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Filed Pursuant to Rule 424(b)(3)
Registration No. 333-204237

PROSPECTUS

TUCSON ELECTRIC POWER COMPANY

Offer to Exchange

$300,000,000 aggregate principal amount of 3.05% Senior Notes due 2025

For

$300,000,000 aggregate principal amount of 3.05% Senior Notes due 2025 registered under the Securities Act of 1933, as amended

We are offering to exchange all of our outstanding 3.05% Senior Notes due 2025 that were issued in a private placement on February 27, 2015, and which we refer to as the “old notes,” for an equal aggregate amount of our 3.05% Senior Notes due 2025, which have been registered with the Securities and Exchange Commission (the “SEC”) and which we refer to as the “exchange notes.” We refer to the old notes and the exchange notes collectively as the “notes.” If you participate in the exchange offer, you will receive registered 3.05% Senior Notes due 2025 for your old 3.05% Senior Notes due 2025 that are properly tendered. The terms of the exchange notes are substantially identical to those of the old notes, except that the transfer restrictions and registration rights relating to the old notes will not apply to the exchange notes. In addition, the exchange notes bear a different CUSIP number than the old notes.

MATERIAL TERMS OF THE EXCHANGE OFFER

The exchange offer expires at 5:00 p.m., New York City time, on June 29, 2015, unless extended.

We will exchange all old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer.

You may withdraw tendered old notes at any time prior to the expiration of the exchange offer.

The only conditions to completing the exchange offer are that the exchange offer not violate any applicable law or applicable interpretation of the staff of the SEC and no injunction, order or decree has been or is issued that would prohibit, prevent or materially impair our ability to proceed with the exchange offer.

We will not receive any cash proceeds from the exchange offer.

There is no active trading market for the notes and we do not intend to list the exchange notes on any securities exchange or to seek approval for quotations through any automated quotation system.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer acknowledges that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received by it in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution” beginning on page 142 of this prospectus.

Investing in the exchange notes involves risks. See “Risk Factors” beginning on page 11 of this prospectus.

Neither the SEC nor any state securities commission has approved or disapproved of the exchange notes or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is May 27, 2015

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You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state or other jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

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DEFINITIONS

The abbreviations and acronyms used in this prospectus are defined below:

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RISK FACTORS

In addition to the other information included in this prospectus, including the matters addressed under “Forward-Looking Statements,” you should carefully consider the following risk factors before investing in the exchange notes.

We are subject to certain risks due to the nature of the business activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, liquidity, cash flows and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, liquidity, cash flows and results of operations.

RISKS RELATED TO THE EXCHANGE NOTES

We may be able to issue substantially more debt.

The indenture does not limit the amount of unsecured indebtedness we may issue. The indenture also permits us to incur secured debt, subject to certain limitations, as described further under “Description of Exchange Notes - Limitation on Secured Debt” herein.

In the event of a bankruptcy or insolvency, holders of our secured indebtedness, if any, and other secured obligations will have a prior secured claim to any collateral securing such indebtedness or other obligations.

Holders of our secured indebtedness, if any, will have claims that are prior to your claims as holders of the exchange notes to the extent of the value of the assets securing that other indebtedness. Our rights to incur secured indebtedness are described under “Description of Exchange Notes – Limitation on Secured Debt”.

Accordingly, in the event of any distribution or payment of our assets in any foreclosure, dissolution, winding-up, liquidation, reorganization, or other bankruptcy proceeding, holders of secured indebtedness will have a prior claim to those of our assets that constitute their collateral. Holders of the exchange notes will participate in our remaining assets ratably with all holders of our unsecured and unsubordinated indebtedness that is deemed to be of the same class as the exchange notes, and potentially with all our other general creditors, based upon the respective amounts owed to each holder or creditor. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the exchange notes.

If an active trading market does not develop for the exchange notes, you may be unable to sell the exchange notes or to sell them at a price you deem sufficient.

The exchange notes are a new issue of securities with no established trading market. We do not intend to apply for listing of the exchange notes on any national securities exchange or to arrange for the exchange notes to be quoted on any automated system. We provide no assurance as to:

Even if a trading market develops, the exchange notes may trade at higher or lower prices than their principal amount or purchase price. If a market for the exchange notes does not develop, purchasers may be unable to resell the exchange notes for an extended period of time. Consequently, a holder of exchange notes may not be able to liquidate its investment readily, and the exchange notes may not be readily accepted as collateral for loans. In addition, market-making activities will be subject to restrictions under the Securities Act and the Exchange Act.

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RISKS RELATED TO THE EXCHANGE OFFER

If you fail to exchange your old notes, they will continue to be restricted securities and may become less liquid.

Notes that you do not tender or that we do not accept will, following the exchange offer, continue to be restricted securities, and you may not offer to sell them except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We will issue the exchange notes in exchange for the old notes in the exchange offer only following the satisfaction of the procedures and conditions set forth in “The Exchange Offer—Procedures for Tendering.” Because we anticipate that most holders of the old notes will elect to exchange their outstanding notes, we expect that the liquidity of the market for the old notes remaining after the completion of the exchange offer will be substantially limited. Any old notes tendered and exchanged in the exchange offer will reduce the aggregate principal amount of the outstanding old notes at maturity. Further, following the exchange offer, if you did not tender your old notes, you generally will not have any further registration rights, and such notes will continue to be subject to certain transfer restrictions.

Broker-dealers may become subject to the registration and prospectus delivery requirements of the Securities Act, and any profit on the resale of the exchange notes may be deemed to be underwriting compensation under the Securities Act.

Any broker-dealer that acquires exchange notes in the exchange offer for its own account in exchange for old notes that it acquired through market-making or other trading activities must acknowledge that it will comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that broker-dealer. Any profit on the resale of the exchange notes and any commission or concessions received by a broker-dealer may be deemed to be underwriting compensation under the Securities Act.

You may not receive the exchange notes in the exchange offer if the exchange offer procedures are not properly followed.

We will issue the exchange notes in exchange for your old notes only if you properly tender such notes before expiration of the exchange offer. Neither we nor the exchange agent is under any duty to give notification of defects or irregularities with respect to the tenders of the old notes for exchange. If you are the beneficial holder of old notes that are held through your broker, dealer, commercial bank, trust company or other nominee, and you wish to tender such notes in the exchange offer, you should promptly contact the person through whom your old notes are held and instruct that person to tender on your behalf.

RISKS RELATED TO TUCSON ELECTRIC POWER COMPANY

The business and financial results of Tucson Electric Power Company (“TEP”) are subject to a number of risks and uncertainties, including those set forth below. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational.

REVENUES

National and local economic conditions can negatively affect the results of operations, net income, and cash flows at TEP.

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% in each year from 2010 through 2014 compared with average increases of approximately 2% in each year from 2005 to 2009. 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.

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New technological developments and compliance with the ACC’s Energy Efficiency Standards will continue to have a significant impact on retail sales, which could negatively impact TEP’s results of operations, net income, and cash flows.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-owned generation, and appliances, equipment, and control systems. Further development and use of these technologies and compliance with the ACC’s Energy Efficiency Standard could negatively impact the results of operations, net income, and cash flows of TEP.

The revenues, results of operations, and cash flows of TEP 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. Cool summers or warm winters may reduce customer usage, adversely affecting operating revenues, cash flows, and net income by reducing sales.

TEP is dependent on a small segment of large customers for future revenues. A reduction in the electricity sales to these customers would negatively affect our results of operations, net income, and cash flows.

TEP sells electricity to mines, military installations, and other large industrial customers. In 2014, 35% of TEP’s retail kWh sales were to 608 industrial and mining customers. Retail sales volumes and revenues from these customer classes could decline as a result of, among other things: economic conditions; commodity prices; decisions by the federal government to close military bases; the effects of EE and DG; or the decision by customers to self-generate all or a portion of the energy needs. A reduction in retail kWh sales to TEP’s large customers would negatively affect our results of operations, net income, and cash flows.

REGULATORY

TEP is subject to regulation by the ACC, which sets the company’s Retail Rates and oversees many aspects of its business in ways that could negatively affect the company’s 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 rates that provide electric utilities with an opportunity to recover their costs of service and earn a reasonable rate of return. As part of the ACC’s process of establishing the retail electric rates charged by TEP, the ACC could disallow the recovery of certain costs, if deemed they were imprudently incurred. The decisions made by the ACC on such matters impact the net income and cash flows of TEP.

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

TEP is 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. TEP is 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.

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As a result of the Energy Policy Act of 2005, owners and operators of bulk power systems, including TEP, are subject to mandatory transmission standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties.

ENVIRONMENTAL

TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it 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 electric 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 by regulatory authorities for costly equipment upgrades.

Existing environmental laws and regulations may be revised and new environmental laws and regulations may 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.

Proposed federal regulations to limit greenhouse gas emissions would, if adopted in the form proposed, result in a shift in generation from coal to natural gas and renewable generation and could increase TEP’s cost of operations.

In June 2014 the EPA proposed carbon emission standards to reduce greenhouse gas emissions from existing power plants. EPA’s proposal for Arizona would result in a significant shift in generation from coal to natural gas and renewables and could lead to the early retirement of coal generation in Arizona by 2020. The EPA is scheduled to finalize those standards by summer 2015. These proposed regulations would, if adopted in the form proposed, result in a change in the composition of TEP’s generating fleet. As of January 30, 2015, approximately 54% of TEP’s generating capacity is fueled by coal. In 2014, approximately 68% of our total electricity resources were fueled by coal. The final rule issued by the EPA could significantly impair the ability to operate certain of TEP’s coal-fired generation plants on an economically viable basis or at all. A substantial change in TEP’s generation portfolio could result in increased cost of operations and/or additional capital investments. The impact of final regulations to address carbon emissions will depend on the specific terms of those measures and cannot be determined at this time.

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Early closure of TEP’s coal-fired generation plants resulting from environmental regulations could result in TEP recognizing material impairments in respect of such plants and increased cost of operations if recovery of our remaining investments in such plants and the costs associated with such early closures were not permitted through rates charged to customers.

TEP’s coal-fired generating stations may be required to be closed before the end of their useful lives in response to recent or future changes in environmental regulation, including potential regulation relating to greenhouse gas emissions. If any of the coal-fired generation plants, or coal handling facilities, from which TEP obtains power are closed prior to the end of their useful life, TEP could be required to recognize a material impairment of its assets and incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation and cancellation of long-term coal contracts of such generating plants and facilities. Closure of any of such generating stations may force TEP to incur higher costs for replacement capacity and energy. TEP may not be permitted full recovery of these costs in the rates it charges its customers.

FINANCIAL

The third-party co-owners of Springerville Unit 1 have failed to pay their pro-rata share of the costs and expenses associated with Springerville Unit 1.

TEP owns 49.5% of Springerville Unit 1 and two separate third-parties own the remaining 50.5%. Starting in January 2015, TEP is obligated to operate Springerville Unit 1 for these Third-Party Owners under an existing facility support agreement. TEP and the Third-Party Owners disagree on several key aspects of this agreement, including the allocation of Springerville Unit 1 operating and maintenance expenses, capital improvement costs, and transmission rights. In addition, in late 2014 the Third-Party Owners filed separate complaints at the FERC and in New York State court that include allegations that TEP violated certain provisions of the facility support agreement in relation to TEP’s operation of Springerville Unit 1. Because of these disagreements and the pending litigation, the Third-Party Owners have refused to pay some or all of their pro-rata share of such Springerville Unit 1 costs and expenses. The Third-Party Owners’ share of monthly fixed operating and maintenance costs for Springerville Unit 1 is approximately $2 million and their share of 2015 capital expenditures is approximately $8 million.

Volatility or disruptions in the financial markets, or unanticipated financing needs, could: increase our financing costs; limit our access to the credit markets; affect our ability to comply with financial covenants in our debt agreements; and increase our pension funding obligations. Such outcomes 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 in 2008 and 2009 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.

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Plant closings or changes in power flows into our service territory could require us to redeem or defease some or all of the tax-exempt bonds issued for our benefit. This could result in increased financing costs.

TEP has financed a substantial portion of utility plant assets with the proceeds of pollution control revenue bonds and industrial development revenue bonds issued by governmental authorities. Interest on these bonds is, subject to certain exceptions, excluded from gross income for federal tax purposes. This tax-exempt status is based, in part, on continued use of the assets for pollution control purposes or the local furnishing of energy within TEP’s two-county retail service area.

As of March 31, 2015, there were outstanding approximately $324 million aggregate principal amount of tax-exempt bonds that financed pollution control facilities at TEP’s generating units. Should certain of TEP’s generating units be retired and dismantled prior to the stated maturity dates of the related tax-exempt bonds, it is possible that some or all of the bonds financing such facilities would be subject to mandatory early redemption by TEP. As of March 31, 2015, there were also outstanding approximately $371 million aggregate principal amount of tax-exempt bonds that financed local furnishing facilities. Depending on changes that may occur to the regional generation mix in the desert southwest, to the regional bulk transmission network, or to the demand for retail energy in TEP’s local service area, it is possible that TEP would no longer qualify as a local furnisher of energy within the meaning of the Internal Revenue Code. If that were to occur, all of TEP’s tax-exempt local furnishing bonds would be subject to mandatory early redemption by TEP or defeasance to the earliest possible redemption date. Of the total tax-exempt local furnishing bonds outstanding, $164 million aggregate principal amount is currently redeemable at par, while the remaining $207 million principal amount can be redeemed at par at the respective bond’s early redemption date ranging from 2020 to 2023.

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

At March 31, 2015, TEP had $215 million of tax-exempt variable rate debt obligations. The interest rates are set weekly or monthly. The average weekly interest rates (including Letters of Credit (LOCs) and remarketing fees) ranged from 1.40% to 1.75% in 2014. The average monthly interest rates ranged from 0.85% to 0.95%. 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.

TEP is also subject to risk resulting from changes in the interest rate on its borrowings under the 2010 and 2014 Credit Agreements. Such borrowings may be made on a spread over London Interbank Offer Rate (LIBOR) or an Alternate Base Rate.

If capital market conditions result in rising interest rates, the resulting increase in the cost of variable rate borrowings would negatively impact our results of operations, net income, and cash flows.

The expected purchase of certain of TEP’s leased assets, as well as the cost of significant investments in TEP’s transmission system could require significant outlays of cash, which could be difficult to finance.

TEP leases a 50% undivided interest in Springerville Common Facilities with primary lease terms ending in 2017 and 2021. Upon expiration of the Springerville Common Facilities Leases, TEP has the obligation under agreements with the owners of Springerville Units 3 and 4 to purchase such facilities. Upon acquisition by TEP, the owner of Springerville Unit 3 has the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 14% interest in the Common Facilities.

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OPERATIONAL

The operation of electric generating stations, and transmission and distribution systems, involves risks that could result in reduced generating capability or unplanned outages that could adversely affect TEP’s results of operations, net income, and cash flows.

The operation of electric generating stations, and transmission and distribution systems, involves certain risks, including equipment breakdown or failure, fires and other hazards, interruption of fuel supply, and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications, occur from time to time and are an inherent risk of our business. If TEP’s generating stations and transmission and distribution systems operate below expectations, TEP’s operating results could be adversely affected.

The operation of the San Juan Generating Station could be adversely affected if the Participants are unable to secure an economic long-term coal supply.

In connection with the implementation of environmental requirements and the associated retirement of San Juan units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of their San Juan ownership. The current coal supply contract for San Juan expires on December 31, 2017. The Participants have agreed that prior to executing a binding restructuring agreement, the remaining Participants will need to have greater certainty regarding the cost and availability of fuel for San Juan after December 31, 2017. TEP and other San Juan owners are currently negotiating agreements concerning the future San Juan fuel supply. If the Participants are unable to negotiate an economic fuel supply, the continued operation of San Juan could be jeopardized resulting in the retirement of San Juan Unit 1 earlier than expected. At March 31, 2015, the net book value of TEP’s investment in San Juan Unit 1 is $95 million.

TEP receives power from certain generating facilities that are jointly owned and operated by third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could adversely affect TEP’s results of operations, net income, and cash flows.

Certain of the generating stations from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have the sole discretion or any ability to affect the management or operations at such facilities. As a result of this reliance on other operators, TEP may not be able to ensure the proper management of the operations and maintenance of the plants. Further, TEP may have no ability or a limited ability to make determinations on how best to manage the changing regulations which may affect such facilities. In addition, TEP will not have sole discretion as to how to proceed in the face of requirements relating to environmental compliance which could require significant capital expenditures or the closure of such generating stations. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such generating facilities could negatively impact the business and operations of TEP.

We may be subject to physical attacks.

As operators of critical energy infrastructure, we may face a heightened risk of physical attacks on our electric systems. Our electric generation, transmission, and distribution assets and systems are geographically dispersed and are often in rural or unpopulated areas which make them especially difficult to adequately detect, defend from, and respond to such attacks.

If, despite our security measures, a significant physical attack occurred, we could have our operations disrupted, property damaged, experience loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on our business and results of operations.

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We may be subject to cyber attacks.

We may face a heightened risk of cyber attacks. Our information and operations technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. Our operations technology systems have direct control over certain aspects of the electric system and, in addition, our utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.

If, despite our security measures, a significant cyber breach occurred, we could have our operations disrupted, property damaged, and customer information stolen; experience loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on our business and results of operations.

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended, which we refer to as the “Exchange Act.” Such statements are based upon current expectations that involve risks and uncertainties. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. For example, words such as “may,” “should,” “estimates,” “predicts,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends” and similar expressions are intended to identify forward-looking statements.

Our actual results and the outcome and timing of certain events may differ significantly from the expectations discussed in the forward-looking statements. Factors that might cause or contribute to such a discrepancy include, but are not limited to, the following: state and federal regulatory and legislative decisions and actions; changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital costs, reduce generating facility output or accelerate generating facility retirements; regional economic and market conditions which could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of our pension and other retiree benefit plan assets and the related contribution requirements and expense; the inability to make additions to our existing high voltage transmission system; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing impact of mandated energy efficiency and distributed generation initiatives; changes to long-term contracts; the cost of fuel and power supplies; ability to obtain coal from our suppliers; cyber attacks or challenges to our information security; and the performance of TEP’s generating plants.

The foregoing risks and uncertainties, as well as those risks and uncertainties referred to under the heading “Risk Factors”, may cause actual results to differ materially from the forward-looking statements. The information included in this prospectus is given as of the date of this prospectus and future events or circumstances could differ significantly from such information. We do not undertake to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by the federal securities laws.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room located at One Station Place, 100 F Street, N.E., Washington, D.C. 20549. You can also request copies of the documents, upon payment of a duplicating fee, by writing the Public Reference Section of the SEC. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room. These filings are also available to the public from the SEC’s website at www.sec.gov.

TEP makes available its 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 we electronically file or furnish them to the SEC. These reports are available free of charge through TEP’s website address at www.tep.com/about/investors/.

TEP is providing the address of TEP’s website solely for the information of investors and does not intend the address to be an active link. Information contained at TEP’s website is not part of this prospectus.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We issued the old notes in a private placement on February 27, 2015. The old notes were issued, and the exchange notes will be issued, under an indenture, dated as of November 1, 2011, between us and U.S. Bank National Association, as trustee, and the officer’s certificate dated as of February 27, 2015 supplementing the indenture and establishing the terms of the old notes and the exchange notes (which we collectively refer to herein as the indenture). In connection with the private placement, we entered into a registration rights agreement, which requires that we file this registration statement under the Securities Act with respect to the exchange notes to be issued in the exchange offer and, upon the effectiveness of this registration statement, offer to you the opportunity to exchange your old notes for a like principal amount of exchange notes. The exchange notes will be issued without a restrictive legend and, except as set forth below, you may reoffer and resell them without registration under the Securities Act. After we complete the exchange offer, our obligation to register the exchange of exchange notes for old notes will terminate. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties unrelated to us, if you are not our “affiliate” within the meaning of Rule 405 under the Securities Act or a broker-dealer referred to in the next paragraph, we believe that you may reoffer, resell or otherwise transfer the exchange notes issued to you in the exchange offer without compliance with the registration and prospectus delivery requirements of the Securities Act. This interpretation, however, is based on your representation to us that:

If you tender old notes in the exchange offer for the purpose of participating in a distribution of the exchange notes to be issued to you in the exchange offer, you cannot rely on this interpretation by the staff of the SEC. Under those circumstances, you must comply with the registration and prospectus delivery requirements of the Securities Act in order to reoffer, resell or otherwise transfer your exchange notes. Each broker-dealer that receives exchange notes for its own account in the exchange offer for old notes that were acquired as a result of market-making or other trading activities must acknowledge that it will comply with the prospectus delivery requirements of the Securities Act in connection with any offer to resell or other transfer of the exchange notes issued in the exchange offer. See “Plan of Distribution.” Broker-dealers who acquired old notes directly from us and not as a result of market making or other trading activities may not rely on the staff’s interpretations discussed above or participate in the exchange offer, and must comply with the prospectus delivery requirements of the Securities Act in order to sell the private notes.

If you will not receive freely tradeable exchange notes in the exchange offer or are not eligible to participate in the exchange offer, you can elect to have your old notes registered on a “shelf” registration statement pursuant to Rule 415 under the Securities Act. In the event that we are obligated to file a shelf registration statement, we will be required to keep the shelf registration statement effective for a period of one year following the date of

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original issuance of the old notes or 90 days from the effectiveness of such shelf registration statement, or such shorter period as will terminate when all the securities covered by the shelf registration statement (a) have been sold pursuant thereto or (B) are no longer transfer restricted securities (as such term is defined in the registration rights agreement). Other than as set forth in this paragraph, you will not have the right to require us to register your old notes under the Securities Act. See “—Procedures for Tendering” below.

Consequences of Failure to Exchange

If you do not participate or properly tender your old notes in this exchange offer:

Terms of the Exchange Offer

Upon the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal, we will accept any and all old notes validly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. We will issue $1,000 principal amount of the exchange notes in exchange for each $1,000 principal amount of the old notes accepted in the exchange offer. You may tender some or all of your old notes pursuant to the exchange offer; however, old notes may be tendered only in denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The form and terms of the exchange notes are substantially identical to those of the old notes, except that the transfer restrictions and registration rights relating to the old notes will not apply to the exchange notes, and the exchange notes will not provide for the payment of additional interest in the event of a registration default. In addition, the exchange notes bear a different CUSIP number than the old notes. The exchange notes will be issued under and entitled to the benefits of the same officer’s certificate that authorized the issuance of the outstanding old notes.

As of the date of this prospectus, $300,000,000 aggregate principal amount of the old notes were outstanding and registered in the name of Cede & Co., as nominee for DTC. This prospectus, together with the letter of transmittal, is being sent to the registered holder and to others believed to have beneficial interests in the private notes. We intend to conduct the exchange offer in accordance with the applicable requirements of the Exchange Act and the rules and regulations of the SEC promulgated under the Exchange Act.

We will be deemed to have accepted validly tendered old notes if and when we have given oral (any such oral notice to be promptly confirmed in writing) or written notice of our acceptance to U.S. Bank National Association, the exchange agent for the exchange offer. The exchange agent will act as our agent for the purpose of receiving from us the exchange notes for the tendering noteholders. If we do not accept any tendered old notes because of an invalid tender, the occurrence of certain other events set forth in this prospectus or otherwise, we will return certificates, if any, for any unaccepted old notes, without expense, to the tendering noteholder as promptly as practicable after the expiration date of the exchange offer.

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You will not be required to pay brokerage commissions or fees or transfer taxes, except as set forth below under “—Transfer Taxes,” with respect to the exchange of your old notes in the exchange offer. We will pay all charges and expenses, other than certain applicable taxes, in connection with the exchange offer. See “—Fees and Expenses” below.

Expiration Date; Amendment

The expiration date for the exchange offer will be 5:00 p.m., New York City time, on June 29, 2015 unless we determine, in our sole discretion, to extend the exchange offer, in which case it will expire at the later date and time to which it is extended. We do not intend to extend the exchange offer, however, although we reserve the right to do so. If we extend the exchange offer, we will give oral (any such oral notice to be promptly confirmed in writing) or written notice of the extension to the exchange agent and give each registered holder of old notes notice by means of a press release or other public announcement of any extension prior to 9:00 a.m., New York City time, on the next business day after the scheduled expiration date.

We also reserve the right, in our sole discretion:

We will notify you as promptly as we can of any extension, termination or amendment. In addition, we acknowledge and undertake to comply with the provisions of Rule 14e-l(c) under the Exchange Act, which requires us to pay the consideration offered, or return the old notes surrendered for exchange, promptly after the termination or withdrawal of the exchange offer.

Procedures for Tendering

Only a holder of old notes may tender the old notes in the exchange offer. Except as set forth under “—Book-Entry Transfer,” to tender in the exchange offer a holder must complete, sign and date the letter of transmittal, or a copy of the letter of transmittal, have the signatures on the letter of transmittal guaranteed if required by the letter of transmittal and mail or otherwise deliver the letter of transmittal or a copy to U.S. Bank National Association, as the exchange agent, prior to the expiration date. In addition:

If you hold old notes through a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your old notes, you should contact the registered holder of your old notes promptly and instruct the registered holder to tender on your behalf.

If you tender an old note and you do not properly withdraw the tender prior to the expiration date, you will have made an agreement with us to participate in the exchange offer in accordance with the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal.

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Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed by an eligible institution unless:

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantee must be by a financial institution, which includes most banks, savings and loan associations and brokerage houses, that is a participant in the Securities Transfer Agents Medallion Program, the New York Stock Exchange Medallion Program or the Stock Exchanges Medallion Program.

If the letter of transmittal is signed by a person other than you, your old notes must be endorsed or accompanied by a properly completed bond power and signed by you as your name appears on those old notes.

If the letter of transmittal or any old notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should so indicate when signing. Unless we waive this requirement, in this instance you must submit with the letter of transmittal proper evidence satisfactory to us of their authority to act on your behalf.

We will determine, in our sole discretion, all questions regarding the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any and all old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to certain old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties.

You must cure any defects or irregularities in connection with tenders of your old notes within the time period that we determine unless we waive that defect or irregularity. Although we intend to notify you of defects or irregularities with respect to your tender of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give this notification. Your tender will not be deemed to have been made and your old notes will be returned to you if:

The exchange agent will return your old notes, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration of the exchange offer.

In addition, we reserve the right in our sole discretion to:

The terms of any of these purchases or offers could differ from the terms of the exchange offer.

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In all cases, the issuance of exchange notes for old notes that are accepted for exchange in the exchange offer will be made only after timely receipt by the exchange agent of certificates for your old notes or a timely book-entry confirmation of your old notes into the exchange agent’s account at DTC, a properly completed and duly executed letter of transmittal or a computer-generated message instead of the letter of transmittal, and all other required documents. If any tendered old notes are not accepted for any reason set forth in the terms and conditions of the exchange offer or if old notes are submitted for a greater principal amount than you desire to exchange, the unaccepted or non-exchanged old notes, or old notes in substitution therefor, will be returned without expense to you. In addition, in the case of old notes tendered by book-entry transfer into the exchange agent’s account at DTC pursuant to the book-entry transfer procedures described below, the non-exchanged old notes will be credited to your account maintained with DTC, as promptly as practicable after the expiration or termination of the exchange offer.

Book-Entry Transfer

The old notes were issued as global securities in fully registered form without interest coupons. Beneficial interests in the global securities, held by direct or indirect participants in DTC, are shown on, and transfers of these interests are effected only through, records maintained in book-entry form by DTC with respect to its participants.

The exchange agent will make a request to establish an account with respect to the old notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus, and any financial institution that is a participant in DTC’s systems may make book-entry delivery of old notes being tendered by causing DTC to transfer such old notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer.

The DTC’s ATOP system is the only method of processing exchange offers through DTC. To accept the exchange offer through ATOP, participants in DTC must send electronic instructions to DTC through DTC’s communication system instead of sending a signed, hard copy letter of transmittal. DTC is obligated to communicate those electronic instructions to the exchange agent. To tender old notes through ATOP, the electronic instructions sent to DTC and transmitted by DTC to the exchange agent must contain the character by which the participant acknowledges its receipt of, and agrees to be bound by, the letter of transmittal.

If you hold your old notes in the form of book-entry interests and you wish to tender your old notes in exchange for exchange notes, you must instruct a participant in DTC to transmit to the exchange agent on or prior to the expiration date for the exchange offer a computer-generated message transmitted by means of ATOP and received by the exchange agent and forming a part of a confirmation of book-entry transfer, in which you acknowledge and agree to be bound by the terms of the letter of transmittal.

In addition, in order to deliver old notes held in the form of book-entry interests, a timely confirmation of book-entry transfer of such notes into the exchange agent’s account at DTC pursuant to the procedure for book-entry transfers described above must be received by the exchange agent prior to the expiration date.

Guaranteed Delivery Procedures

Guaranteed delivery procedures are not available in connection with the exchange offer.

Withdrawal Rights

You may withdraw tenders of your old notes at any time prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer.

For your withdrawal to be effective, the exchange agent must receive a written or facsimile transmission of or, for DTC participants, an electronic ATOP transmission of, the notice of withdrawal at its address set forth below under “—Exchange Agent” prior to 5:00 p.m., New York City time, on the expiration date.

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The notice of withdrawal must:

We will determine all questions regarding the validity, form and eligibility, including time of receipt, of withdrawal notices. Our determination will be final and binding on all parties. Any old notes withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer. Any old notes that have been tendered for exchange but that are not exchanged for any reason will be returned to you without cost as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn old notes may be retendered by following one of the procedures described under “—Procedures for Tendering” above at any time on or prior to 5:00 p.m., New York City time, on the expiration date.

Conditions

Notwithstanding any other provision of the exchange offer, and subject to our obligations under the related registration rights agreement, we will not be required to accept for exchange, or to issue exchange notes in exchange for, any old notes and may terminate or amend the exchange offer, if at any time before the acceptance of any old notes for exchange any one of the following events occurs:

These conditions are for our sole benefit and we may assert them regardless of the circumstances giving rise to them, subject to applicable law. We also may waive in whole or in part at any time and from time to time any particular condition in our sole discretion. If we waive a condition, we may be required in order to comply with applicable securities laws, to extend the expiration date of the exchange offer. Our failure at any time to exercise any of the foregoing rights will not be deemed a waiver of these rights and these rights will be deemed ongoing rights which may be asserted at any time and from time to time.

In addition, we will not accept for exchange any old notes tendered, and no exchange notes will be issued in exchange for any tendered old notes, if, at the time the notes are tendered, any stop order is threatened by the SEC or in effect with respect to the registration statement of which this prospectus is a part.

The exchange offer is not conditioned on any minimum principal amount of old notes being tendered for exchange.

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Exchange Agent

We have appointed U.S. Bank National Association, as exchange agent for the exchange offer. Questions, requests for assistance and requests for additional copies of the prospectus, the letter of transmittal and other related documents should be directed to the exchange agent addressed as follows:

U.S. Bank National Association, as Exchange Agent

By Facsimile Transmission:

(for Eligible Institutions Only)

651-466-7372

For Information or Confirmation by

Telephone

(651) 466-7372

DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE, OR TRANSMISSION OF SUCH LETTER OF TRANSMITTAL VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE, WILL NOT CONSTITUTE A VALID DELIVERY.

The exchange agent also acts as trustee under the indenture.

Fees and Expenses

We will not pay brokers, dealers or others soliciting acceptances of the exchange offer. The principal solicitation is being made by mail. Additional solicitations, however, may be made in person or by telephone by our officers and employees.

We will pay the estimated cash expenses to be incurred in connection with the exchange offer. These are estimated in the aggregate to be approximately $300,000, which includes fees and expenses of the exchange agent and accounting, legal, printing and related fees and expenses.

Transfer Taxes

You will not be obligated to pay any transfer taxes in connection with a tender of your old notes unless you instruct us to register exchange notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder of old notes, in which event the registered tendering holder will be responsible for the payment of any applicable transfer tax.

Accounting Treatment

We will not recognize any gain or loss for accounting purposes upon the consummation of the exchange offer. We will amortize the expense of the exchange offer over the term of the exchange notes under generally accepted accounting principles.

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the exchange notes pursuant to the exchange offer. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive in exchange a like principal amount of outstanding old notes, the terms of which are substantially identical in to the exchange notes. The outstanding old notes surrendered in exchange for the exchange notes will be retired and cancelled and cannot be reissued. Accordingly, the issuance of the exchange notes will not result in any change in our capitalization. We have agreed to bear the expenses of the exchange offer. No underwriter is being used in connection with the exchange offer.

CAPITALIZATION

You should read the information set forth below as to our consolidated capitalization in conjunction with our historical financial statements and the related notes and other financial information contained in this prospectus.

RATIO OF EARNINGS TO FIXED CHARGES

The following table contains our consolidated ratio of earnings to fixed charges for the periods indicated. You should read those ratios in connection with our consolidated and condensed consolidated financial statements, including the notes to those statements, which are included in this prospectus.

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BUSINESS

GENERAL

Tucson Electric Power Company (TEP) is a vertically integrated, regulated utility that generates, transmits and distributes electricity. TEP also sells electricity to other utilities and power marketing entities located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis), which is a leader in the North American electric and gas utility business.

FORTIS ACQUISITION OF UNS ENERGY

UNS Energy, the parent of TEP, was acquired by Fortis for $60.25 per share of UNS Energy common stock in cash effective August 15, 2014.

The Arizona Corporation Commission’s (ACC) approval of the Merger was subject to certain stipulations, including, but not limited to, the following:

As a result of the Merger being completed, TEP recorded approximately $15 million in 2014 as its allocated share of merger- related expenses, in addition to the customer bill credits discussed above. Merger-related expenses include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards.

SERVICE AREA AND CUSTOMERS

TEP’s service territory covers 1,155 square miles with service to approximately 417,000 retail electric customers 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 wholesale 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.

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Customer Base

The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years. In 2015, 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 2014, 2013, and 2012, 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 approximately 1% in 2015 and 2016 based on estimated population growth in our service territory.

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 5.4% in 2014.

Retail Sales Volumes

TEP’s retail sales volumes in 2014 were approximately 9,165 Gigawatt-hours (GWh). These volumes were 1.3% below 2010 levels. During the past four years, economic conditions and state requirements for Energy Efficiency (EE) and Distributed Generation (DG) have negatively affected retail electricity sales.

Wholesale Sales

TEP’s electric utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale sales transactions are made on both a firm and interruptible basis. A firm contract requires TEP to supply power on demand (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions. See Generating and Other Resources, and Purchases, 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. In 2014, TEP’s two primary long-term contracts were with Salt River Project Agriculture Improvement and Power District (SRP) and the Navajo Tribal Utility Authority (NTUA). The SRP contract expires in May 2016 and the NTUA contract expires in December 2022.

In December 2014, TEP entered into two additional long-term wholesale sales contracts that began in January 2015. The first long-term sales contract is with TRICO Electric Cooperative and expires in December 2024. The second long-term sales contract is with Shell Energy North America and expires in December 2017. The execution of these two additional wholesale sales contracts use near-term capacity acquired with TEP’s purchase of Gila River Unit 3 discussed below.

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Short-Term Sales

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

GENERATING AND OTHER RESOURCES

As of March 31, 2015, TEP owned 2,448 MW of nominal generating capacity, as set forth in the following table. Nominal capacity is based on unit design net output.

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Springerville Generating Station

Springerville Unit 1

TEP leased Unit 1 of the Springerville Generating Station and an undivided one-half interest in certain Springerville Common Facilities (collectively Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that were accounted for as capital leases. The leases expired in January 2015 and included fair market value renewal and purchase options. As of January 1, TEP owns 49.5% of Unit 1 and a one-quarter interest in the common facilities.

In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 megawatts (MW) of capacity. During 2013, TEP agreed to purchase leased interests of 35.4% or 137 MW of Springerville Unit 1, for an aggregate purchase price of approximately $65 million. TEP completed the purchase of a 10.6% leased interest, representing 41 MW of capacity in December 2014 and a 24.8% leased interest, representing 96 MW of capacity, in January 2015. The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, continues to be owned by third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). With the expiration of the leases in January 2015, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $2 million per month, and their share of capital expenditures, which are approximately $8 million in 2015.

Springerville Unit 2

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.

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 fair market value renewal options as well as fixed-price purchase options. 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 into the lease, TEP purchased a 13% ownership interest in the Springerville Coal Handling Facilities. In April 2015, upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, bringing its total ownership of the assets to 100%.

With the completion of this purchase, SRP is obligated to purchase a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either: 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. TEP expects SRP to complete its purchase commitment in the second quarter 2015. Tri-State has until April 2016 to elect an option. At March 31, 2015, no amounts have been recorded on TEP’s balance sheet for commitments from either SRP or Tri-State.

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.

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Gila River Generating Station Unit 3

On December 10, 2014, TEP and UNS Electric, Inc. (UNS Electric), an affiliated subsidiary of UNS Energy, acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW) for $164 million, and UNS Electric purchased the remaining 25% undivided interest. See Note 7 of Notes to Consolidated Financial Statements for the fiscal year ended December 31, 2014.

The purchase of Gila River Unit 3 is intended to replace the expired coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, and is consistent with TEP’s strategy to diversify its generation fuel mix. See Environmental Matters, Regional Haze Rules, San Juan, below.

Renewable Energy Resources

Owned Resources

As of December 31, 2014, TEP owned 45 MW of photovoltaic (PV) solar generating capacity. The Springerville solar system, which is located near the Springerville Generating Station, has a total capacity of 16 MW, including 10 MW of capacity completed in December 2014. In December 2014, TEP also completed a solar project providing 17 MW of capacity at Ft. Huachuca, Arizona. TEP’s remaining 12 MW of PV solar generating capacity is located in the Tucson area.

Power Purchase Agreements

In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 165 MW of capacity from solar resources, 90 MW of capacity from wind resources and 4 MW of capacity from a landfill gas generation plant. At March 31, 2015, approximately 124 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 allow TEP to purchase all or part of the related project at a future period. See Rates and Regulation, Renewable Energy Standard and Tariff, below.

Power Purchases

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 power purchases are price-indexed to natural gas. 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.

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 Springerville Units 1 and 2. The owners of

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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.

Peak Demand and Resources

The chart above shows the relationship over a five-year period between peak demand and energy resources. 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. The reserve margin in 2014 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.

Peak demand occurs during the summer months due to the cooling requirements of retail customers. Retail peak demand varies from year-to-year due to weather, economic conditions, and other factors. Retail peak demand declined over the period of 2010 to 2014 due primarily to weak economic conditions and the implementation of energy efficiency programs and distributed generation.

Forecasted retail peak demand for 2015 is 2,222 MW compared with actual peak demand of 2,218 MW in 2014. TEP’s 2015 estimated retail peak demand is based on weather patterns observed over a 10-year period and other factors, including estimates of customer usage. TEP believes existing generation capacity and PPAs are sufficient to meet expected demand in 2015 and established reserve margin criteria.

FUEL SUPPLY

Fuel and Purchased Power Summary

Resource information is provided below:

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Coal

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona and New Mexico. The table below provides information on the existing coal contracts that supply our generating stations. The average cost per ton of coal, including transportation, was $45.50 in 2014, $48.51 in 2013, and $45.84 in 2012.

TEP Operated Generating Facilities

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.

TEP does not have a long-term coal supply contract for Sundt Unit 4. 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 landfill gas, a renewable energy resource, delivered 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. See Note 6 of Notes to Consolidated Financial Statements for the fiscal year ended December 31, 2014.

Coal 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 Company (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 received under contracts administered by the operating agents. As indicated in the table above, the current coal supply contract for San Juan expires on December 31, 2017. TEP and other San Juan owners are currently negotiating agreements concerning the future San Juan fuel supply with the existing coal supplier. If the participants are unable to negotiate an economic fuel supply, the continued operation of San Juan could be adversely affected.

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 94 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 (EPNG) for transportation from the San Juan and Permian Basins to its Sundt plant under firm transportation agreements and buys gas from third-party suppliers for Sundt and DeMoss Petrie.

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TEP also purchases firm gas transportation for Gila from EPNG and Transwestern and for Luna Generating Station (Luna) from EPNG.

TRANSMISSION ACCESS

TEP has transmission access and power transaction arrangements with over 140 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.

To improve transmission capacity between Palo Verde and Tucson, TEP participated in the construction and ownership of a 500 kV transmission line from the Palo Verde area to the Pinal Central substation east of Casa Grande, AZ. This project was placed in service in 2014. Also, construction is underway on a 45-mile 500-kV transmission line from the Pinal Central substation to TEP’s Tortolita substation northwest of Tucson. TEP expects the Pinal Central to Tortolita line to be in service in 2016. Additionally, TEP is working with SRP and others to tie the Gila River power plant into TEP’s Palo Verde to Tucson transmission system. This will provide an improved electrical path to bring Gila River Unit 3 power into Tucson.

As part of TEP’s purchase of the Gila River unit TEP received transmission rights across the APS transmission system. These rights extend from the Gila River switchyard adjacent to the plant to the Jojoba switchyard. TEP is pursuing interconnection of the Jojoba switchyard to the existing transmission line from the Palo Verde area to Pinal Central substation in which TEP has an ownership interest. This interconnection, along with the rights obtained with the purchase, will provide direct transmission access from the Gila Plant to TEP’s service territory.

Discontinued Transmission Project

TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the Federal Energy Regulatory Commission (FERC) before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP’s next FERC rate case.

RATES AND REGULATION

The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

2013 TEP Rate Order

In June 2013, the ACC issued an order (2013 TEP Rate Order) which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

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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 costs of contracts for hedging fuel and purchased power costs for its retail customers. The PPFAC consists of a forward component and a true-up component.

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

TEP’s PPFAC also includes the recovery of the following costs and/or credits: lime costs used to control SO2 emissions at Springerville, sulfur credits received from TEP’s coal suppliers; broker fees; 100% of short-term wholesale revenues; and all of the proceeds from the sale of SO2 allowances.

At December 31, 2014, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $32 million.

Renewable Energy Standard and Tariff

The ACC’s Renewable Energy Standard (RES) requires 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, with distributed generation accounting for 30% of the annual renewable energy requirement. 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 until such costs are reflected in TEP’s Base Rates.

In December 2014, the ACC approved TEP’s 2015 RES implementation plan. Under the plan, TEP expects to collect approximately $33 million from retail customers during 2015 to fund the following: the above market cost of renewable energy purchases; performance based incentives for customer installed DG; depreciation and a return on TEP’s investments in company-owned solar projects; and various other program costs. TEP expects to recognize approximately $4 million of revenue in 2015 as a return on company-owned solar projects.

The 2015 RES implementation plan authorized a TEP investment of $10 million in 2015 for up to 600 company-owned residential solar projects. Participants in this program will take service under a fixed electric rate. While participating customers could realize significant savings over time if TEP’s standard rates or energy costs increase, their payments are expected to cover a majority of the company’s fixed service costs associated with that customer.

TEP met the overall 2014 RES renewable energy target of 4.5% of retail kWh sales and expects to meet the 2015 target of 5% of retail kWh sales. Compliance with RES is determined through periodic filings with the ACC. As TEP no longer pays incentives to obtain distributed generation Renewable Energy Credits (REC), which are used to demonstrate compliance with the distributed generation requirement, the company may request a waiver of the RES distributed generation requirements.

Electric Energy Efficiency Standards

In 2010, the ACC approved new Electric EE Standards designed to require electric utilities to implement cost-effective programs to reduce customers’ energy consumption. The Electric EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. Since the implementation of the Electric EE Standards, TEP’s cumulative annual energy savings are approximately 7.0% of retail kWh sales. TEP’s compliance with the Electric EE Standards is governed by the ACC’s approval of implementation plans filed by TEP annually.

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In December 2014, the ACC approved TEP’s 2014 and 2015 Energy Efficiency Implementation Plans. Under the 2015 plan, TEP expects to collect approximately $19 million from retail customers and will offer customers new and existing DSM programs. Energy savings realized through the programs will count toward Arizona’s Energy Efficiency Standard and the associated lost revenue will be partially collected through the Lost Fixed Cost Recovery Mechanism (LFCR). See Note 2 of Notes to Consolidated Financial Statements for the fiscal year ended December 31, 2014. In December 2014, the ACC initiated a new rulemaking proceeding that could result in the elimination of specific targeted savings and instead treat EE as a resource to be evaluated through the ACC’s integrated resource planning process.

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TEP’S UTILITY OPERATING STATISTICS

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ENVIRONMENTAL MATTERS

Environmental Regulation

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP 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 ratepayers.

National Ambient Air Quality Standards

In November 2014, the EPA released a proposed rule that would revise the ozone National Ambient Air Quality Standards (NAAQS). The proposal revises the primary and secondary 8-hour NAAQS to within a range of 65-70 parts per billion (ppb), but the EPA is also taking comments on retaining the existing 75 ppb 8-hour standard or adopting an 8-hour standard as low as 60 ppb.

If the standard is ultimately revised below 70 ppb, Pima County and many other parts of Arizona would likely not be able to comply based on current ozone levels. Arizona would then need to submit a plan to meet the revised standard which could potentially limit economic growth in the affected regions. TEP filed comments on the proposed rule urging EPA to retain the existing standard at 75 ppb. The EPA is expected to finalize the rule by October 2015.

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 Mercury and Air Toxics Standards (MATS) rules to set the standards for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the final rule, additional emission control equipment would have been required by April 2015. However, TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules.

For more information see Note 5 to the Condensed Consolidated Financial Statements for the quarter ended March 31, 2015.

Navajo

Based on the MATS rules, Navajo will require mercury control equipment by April 2016. TEP’s share of the estimated capital costs of this equipment is $1 million for mercury control. TEP expects its share of the annual operating costs for mercury control to be $1 million.

San Juan

TEP expects San Juan’s current emission controls to be adequate to comply with the MATS rules.

Four Corners

TEP expects Four Corners’ current emission controls to be adequate to comply with the MATS rules.

Springerville Generating Station

Based on the MATS rules, Springerville may require mercury emission control equipment by April 2016. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the

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annual operating cost of the mercury emission control equipment to be about $1 million. Estimated costs are split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015. With the completion of the purchases, Third-Party Owners are responsible for 50.5% of environmental costs attributed to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

Sundt Generating Station

TEP expects the MATS rules will have little effect on capital expenditures at Sundt.

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 in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. BART applies to plants built between August 1962 and August 1977. 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 all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in the units they own at these power plants. TEP cannot predict the ultimate outcome of these matters.

For more information see Note 5 to the Condensed Consolidated Financial Statements for the quarter ended March 31, 2015.

Navajo

In August 2014, the EPA published the final Regional Haze Federal Implementation Plan (FIP) for Navajo. Among other things, the FIP calls for the shut-down of one unit or an equivalent reduction in emissions by 2020. The shutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install Selective Catalytic Reduction (SCR) or an equivalent technology on the remaining two units by 2030, and the current owners have to cease their operation of conventional coal-fired generation at Navajo no later than December 22, 2044. The Navajo Nation can continue operation after 2044 at its election. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented.

If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $28 million for the two remaining units. 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 $28 million for the two remaining units. TEP’s share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.

San Juan

In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan. The SIP requires the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February of 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan

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Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP’s share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million.

In connection with the implementation of the SIP revision and the early retirement of San Juan Units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of the ownership in San Juan, as well as addressing the obligations of the exiting Participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The Participants have engaged a mediator to assist in facilitating the resolution of these matters among the Participants. The Participants of the affected units also may seek approvals of their utility commissions or governing boards. We are unable to predict the outcome of the negotiations and mediation.

Upon the early retirement of San Juan Unit 2, TEP will seek ACC approval to recover any unrecovered cost. TEP’s 2013 Rate Case identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC’s authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. At March 31, 2015, the net book value of TEP’s share in San Juan Unit 2 was $109 million.

Four Corners

In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on one unit by October 2016 and the remaining units by October 2017. In December 2013, Arizona Public Service Company (APS), the operator of Four Corners, decided to exercise an option to shut down Units 1, 2, and 3 and install SCRs on Units 4 and 5. Under this scenario, the installation of SCR technology can be delayed until July 2018. TEP’s estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $44 million. TEP’s share of incremental annual operating costs for SCR is estimated at $2 million.

Springerville

The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018.

Sundt

In June 2014, the EPA issued a final Regional Haze FIP for Arizona including BART requirements for Sundt. The final FIP would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection (DSI) if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. TEP estimates that the cost to install SNCR and DSI would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If retired early, we will request the ACC’s approval to recover all the remaining costs of the coal handling facilities.

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Greenhouse Gas Regulation

In June 2013, President Obama directed the EPA to move forward with carbon emission regulations for both new and existing fossil-fueled power plants.

In January 2014, the EPA published a re-proposed rule for new power plants. At this time, TEP does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on its operations.

In June 2014, the EPA issued proposed carbon emission regulations for existing power plants called the Clean Power Plan. The Clean Power Plan targets a nation-wide reduction in carbon emissions of 30% by 2030. To achieve this goal, the proposed plan sets carbon emission rates for each state that must be achieved by an interim period of 2020-2029, with final emission rates by 2030. States can apply a variety of strategies to achieve the interim and final emission rates. Using 2012 as a baseline year, Arizona’s carbon emission rate for 2030 represents a 52% reduction, most of which would be required by the interim emission rate requirement and could lead to the early retirement of coal generation in Arizona by 2020. The EPA expects to issue a final rule by the summer of 2015, and under the current proposal, states must file implementation plans by June 2016 or June 2017 for multi-state plans. In October 2014, the EPA issued a supplemental proposal regarding carbon emissions regulation impacting the Navajo Nation and the Four Corners and Navajo generating stations which are located on land leased from the Navajo Nation. The regulation, if implemented as proposed, will require carbon reductions on the Navajo Reservation; however, the reduction requirement is less than what is anticipated from unit retirements at the Four Corners and Navajo generating stations associated with Regional Haze requirements. See Regional Haze Rules above.

TEP will continue working with federal and state regulatory authorities, other neighboring utilities, and stakeholders to seek relief from the proposed regulation by reducing the disproportionately high level of carbon emissions reduction for Arizona, and to seek relief from the interim and final proposed compliance requirements. On December 1, 2014, UNS Energy submitted comments on the proposal on behalf of TEP and its other utility subsidiaries. The EPA has received over 3.8 million comments in response to the proposed rule. The proposed rule has been challenged in court and is subject to further legal challenge. TEP cannot predict the ultimate outcome of these matters.

Coal Combustion Residuals Regulations

In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. Additional requirements would apply to lateral expansion of those existing landfills or to any new landfill.

For more information see Note 5 to the Condensed Consolidated Financial Statements for the quarter ended March 31, 2015.

EMPLOYEES

At December 31, 2014, TEP had 1,448 employees, of which approximately 691 were 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.

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SEC REPORTS AVAILABLE ON TEP’S WEBSITE

TEP makes available its 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 we electronically file or furnish them to the Securities and Exchange Commission (SEC). These reports are available free of charge through TEP’s website address at www.tep.com/about/ investors/.

UNS Energy’s code of ethics, which applies to the Board of Directors and all officers and employees of UNS Energy and its subsidiaries, including TEP, and any amendments or any waivers made to the code of ethics, is also available on TEP’s website at www.tep.com/about/investors/.

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

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PROPERTIES

Transmission facilities owned by TEP and by third parties are located in Arizona and New Mexico and transmit the output from TEP’s electric generating stations at Four Corners, Navajo, San Juan, Springerville, Gila River, and Luna to the Tucson area for use by TEP’s retail customers. The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. TEP has arrangements with approximately 140 companies to interchange generation capacity and for the transmission of energy. See Business; Generating and Other Resources.

At March 31, 2015, TEP owned or participated in an overhead electric transmission and distribution system consisting of:

TEP’s underground electric distribution system includes 4,477 cable-miles of lines. TEP owns approximately 77% of the poles on which its lower voltage lines are located. Electric substation capacity consists of 106 substations with a total installed transformer capacity of 15,809,050 kilovolt amperes.

The electric generating stations (except as noted below), administrative headquarters, warehouses and service centers are located on land owned by TEP. The electric distribution and transmission facilities owned by TEP are located:

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or liens existing at the time the easements were acquired.

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

Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Nation. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired land rights, easements and leases for the plant, transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP also has acquired easements for transmission facilities related to San Juan, Four Corners, and Navajo across the Zuni, Navajo, and Tohono O’odham American Indian Reservations. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna is located.

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

These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities.

TEP, under separate sale and leaseback arrangements, leased the following generation facilities (which do not include land):

Under separate ground lease agreements, TEP leased parcels of land for the following photovoltaic facilities:

In December 2014, TEP placed in service an additional photovoltaic facility in Cochise County, Arizona, for which TEP entered into a 30-year easement agreement. The easement is to facilitate the operations of a solar photovoltaic renewable energy generation system on behalf of the Department of the Army, located at Fort Huachuca in Cochise County.

See Note 5 of Notes to Consolidated Financial Statements for the fiscal year ended December 31, 2014.

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LEGAL PROCEEDINGS

Springerville Unit 1 Proceedings

Upon the termination of the Springerville Unit 1 Leases on January 1, 2015, 50.5% of Springerville Unit 1, or 195 MW of capacity, continued to be owned by third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). TEP is not obligated to purchase any of the Third-Party Owners’ Springerville Unit 1 power.

Commencing on January 1, 2015 with the termination of the leases, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. In 2014, TEP and the Third-Party Owners engaged in discussions regarding the post-lease operation of Springerville Unit 1 and related cost sharing arrangements, but did not reach agreement on several key points.

On November 7, 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1, 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint. On March 23, 2015, the Third-Party Owners filed a request for rehearing in the FERC Action. On April 7, 2015, TEP filed an answer in response to the request for rehearing. The FERC has not yet ruled on the request for rehearing.

On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners’ instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action, and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses. On February 20, 2015, TEP filed a motion to dismiss in the New York Action that requested that the court dismiss various counts of the complaint. On March 20, 2015, the Third-Party Owners filed a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the Third-Party Owners instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that TEP has failed to pay the Third-Party Owners approximately $71 million in liquidated damages they allege they are owed (see following paragraph), that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired, that TEP has converted the Third-Party Owners’ water rights and that TEP has been unjustly enriched as a result, and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. On April 20, 2015, TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action. On May 13, 2015, the Third-Party Owners filed a second amended complaint which includes the prior claims which relate to TEP’s actions during the terms of the leases and the claims relating to water rights. The second amended complaint does not include the claim for breach of fiduciary duty but adds a claim for breach of an alleged duty of good faith and fair dealing and a claim for conversion of certain emission reduction payments made to TEP by the participants in Springerville Units 3 and 4. The second amended complaint continues to seek $71 million in liquidated damages, direct and

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consequential damages in an amount to be determined at trial and punitive damages. The second amended complaint continues to include the claim that TEP has not agreed to wheel power and energy as required but agrees to stay such claim pending the outcome of the FERC Action. The second amended complaint drops the claim relating to TEP’s alleged failure to properly operate and maintain Springerville Unit 1 since the expiration of the leases. The Third-Party Owners have indicated that they intend to pursue this claim through arbitration proceedings.

On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. In January 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.

On April 20, 2015, TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1. As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015.

TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.

See the Legal Proceedings described in Note 5 to the Condensed Consolidated Financial Statements for the quarter ended March 31, 2015 and Note 6 to the Consolidated Financial Statements for the fiscal year ended December 31, 2014.

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SELECTED FINANCIAL DATA

The following table presents our selected financial data as of and for the three-month periods ended March 31, 2015 and 2014 and as of and for the fiscal years ended December 31, 2014, 2013, 2012, 2011 and 2010. The financial data as of and for the five fiscal years ended December 31, 2014 has been derived from our audited consolidated financial statements. The financial data as of March 31, 2015 and for the three-month periods ended March 31, 2015 and 2014 has been derived from unaudited financial statements. Our historical results are not necessarily indicative of the results of operations for future periods, and our results of operations for the three-month period ended March 31, 2015 are not necessarily indicative of results that could be expected for the full year. The selected financial data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes that are included elsewhere in this prospectus.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations together with the financial statements and related notes that are included elsewhere in this prospectus. This discussion and other parts of this prospectus contain forward-looking statements based upon current plans, expectations and beliefs that involve risks and uncertainties. Our actual results may differ materially from those discussed in these forward-looking statements as a result of various factors, including in the section entitled “Risk Factors” and in other parts of this prospectus.

Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for TEP. It includes the following:

OVERVIEW

TEP is a vertically integrated, regulated utility that generates, transmits and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona.

Management’s Discussion and Analysis includes financial information prepared in accordance with generally accepted accounting principles (GAAP) in the U.S., as well as certain non-GAAP financial measures. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.

Management’s Discussion and Analysis should be read in conjunction with the Selected Financial Data, the Condensed Consolidated Financial Statements for the quarter ended March 31, 2015 and related Notes and the Consolidated Financial Statements for the fiscal year ended December 31, 2014 and related Notes. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see Forward-Looking Statements and Risk Factors.

References in this report to “we” and “our” are to TEP.

OUTLOOK AND STRATEGIES

TEP’s financial prospects and outlook are affected by many factors including: national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:

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RESULTS OF OPERATIONS – CONDENSED CONSOLIDATED FINANCIAL STATEMENTS FOR THE PERIOD ENDED MARCH 31, 2015

The following discussion provides the significant items that affected TEP’s results of operations for the three month periods ended March 31, 2015 and 2014.

First quarter of 2015 compared with the first quarter of 2014

TEP’s reported net income of $9 million in the first quarter of 2015 was unchanged from the first quarter of 2014. The following factors affected the period over period change in TEP’s results. All amounts are presented on an after-tax basis:

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Utility Sales and Revenues

The table below provides a summary of retail kWh sales, revenues, and weather data during the first quarter of 2015 and 2014:

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Retail kWh Sales and Margin Revenues

TEP’s total retail kWh sales decreased by 0.5% in the first quarter of 2015 due in part to ongoing EE programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $1 million, or 0.8% principally due to a change in the customer mix and additional residential usage.

Wholesale Sales and Transmission Revenues

Long-Term Wholesale Margin Revenues in the first three months of 2015 were lower when compared with the first three months of 2014 due in part to lower market prices for wholesale power.

All revenues from short-term wholesale sales are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.

Other Revenues

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In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include inter-company revenues from its affiliates, UNS Gas and UNS Electric, for corporate services provided by TEP, and miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees. See Note 3 to the Condensed Consolidated Financial Statements for the quarter ended March 31, 2015.

Operating Expenses

Generating Output and Fuel and Purchased Power Expense

Total generating output increased during the first quarter of 2015 when compared with the same period last year due to an unplanned maintenance outage in the first quarter of 2014.

TEP’s fuel and purchased power expense and energy resources for the quarters ended March 31, 2015 and 2014 are detailed below: