply from a nearby coal mine and a dedicated rail delivery system. The coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining presently estimated lives of the stations.

Natural Gas Supply

TEP typically uses generation from its facilities fueled by natural gas, in addition to energy from its coal-fired facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs. TEP purchases gas from Southwest Gas Corporation under a retail tariff for North Loop’s 95 MWs of internal combustion turbines and receives distribution service under a transportation agreement for DeMoss Petrie, a 75 MW internal combustion turbine. TEP purchases capacity from El Paso Natural Gas Company (EPNG) for transportation from the San Juan and Permian Basins to its Sundt plant under a contract that expires in April 2013, with right-of-first-refusal for continuation thereafter. TEP also buys gas from third-party suppliers for Sundt and DeMoss Petrie.

TEP purchases gas transportation for Luna from EPNG from the Permian Basin to the plant site under an agreement effective through January 2017, with right-of-first-refusal for continuation thereafter. TEP purchases gas for its share of Luna from various suppliers in the Permian Basin region.

TRANSMISSIONACCESS

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

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

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement initiated in 2000 for the joint construction of a 60-mile 345kV transmission line from Tucson to Nogales, Arizona. The project development agreement was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales and surrounding Santa Cruz County by building a second transmission line to Nogales. TEP received approval from the ACC for construction along a specific route in 2002. However, due to an impasse with the US Forest Service, UNS Electric has taken alternative steps towards improving service reliability in the area.

As of December 31, 2011, TEP had capitalized $11 million related to the project, including $2 million of land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes that cost recovery is probable for prudent and reasonably incurred costs related to the project as a consequence of the ACC’s requirement for a second transmission line serving Santa Cruz County.

RATES AND REGULATION

Purchased Power and Fuel Adjustment Clause

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

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

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

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

Base Rate Increase Moratorium

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

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

Renewable Energy Standard and Tariff

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

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

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

Electric Energy Efficiency Standards and Decoupling

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

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

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

Decoupling

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

Retail Electric Competition Rules

In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC Rules that enabled ESPs to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2005. In 2008, the ACC opened an administrative proceeding to address the Rules. Unless and until the ACC clarifies the Rules or authorizes alternative ESPs to provide retail electric service, and ESPs offer to provide energy in TEP’s service area, it is not possible for TEP’s retail customers to use alternative ESPs. We cannot predict what changes, if any, the ACC will make to the Rules.

TEP’S UTILITY OPERATING STATISTICS

ENVIRONMENTAL MATTERS

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

Clean Air Act Requirements

TEP generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $8 million in 2011, $18 million in 2010 and $24 million in 2009 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan described below. TEP expects to capitalize environmental compliance costs of $7 million in 2012 and $25 million in 2013.

TEP recorded operating expenses of $12 million in 2011, $14 million in 2010 and $13 million in 2009 related to environmental compliance. TEP expects to record $14 million in operating expenses related to environmental compliance in 2012. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may reduce operating efficiency.

TEP has sufficient Emission Allowances to comply with acid rain SO₂ regulations.

EPA Information Request

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

The EPA uses information obtained from such requests to determine if additional action is necessary. TEP can neither predict whether the EPA will take further action at Sundt nor project the impact of any such action.

Hazardous Air Pollutant Requirements

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

Navajo

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

Springerville

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

San Juan

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

Sundt

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

Four Corners

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

Climate Change

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

While the debate over the direction of domestic climate policy continues on the national level, several states have developed state-specific policies or regional initiatives to reduce GHG emissions. In 2007, the governors of several western states, including the then-governor of Arizona, signed the Western Regional Climate Action Initiative (the Western Climate Initiative) which directed their respective states to develop a regional target for reducing greenhouse gases. The states in the Western Climate Initiative announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020. In 2008, the Western Climate Initiative participants submitted their design recommendation for the Western Climate Initiative cap-and-trade program for greenhouse gas emissions, with an implementation date set for 2012.

In 2010, New Mexico adopted regulations limiting GHG emissions from power plants and providing for participation in the Western Climate Initiative. Several parties filed petitions to repeal those regulations and the New Mexico Environmental Improvement Board held hearings on the repeal petitions in November and December 2011. In February 2012, the New Mexico Environmental Improvement Board repealed some, but not all, of the GHG regulations and will deliberate on the repeal of the remaining regulations in March 2012. We cannot predict if, or when, the remaining regulations will impact the generating output or cost of operations at San Juan and Luna.

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

Regional Haze Rules

The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA for approval. Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions. The EPA is the lead regulatory agency for these plants in terms of regional haze planning.

Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of the San Juan, Four Corners and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants. TEP cannot predict the ultimate outcome of these matters.

San Juan

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

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

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

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

Four Corners

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

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the National Renewable Energy Laboratory (NREL) in partnership with the Department of the Interior and the Department of Energy. The report addresses potential energy, environmental and economic issues related to compliance with the regional haze rule. The report was submitted to the EPA in January 2012. A final BART rule is expected later in 2012. If the EPA determines that SCR is required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital expenditure for the required baghouses would be approximately $43 million. The cost of required pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.

Coal Combustion Residuals

In 2010, the EPA published its proposed regulations governing the handling and disposal of coal ash and other coal combustion residuals (CCRs). The EPA has proposed regulating CCRs as either non-hazardous solid waste or hazardous waste. The hazardous waste alternative would require additional capital investments and operational costs associated with storage and handling at plants and transportation to the disposal locations. Both the hazardous waste and non-hazardous solid waste alternatives would require liners for new ash landfills or expansions to existing ash landfills. The rules will apply to CCRs produced by all of TEP’s coal-fired generating assets. San Juan may also be subject to separate regulations being drafted by the Office of Surface Mining Reclamation and Enforcement because it disposes of CCRs in surface mine pits.

The EPA has not yet indicated a preference for an alternative. Each option would allow CCRs to be beneficially reused or recycled as components of other products. The EPA has indicated that it will issue a final rule by the end of 2012. The financial impact of this rulemaking to TEP, if any, cannot be determined at this time.

Ozone National Ambient Air Quality Standard

In September 2011, President Obama ordered the EPA to withdraw its reconsideration of the 2008 National Ambient Air Quality Standard for Ozone. The ozone standard is scheduled to be updated in 2013 as required by the Clean Air Act.

UNSGAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 148,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as Santa Cruz County in southeastern Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 700,000. UNS Gas’ customer base is primarily residential. Sales to residential customers provided approximately 60% of total revenues in 2011, while sales to other retail customer classes accounted for about 36% of total revenues.

UNS Gas’ annual retail customer growth rate was less than 1% from 2009 through 2011. In 2012, we expect UNS Gas’ retail customer base to increase by less than 1%.

GAS SUPPLY AND TRANSMISSION

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

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

With EPNG, the average daily capacity right of UNS Gas is approximately 655,000 therms per day, with an average of 1,095,000 therms per day in the winter season (November through March) to serve its northern and southern Arizona service territories. UNS Gas has capacity rights of 250,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline. The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman and also the Griffith Power Plant in Mohave County.

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

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

RATES AND REGULATION

2011 UNS Gas Rate Filing

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

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

2010 UNS Gas Rate Order

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

Purchased Gas Adjustor (PGA)

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

The PGA mechanism has two components, the PGA factor and the PGA surcharge or surcredit. The PGA factor is a mechanism that calculates the twelve-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a 12-month period. The annual cap on the maximum increase in the PGA factor is $0.15 per therm in a 12-month period.

At any time UNS Gas’ PGA balancing account, called the PGA bank balance, is under-recovered, UNS Gas may request a PGA surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed-to-customers basis, UNS Gas is required to make a filing with the ACC to determine how the over-collected balance should be returned to customers. On December 31, 2011, the PGA bank balance was over-collected by $8 million on a billed-to-customers basis.

Gas Utility Energy Efficiency Standards and Decoupling

In August 2010, the ACC approved new Gas Utility Energy Efficiency Standards (Gas EE Standards) designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2011, the Gas EE Standards targeted total retail therm savings equal to 0.5% of 2010 sales; UNS Gas estimates its total savings in 2011 were 0.25%. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.

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

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

ENVIRONMENTAL MATTERS

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

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

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

POWER SUPPLY AND TRANSMISSION

Purchased Energy

UNS Electric relies on a portfolio of long, intermediate and short-term purchases to meet customer load requirements.

Generating Resources

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

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

Renewable Energy Resources

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

Future Generating Resources

UNS Electric invested $5 million in 2011 in company-owned solar PV capacity and expects to invest approximately $5 million annually from 2012 through 2014 to build about 1.25 MW per year in company-owned solar PV capacity. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff for more information.

Transmission

UNS Electric imports the power generated at BMGS into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has a network transmission service agreement for its primary transmission capacity with WAPA for the Parker-Davis system that expires in August 2016. UNS Electric also has a long-term electric point-to-point transmission capacity agreement with WAPA for the Southwest Intertie system that expires in June 2016.

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

RATES AND REGULATION

2010 UNS Electric Rate Order

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

The 2010 UNS Electric Rate Order approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. FERC approved the purchase in June 2011.

The 2010 UNS Electric Rate Order also approved a plan for UNS Electric to invest $5 million each year from 2011 through 2014 in solar projects that would be owned by UNS Electric. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff, for more information.

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

Purchased Power and Fuel Adjustment Clause

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

Renewable Energy Standard and Tariff

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

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

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

Energy Efficiency Standards and Decoupling

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

ENVIRONMENTAL MATTERS

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

OTHER NON-REPORTABLESEGMENTS

Millennium

As of December 31, 2011, Millennium had assets of $20 million including a $15 million note receivable (seeSabinasbelow), and cash and cash equivalents of $5 million. In total, Millennium’s assets represented less than 1% of UniSource Energy’s total consolidated assets. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other Non-Reportable Business Segments,for more information.

Sabinas

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

Millennium received an upfront $5 million cash payment in January 2009. Other key terms of the transaction included a three-year, 6% interest-bearing, collateralized $15 million note, which matures in June 2012.

SES

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

EMPLOYEES (Asof December 31, 2011)

TEP had 1,391 employees, of which approximately 51% are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A collective bargaining agreement between the IBEW and TEP expires in January 2013.

UNS Gas had 187 employees, of which 108 employees were represented by IBEW Local No. 1116 and 5 employees were represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2012 and February 2014, respectively.

UNS Electric had 154 employees, of which 27 employees were represented by the IBEW Local No. 387 and 96 employees were represented by the IBEW Local No. 769. The existing agreements with the IBEW Local No. 387 and No. 769 expire in February 2014 and June 2013, respectively.

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

EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers – UniSource Energy and TEP

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

SEC REPORTS AVAILABLE ON UNISOURCE ENERGY’S WEBSITE

UniSource Energy and TEP make available their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practical after they electronically file them with, or furnish them to, the Securities and Exchange Commission (SEC). These reports are available free of charge through UniSource Energy’s website address:http://www.uns.com. A link from UniSource Energy’s website to these SEC reports is accessible as follows: At the UniSource Energy main page, select Investors from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page. UniSource Energy’s code of ethics, which applies to the Board of Directors and all officers and employees of UniSource Energy and its subsidiaries, and any amendments or any waivers made to the code of ethics, is also available on UniSource Energy’s website.

Information contained at UniSource Energy’s website is not part of any report filed with the SEC by UniSource Energy or TEP.

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

REVENUES

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

Economic conditions have contributed significantly to a reduction in TEP’s retail customer growth and lower energy usage by the company’s residential, commercial and industrial customers. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 1% per year in 2008 through 2011 compared with average increases of approximately 2% per year from 2003 to 2007. In 2011, total retail kWh sales were 0.4% above 2010 levels. TEP estimates that a 1% decrease in annual retail sales could reduce pre-tax net income and pre-tax cash flows by approximately $6 million.

Similar impacts were felt at UNS Gas and UNS Electric. Annual increases in the number of retail customers at both companies remained below 1% in 2008 through 2011 compared with average annual growth rates of 3% from 2003 to 2007. We estimate that a 1% decrease in annual retail sales at UNS Gas and UNS Electric could reduce pre-tax net income and pre-tax cash flows by less than $1 million.

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

Under the terms of the 2008 TEP Rate Order, TEP is prohibited from submitting an application for new Base Rates before June 30, 2012. New Base Rates would not be in effect until approval by the ACC, which is not anticipated to occur before the third quarter of 2013. If the cost of serving TEP’s customers rises more quickly than the revenues it collects from customers, TEP’s results of operations, net income and cash flows could be negatively impacted.

New technological developments and the implementation of new Energy Efficiency Standards may have a significant impact on retail sales, which could negatively impact UniSource Energy’s results of operations, net income and cash flows.

Heightened awareness of energy costs has increased demand for products intended to reduce consumers’ use of electricity. TEP and UNS Electric also are promoting DSM programs designed to help customers reduce their energy use, and these efforts will increase significantly under new energy efficiency rules approved in 2010 by the ACC. Unless the ACC makes a specific provision for the recovery of usage-based revenues lost to these energy efficiency programs, the reduced retail sales that would result from the success of these efforts would negatively impact the results of operations, net income and cash flows of TEP and UNS Electric.

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

TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during Tucson’s hot summer weather. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in its retail service territory. UNS Electric’s earnings follow a similar pattern, while UNS Gas’ sales peak in the winter during home heating season. Cool summers or warm winters may reduce customer usage at all three companies, adversely affecting operating revenues, cash flows and net income by reducing sales. TEP estimates that a 1% decrease in annual retail sales could reduce pre-tax net income and pre-tax cash flows by approximately $6 million. We estimate that a 1% decrease in annual retail sales at UNS Gas and UNS Electric could reduce pre-tax net income and pre-tax cash flows by less than $1 million.

REGULATORY

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

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

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

Changes in federal energy regulation may negatively affect the results of operations, net income and cash flows of TEP, UNS Gas and UNS Electric.

TEP, UNS Gas and UNS Electric are subject to the impact of comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric and gas utility industries and the ways in which these industries are regulated. UniSource Energy’s electric utility subsidiaries are subject to regulation by the FERC. The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale prices.

ENVIRONMENTAL

UniSource Energy’s utility subsidiaries are subject to numerous environmental laws and regulations that may increase their cost of operations or expose them to environmentally-related litigation and liabilities.Many of these regulations could have a significant impact on TEP due to its reliance on coal as its primary fuel for energy generation.

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

These laws and regulations can contribute to higher capital, operating and other costs, particularly with regard to enforcement efforts focused on existing power plants and new compliance standards related to new and existing power plants. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, authorizations and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable laws and regulations may result in litigation, and the imposition of fines, penalties and a requirement for costly equipment upgrades by regulatory authorities.

We cannot provide assurance that existing environmental laws and regulations will not be revised or that new environmental laws and regulations will not be adopted or become applicable to our facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on our results of operations, particularly if those costs are not fully recoverable from our ratepayers. TEP’s obligation to comply with the EPA’s BART determinations as a participant in the San Juan, Four Corners and Navajo plants, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to meet their obligations and continue their participation in these plants. TEP cannot predict the ultimate outcome of these matters.

TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generating stations. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.

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

Based on the finding by the EPA in December 2009 that emissions of greenhouse gases endanger public health and welfare, the agency is in the process of regulating greenhouse gas emissions. In addition, there are proposals and ongoing studies at the state, federal and international levels to address global climate change that could also result in the regulation of carbon dioxide (CO₂) and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. In 2011, 73% of TEP’s total energy resources came from its coal-fueled generating facilities.

Reductions in CO₂ emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers.

Any future legislation or regulation addressing climate change could produce a number of other results including costly modifications to, or reexamination of the economic viability of, our existing coal plants; changes in the overall fuel mix of our generating fleet; or additional costs to fund energy efficiency activities. The impact of legislation or regulation to address global climate change would depend on the specific terms of those measures and cannot be determined at this time.

FINANCIAL

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

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

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

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

As of February 21, 2012, TEP had $215 million of tax-exempt variable rate debt obligations, $50 million of which was hedged with a fixed for floating interest rate swap through September 2014. The interest rates are set weekly with maximum interest rates of 20% on $178 million of debt obligations and 10% on the remaining $37 million. The average weekly interest rate ranged from 0.05% to 0.34% in 2011. A 100 basis point increase in the average interest rates on this debt over a twelve-month period would increase TEP’s interest expense by approximately $2 million.

UniSource Energy, TEP, UNS Gas and UNS Electric also are subject to risk resulting from changes in the interest rate on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on a spread over LIBOR or an Alternate Base Rate. Each of these agreements is a committed facility and expires in November 2016.

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

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

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

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

The maximum amount TEP may use under its revolving credit facility is $200 million. As of February 21, 2012, TEP had $114 million available to borrow under its revolving credit facility. The maximum amount UNS Gas or UNS Electric may use under their revolving credit facility is $70 million, so long as the combined amount drawn by

both companies does not exceed $100 million. As of February 21, 2012, UNS Gas and UNS Electric had $64 million and $70 million, respectively, to borrow under their revolving credit facility. From time to time, TEP, UNS Gas and UNS Electric use their respective revolving credit facilities to post collateral. If additional collateral is required, it may negatively impact TEP, UNS Gas and/or UNS Electric’s ability to fund their capital requirements. As of December 31, 2011, TEP and UNS Electric had posted $1 million, and $6 million, respectively, with counterparties in the form of cash or letters of credit.

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